ETR, §1A diff (2022 → 2023)

Table of Contents

Part I Item 1A, 1B, and 1C

Entergy Corporation, Utility operating companies, and System Energy

Item 1A. Risk Factors

See “RISK FACTORS SUMMARY” in Part I, Item 1 for a summary of Entergy’s and the Registrant Subsidiaries’ risk factors.

Investors should review carefully the following risk factors and the other information in this Form 10-K. The risks that Entergy faces are not limited to those in this section. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely affect Entergy’s business, financial condition, results of operations, and liquidity. See “FORWARD-LOOKING INFORMATION.”

Utility Regulatory Risks

(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

The terms and conditions of service, including electric and gas rates, of the Utility operating companies and System Energy are determined through regulatory approval proceedings that can be lengthy and subject to appeal, potentially resulting in delays in effecting rate changes, lengthy litigation, the risk of disallowance of recovery of certain costs, and uncertainty as to ultimate results.

The Utility operating companies are regulated on a cost-of-service and rate of return basis and are subject to statutes and regulatory commission rules and procedures. The rates that the Utility operating companies and System Energy charge reflect their capital expenditures, operations and maintenance costs, allowed rates of return, financing costs, and related costs of service. These rates significantly influence the financial condition, results of operations, and liquidity of Entergy and each of the Utility operating companies and System Energy. These rates are determined in regulatory proceedings and are subject to periodic regulatory review and adjustment, including adjustment upon the initiative of a regulator or, in some cases, affected stakeholders. Regulators in a future rate proceeding may alter the timing or amount of certain costs for which recovery is allowed or modify the current authorized rate of return. Rate refunds may also be required, subject to applicable law.

In addition, regulators have initiated and may initiate additional proceedings to investigate the prudence of costs in the Utility operating companies’ and System Energy’s base rates and examine, among other things, the reasonableness or prudence of the companies’ operation and maintenance practices, level of expenditures (including storm costs and costs associated with capital projects), allowed rates of return and rate base, proposed resource acquisitions, and previously incurred capital expenditures that the operating companies seek to place in rates. The regulators may disallow costs subject to their jurisdiction found not to have been prudently incurred or found not to have been incurred in compliance with applicable tariffs, creating some risk to the ultimate recovery of those costs. Regulatory proceedings relating to rates and other matters typically involve multiple parties seeking to limit or reduce rates. Traditional base rate proceedings, as opposed to formula rate plans, generally have long timelines, are primarily based on historical costs, and may or may not be limited in scope or duration by statute. The length of these base rate proceedings can cause the Utility operating companies and System Energy to experience regulatory lag in recovering costs through rates, such that the Utility operating companies may not fully recover all costs during the rate effective period and may, therefore, earn less than their allowed returns. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with rate case proceedings. For a discussion of such appeals and related litigation for both the Utility operating companies and System Energy, see Note 2 to the financial statements.

The Utility operating companies have large customer and stakeholder bases and, as a result, could be the subject of public criticism or adverse publicity focused on issues including, but not limited to, the operation and maintenance of their assets and infrastructure, including with respect to climate or environmental matters, their preparedness for major storms or other extreme weather events and/or the time it takes to restore service after such

Part I Item 1A, 1B, and 1C

Entergy Corporation, Utility operating companies, and System Energy

events, the quality of their customer service, including timely and accurate billing practices and ability to resolve customer complaints, and the reasonableness of the cost of their service. Criticism or adverse publicity of this nature could render legislatures and other governing bodies, public service commissions and other regulatory authorities, and government officials less likely to view the applicable operating company in a favorable light and could potentially negatively affect legislative or regulatory processes or outcomes, as well as lead to increased regulatory oversight or more stringent legislative or regulatory requirements or other legislation or regulatory actions that adversely affect the Utility operating companies.

The Utility operating companies and System Energy, and the energy industry as a whole, have experienced a period of rising costs and investments and an upward trend in spending, especially with respect to infrastructure investments, which is likely to continue in the foreseeable future and could result in more frequent rate cases and requests for, and the continuation of, cost recovery mechanisms, all of which could face resistance from customers and other stakeholders especially in a rising cost environment, whether due to inflation or high fuel prices or otherwise, and/or in periods of economic decline or hardship. Significant increases in costs could increase financing needs and otherwise adversely affect Entergy, the Utility operating companies, and System Energy’s business, financial position, results of operation, or cash flows. For information regarding rate case proceedings and formula rate plans applicable to the Utility operating companies, see Note 2 to the financial statements.

Changes to state or federal legislation or regulation affecting electric generation, electric and natural gas transmission, distribution, and related activities could adversely affect Entergy and the Utility operating companies’ financial position, results of operations, or cash flows and their utility businesses.

If legislative and regulatory structures evolve in a manner that erodes the Utility operating companies’ exclusive rights to serve their regulated customers, such as through “retail open access” or otherwise, they could lose customers and sales and their results of operations, financial position, or cash flows could be materially affected. Additionally, technological advances in energy efficiency and distributed energy resources are reducing the costs of these technologies and, together with ongoing state and federal subsidies, the increasing penetration of these technologies could result in reduced sales by the Utility operating companies. Such loss of sales, due to the methodology used to determine cost of service rates or otherwise, could put upward pressure on rates, possibly resulting in adverse regulatory actions to mitigate such effects on rates. Further, the failure of regulatory structures to evolve to accommodate the changing needs and desires of customers with respect to the sourcing and use of electricity also could diminish sales by the operating companies. Entergy and the Utility operating companies cannot predict if or when they may be subject to changes in legislation or regulation, or the extent and timing of reductions of the cost of distributed energy resources, nor can they predict the impact of these changes on their results of operations, financial position, or cash flows.

The Utility operating companies recover fuel, purchased power, and associated costs through rate mechanisms that are subject to risks of delay or disallowance in regulatory proceedings, and sudden or prolonged increases in fuel and purchased power costs could lead to increased customer arrearages or bad debt expenses.

The Utility operating companies recover their fuel, purchased power, and associated costs from their customers through rate mechanisms subject to periodic regulatory review and adjustment. Because regulatory review can result in the disallowance of incurred costs found not to have been prudently incurred or not reflected in rates as permitted by approved rate schedules and accounting rules, including the cost of replacement power purchased when generators experience outages or when planned outages are extended, with the possibility of refunds to ratepayers, there exists some risk to the ultimate recovery of those costs, particularly when there are substantial or sudden increases in such costs. Regulators also may initiate proceedings to investigate the continued usage or the adequacy and operation of the fuel and purchased power recovery clauses of the Utility operating companies and, therefore, there can be no assurance that existing recovery mechanisms will remain unchanged or in effect at all.

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The Utility operating companies’ cash flows can be negatively affected by the time delays between when gas, power, or other commodities are purchased and the ultimate recovery from customers of the costs in rates. On occasion, when the level of incurred costs for fuel and purchased power rises dramatically, some of the Utility operating companies may agree to defer recovery of a portion of that period’s fuel and purchased power costs for recovery at a later date, which could increase the near-term working capital and borrowing requirements of those companies. The Utility operating companies also may experience, and in some instances have experienced, an increase in customer bill arrearages and bad debt expenses due to, among other reasons, increases in fuel and purchased power costs, especially in periods of economic decline or hardship. For a description of fuel and purchased power recovery mechanisms and information regarding the regulatory proceedings for fuel and purchased power cost recovery, see Note 2 to the financial statements.

The Utility operating companies are subject to economic risks associated with participation in the MISO markets and the allocation of transmission upgrade costs. The operation of the Utility operating companies’ transmission system pursuant to the MISO RTO tariff and their participation in the MISO RTO’s wholesale markets may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.

The Utility operating companies are subject to economic risks associated with participation in the MISO markets and resource adequacy construct. MISO tariff rules and system conditions, including transmission congestion, could affect the Utility operating companies’ ability to sell capacity, energy, and/or ancillary services in certain regions and/or the economic value of such sales, or increase the cost of serving the Utility operating companies’ respective loads. MISO market rules may change or be interpreted in ways that cause additional cost and risk, including compliance risk. Additionally, each Utility operating company’s continued participation in MISO may be affected by the outcomes of proceedings at their respective retail regulators regarding the realized and expected costs and benefits associated with such Utility operating company’s ongoing participation in MISO.

The Utility operating companies participate in the MISO regional transmission planning process and are subject to risks associated with planning decisions that MISO makes in the exercise of control over the planning of the Utility operating companies’ transmission assets that are under MISO’s functional control. The Utility operating companies pay transmission rates that reflect the cost of transmission projects that the Utility operating companies do not own, which could increase cash or financing needs. Further, FERC policies and regulation addressing cost responsibility for transmission projects, including transmission projects to interconnect new generation facilities, may potentially give rise to cash and financing-related risks as well as result in upward pressure on the retail rates of the Utility operating companies, which, in turn, may result in adverse actions by the Utility operating companies’ retail regulators. In addition to the cash and financing-related risks arising from the potential additional cost allocation to the Utility operating companies from transmission projects of others or changes in FERC policies or regulation related to cost responsibility for transmission projects, there is a risk that the Utility operating companies’ business and financial position could be harmed as a result of lost investment opportunities and other effects that flow from an increased number of competitive projects being approved and constructed that are interconnected with their transmission systems.

Further, the terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets, the allocation of transmission upgrade costs, the MISO-wide allowed base rate of return on equity, and any required MISO-related charges and credits are subject to regulation by the FERC. The operation of the Utility operating companies’ transmission system pursuant to the MISO tariff and their participation in the MISO wholesale markets, and the resulting costs, may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.

The MISO tariff provisions governing the rights and obligations associated with the resource adequacy construct provided under the MISO tariff are subject to change and have recently undergone significant changes, some of which are the subject of pending litigation and/or appeals. As an example, MISO recently has made

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changes to its capacity accreditation methodology for thermal resources which emphasizes performance during a very small subset of hours in which the supply of generation capacity needed to serve load is tightest. MISO is now embarking on a larger scale reassessment of its overall accreditation practices, including accreditation of renewable resources. Due to their magnitude and, with respect to the changes already made, the speed with which they have been implemented, these changes carry risk, including compliance risk, and may result in material additional costs being passed through to the Utility operating companies’ customers in retail rates, including but not limited to additional capacity costs incurred in the annual MISO Planning Resource Auction. Also, by virtue of the Utility operating companies’ participation in MISO and the design and terms of the MISO resource adequacy construct, other load-serving entities served by the Utility operating companies’ transmission assets, which are under MISO’s functional control, may be able to circumvent reasonable resource planning obligations and avoid, in whole or in part, the full cost of procuring the resources reasonably needed to reliably supply their respective loads. In particular, the design of the current MISO resource adequacy construct and the absence of a minimum capacity obligation in MISO create a risk of other load-serving entities engaging in “free ridership” through their strategy for participation in the MISO resource adequacy construct and energy and ancillary services markets – specifically, by using energy and ancillary services available from the Utility operating companies’ owned and controlled generating units without paying a reasonable share of the cost of the capacity required to provide such energy and ancillary services. As a result, there are a variety of risks to the Utility operating companies and their customers, including the risk of bearing additional costs for resources needed to ensure reliable service, the risk of reduced reliability and the enhanced risk of outages and lost sales which, because of the methodology for establishing cost of service rates, presents the risk of upward pressure on the Utility operating companies’ rates.

In addition, a large volume of parties and individual generation resources are presently seeking to interconnect to the transmission system MISO administers and over which MISO exercises functional control. Due to the resources and time required to study and evaluate these numerous interconnection requests, including the effects of speculative requests and requests that are withdrawn at late stages of the process, the current MISO interconnection queue to review new requests is subject to significant delays or periods in which MISO does not accept new interconnection requests. These delays present risks to the Utility operating companies and their ability to develop and procure new generation resources to serve their respective loads.

For additional information on MISO regulation and the Utility operating companies’ membership in MISO, see “Federal Regulation of the Utility – Transmission and MISO Markets” section of Part I, Item 1.

Entergy’s and the Utility operating companies’ business, results of operations, and financial condition could be adversely affected by events beyond their control, such as public health crises, natural disasters, geopolitical tensions, or other catastrophic events.

Entergy and the Utility operating companies could be adversely affected by various events beyond their control, including, without limitation, public health crises, natural disasters, geopolitical tensions and other political instability, or other catastrophic events. Any of the foregoing, whether occurring locally, nationally, or globally, and the resulting effects thereof could lead to disruption of the general economy, impacts on the customers of the Utility operating companies, and disruption of the operations of Entergy’s subsidiaries, due to, among other things:

•supply chain, vendor, and contractor disruptions, including shortages or delays in the availability of key components, parts, and supplies such as electronic components and solar panels;

•delays in completion of capital or other construction projects, maintenance, and other operations activities, including prolonged or delayed refueling and maintenance outages;

•adverse impacts on liquidity and cash flows, including through declining sales, reduced revenues, delays in receipts of customer payments, or increased bad debt expense;

•delays in regulatory proceedings;

•regulatory outcomes that require the Utility operating companies to postpone planned investments and otherwise reduce costs due to, for example, the impact of a public health crises or such other catastrophic events on their customers;

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•workforce availability challenges, including, for example, from infections, health, or safety issues resulting from a public health crisis;

•increased storm recovery costs;

•increased cybersecurity risks as a result of many employees telecommuting;

•volatility in the credit or capital markets (and any related increased cost of capital or any inability to access the capital markets or draw on available credit facilities on favorable terms), which could in turn, cause a decrease in the value of its defined benefit pension or decommissioning trust funds;

•adverse impacts on Entergy’s credit metrics or ratings;

•governmental mandates in response to any such event; or

•other adverse impacts on their ability to execute on business strategies and initiatives.

To the extent any of these events occur, the business, results of operations, and financial condition of Entergy and the Utility operating companies could be adversely affected.

(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)

A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather, the impact on customer bills of permitted storm cost recovery, or the inability to securitize future storm restoration costs could have material effects on Entergy and its Utility operating companies.

Entergy’s and its Utility operating companies’ results of operations, liquidity, and financial condition can be materially affected by the destructive effects of severe weather. Severe weather can also result in significant outages for the customers of the Utility operating companies and, therefore, reduced revenues for the Utility operating companies during the period of the outages. A delay or failure in recovering amounts for storm restoration costs incurred, inability to securitize future storm restoration costs, or loss of revenues as a result of severe weather could have a material effect on Entergy and those Utility operating companies affected by severe weather, including lower credit ratings and, thus, higher costs for future debt issuances. The inability to recover losses either excluded by insurance or in excess of the insurance limits that can be secured economically also could have a material effect on Entergy and its Utility operating companies. In addition, the recovery of major storm restoration costs from customers could effectively limit our ability to make planned capital or other investments due to the impact of such storm cost recovery on customer bills, especially in a rising cost environment.

Weather, economic conditions, technological developments, and other factors may have a material impact on electricity and gas sales and otherwise materially affect the Utility operating companies’ results of operations and system reliability.

Temperatures above normal levels in the summer tend to increase electric cooling demand and revenues, and temperatures below normal levels in the winter tend to increase electric and gas heating demand and revenues. As a corollary, mild temperatures in either season tend to decrease energy usage and resulting revenues. Higher consumption levels coupled with seasonal pricing differentials typically cause the Utility operating companies to report higher revenues in the third quarter of the fiscal year than in the other quarters. Changing weather patterns and extreme weather conditions, including hurricanes or tropical storms, droughts, wildfires, flooding events, or ice storms, the frequency or intensity of which may be exacerbated by climate change, may stress the Utility operating companies’ generation facilities and transmission and distribution systems, resulting in increased maintenance and capital costs (and potential increased financing needs), limits on their ability to meet peak customer demand, increased regulatory oversight, criticism or adverse publicity, and reduced customer satisfaction. These extreme conditions could have a material effect on the Utility operating companies’ financial condition, results of operations, and liquidity.

Entergy’s electricity sales volumes are affected by a number of factors including weather and economic conditions, trends in energy efficiency, new technologies, and self-generation alternatives, including the willingness

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and ability of large industrial customers to develop co-generation facilities that greatly reduce their grid demand. In addition, changes to regulatory policies, such as those that allow customers to directly access the market to procure wholesale energy or those that incentivize development and utilization of new, developing, or alternative sources of generation, could, and in some instances, have reduced sales, and other non-traditional procurements, such as virtual purchase power agreements, could, and in some instances have limited growth opportunities or reduced sales at the Utility operating companies. Some of these factors are inherently cyclical or temporary in nature, such as the weather or economic conditions, and typically do not have a long-lasting effect on Entergy’s operating results. Others, such as the organic turnover of appliances and lighting and their replacement with more efficient ones and adoption of newer technologies, including smart thermostats, new building codes, distributed energy resources, energy storage, demand side management, and rooftop solar, are having a more permanent effect by reducing sales growth rates from historical norms. As a result of these emerging efficiencies and technologies, the Utility operating companies may lose customers or experience lower average use per customer in the residential and commercial classes, and continuing advances have the potential to further limit sales or sales growth in the future.

The Utility operating companies also may face competition from other companies offering products and services to Entergy’s customers. Electricity sales to industrial customers, in particular, benefit from steady economic growth and favorable commodity markets; however, industrial sales are sensitive to changes in conditions in the markets in which its customers operate. Negative changes in any of these or other factors, particularly sustained economic downturns or sluggishness, have the potential to result in slower sales growth or sales declines and increased bad debt expense, which could materially affect Entergy’s and the Utility operating companies’ results of operations, financial condition, and liquidity. The Utility operating companies also may not realize anticipated or expected growth in industrial sales, such as from electrification opportunities to help such customers achieve their environmental and sustainability goals. This could occur because of changes in customers’ goals or business priorities, competition from other companies, or decisions by such customers to seek to achieve such goals through methods not offered by Entergy.

Nuclear Operating, Shutdown, and Regulatory Risks

(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)

Certain of the Utility operating companies and System Energy are expected to consistently operate their nuclear power plants at high capacity factors in order to be successful, and lower capacity factors could materially affect Entergy’s and their results of operations, financial condition, and liquidity.

Nuclear capacity factors significantly affect the results of operations of certain Utility operating companies and System Energy. Nuclear plant operations involve substantial fixed operating costs. Consequently, there is pressure on plant owners to operate nuclear power plants at higher capacity factors, though such operations always must be consistent with safety, reliability, and nuclear regulatory requirements. For the Utility operating companies that own nuclear plants, lower nuclear plant capacity factors can increase production costs by requiring the affected companies to generate additional energy, sometimes at higher costs, from their owned or contractually controlled facilities or purchase additional energy in the spot or forward markets in order to satisfy their supply needs.

Certain of the Utility operating companies and System Energy periodically shut down their nuclear power plants to replenish fuel. Plant maintenance and upgrades are often scheduled during such refueling outages. If refueling outages last longer than anticipated or if unplanned outages arise, Entergy’s and their results of operations, financial condition, and liquidity could be materially affected.

Outages at nuclear power plants to replenish fuel require the plant to be “turned off.” Refueling outages generally are planned to occur once every 18 to 24 months. Plant maintenance and upgrades are often scheduled during such planned outages, which may extend the planned outage duration beyond that required for only refueling activities. When refueling outages last longer than anticipated or a plant experiences unplanned outages, capacity factors decrease, and maintenance costs may increase.

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Certain of the Utility operating companies and System Energy face risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication). These risks could materially affect Entergy’s and their results of operations, financial condition, and liquidity.

Based upon currently planned fuel cycles, Entergy’s nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable prices through the end of 2027. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners. While there are a number of possible alternate suppliers that may be accessed to mitigate any supplier performance failure, the pricing of any such alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S. Market prices for nuclear fuel have been extremely volatile from time to time in the past and may be subject to increased volatility due to the imposition of tariffs, domestic purchase requirements, supply chain disruptions, limitations or bans on importation of uranium or uranium products from foreign countries, evolving geopolitical conditions such as the wars between Russia and Ukraine and Israel and Hamas, the Nigerien coup, or shifting trade arrangements or sanctions between countries. Although Entergy’s nuclear fuel contract portfolio provides a degree of hedging against market risks for several years, costs for nuclear fuel in the future cannot be predicted with certainty due to inherent market uncertainties, as well as uncertainties arising from geopolitical conflicts, and price changes could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.

Entergy’s ability to assure uninterrupted nuclear fuel supply also depends upon the performance and reliability of conversion, enrichment, and fabrication services providers. These service providers are fewer in number than uranium suppliers. For conversion and enrichment services, Entergy diversifies its supply by supplier and country and may take special measures to ensure a reliable supply of enriched uranium for fabrication into nuclear fuel. For fabrication services, each plant is dependent upon the performance of the fabricator of that plant’s nuclear fuel; therefore, Entergy relies upon additional monitoring, inspection, and oversight of the fabrication process to assure reliability and quality of its nuclear fuel. Certain of the suppliers and service providers are located in or dependent upon foreign countries, such as Russia, and international sanctions or tariffs impacting trade with such countries could further restrict the ability of such suppliers or service providers to continue to supply fuel or provide such services at acceptable prices or at all. While such suppliers have performed as expected to date, the future inability of suppliers to perform such obligations could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.

Certain of the Utility operating companies and System Energy face the risk that the NRC will change or modify its regulations, suspend or revoke their licenses, or increase oversight of their nuclear plants, which could materially affect Entergy’s and their results of operations, financial condition, and liquidity.

Under the Atomic Energy Act and Energy Reorganization Act, the NRC regulates the operation of nuclear power plants. The NRC may modify, suspend, or revoke licenses, shut down a nuclear facility and impose civil penalties for failure to comply with the Atomic Energy Act, related regulations, or the terms of the licenses for nuclear facilities. Interested parties may also intervene in pending proceedings, which could result in prolonged proceedings. A change in the Atomic Energy Act, other applicable statutes, or the applicable regulations or licenses, or the NRC’s interpretation thereof, may require a substantial increase in capital expenditures or may result in increased operating or decommissioning costs and could materially affect the results of operations, liquidity, or financial condition of Entergy, certain of the Utility operating companies, or System Energy. A change in the classification of a plant owned by one of these companies under the NRC’s Reactor Oversight Process, which is the NRC’s program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response, also could cause the owner of the plant to incur material additional costs as a result of the increased oversight activity and potential response costs associated with the

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change in classification. For additional information concerning the current classification of the plants owned by Entergy Arkansas, Entergy Louisiana, and System Energy, see “Regulation of Entergy’s Business - Regulation of the Nuclear Power Industry - NRC Reactor Oversight Process” in Part I, Item 1.

Events at nuclear plants owned by one of these companies, as well as those owned by others, may lead to a change in laws or regulations or the terms of the applicable licenses, or the NRC’s interpretation thereof, or may cause the NRC to increase oversight activity or initiate actions to modify, suspend, or revoke licenses, shut down a nuclear facility, or impose civil penalties. As a result, if an incident were to occur at any nuclear generating unit, whether an Entergy nuclear generating unit or not, it could materially affect the financial condition, results of operations, and liquidity of Entergy, certain of the Utility operating companies, or System Energy.

Certain of the Utility operating companies and System Energy are exposed to risks and costs related to operating and maintaining their nuclear power plants, and their failure to maintain operational efficiency at their nuclear power plants could materially affect Entergy’s and their results of operations, financial condition, and liquidity.

The nuclear generating units owned by certain of the Utility operating companies and System Energy began commercial operations in the 1970s-1980s. Older equipment may require more capital expenditures to keep each of these nuclear power plants operating safely and efficiently. This equipment is also likely to require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages, or any unanticipated capital expenditures, could result in increased costs, some of which costs may not be fully recoverable by these Utility operating companies and System Energy in regulatory proceedings should there be a determination of imprudence. Operations at any of the nuclear generating units owned and operated by Entergy’s subsidiaries could degrade to the point where the affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. A decision may be made to close a unit rather than incur the expense of restarting it or returning the unit to full capacity. For these Utility operating companies and System Energy, this could result in certain costs being stranded and potentially not fully recoverable in regulatory proceedings. In addition, the operation and maintenance of Entergy’s nuclear facilities require the commitment of substantial human resources that can result in increased costs.

Moreover, Entergy is becoming more dependent on fewer suppliers for key parts of Entergy’s nuclear power plants that may need to be replaced or refurbished, and in some cases, parts are no longer available and have to be reverse-engineered for replacement. In addition, certain major parts have long lead-times to manufacture if an unplanned replacement is needed. This dependence on a reduced number of suppliers and long lead-times on certain major parts for unplanned replacements could result in delays in obtaining qualified replacement parts and, therefore, greater expense for certain of the Utility operating companies and System Energy.

The costs associated with the storage of the spent nuclear fuel of certain of the Utility operating companies and System Energy, as well as the costs of and their ability to fully decommission their nuclear power plants, could be significantly affected by the timing of the opening of a spent nuclear fuel disposal facility, as well as interim storage and transportation requirements.

Certain of the Utility operating companies and System Energy incur costs for the on-site storage of spent nuclear fuel. The approval of a license for a national repository for the disposal of spent nuclear fuel, such as the one proposed for Yucca Mountain, Nevada, or any interim storage facility, and the timing of such facility opening, will significantly affect the costs associated with on-site storage of spent nuclear fuel. For example, while the DOE is required by law to proceed with the licensing of the Yucca Mountain repository and, after the license is granted by the NRC, to construct the repository and commence the receipt of spent fuel, the NRC licensing of the Yucca Mountain repository is effectively at a standstill. These actions are prolonging the time before spent fuel is removed from Entergy’s plant sites. Because the DOE has not accomplished its objectives, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and is in partial breach of its spent fuel disposal contracts, and Entergy has sued the DOE for such breach. Furthermore, Entergy is uncertain as to when the DOE will commence acceptance of

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spent fuel from its facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at the companies’ nuclear sites and maintenance costs on existing storage facilities, including aging management of fuel storage casks, may increase. The costs of on-site storage are also affected by regulatory requirements for such storage. In addition, the availability of a repository or other off-site storage facility for spent nuclear fuel may affect the ability to fully decommission the nuclear units and the costs relating to decommissioning. For further information regarding spent fuel storage, see the “Critical Accounting Estimates – Nuclear Decommissioning Costs – Spent Fuel Disposal” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy and Note 8 to the financial statements.

Certain of the Utility operating companies and System Energy may be required to pay substantial retrospective premiums imposed under the Price-Anderson Act and/or by Nuclear Electric Insurance Limited (NEIL) in the event of a nuclear incident, and losses not covered by insurance could have a material effect on Entergy’s and their results of operations, financial condition, or liquidity.

Accidents and other unforeseen problems at nuclear power plants have occurred both in the United States and elsewhere. As required by the Price-Anderson Act, the Utility operating companies and System Energy carry the maximum available amount of primary nuclear off-site liability insurance with American Nuclear Insurers, which as of January 1, 2024 is $500 million for each operating site. Claims for any nuclear incident exceeding that amount are covered under Secondary Financial Protection. The Price-Anderson Act limits each reactor owner’s public liability (off-site) for a single nuclear incident to the payment of retrospective premiums into a secondary insurance pool, which is referred to as Secondary Financial Protection, up to approximately $165.9 million per reactor. With 95 reactors currently participating, this translates to a total public liability cap of approximately $15.8 billion per incident. The limit is subject to change to account for the effects of inflation, a change in the primary limit of insurance coverage, and changes in the number of licensed reactors. As a result, in the event of a nuclear incident that causes damages (off-site) in excess of the primary insurance coverage, each owner of a nuclear plant reactor, including Entergy’s Utility operating companies and System Energy, regardless of fault or proximity to the incident, will be required to pay a retrospective premium, equal to its proportionate share of the loss in excess of the primary insurance level, up to a maximum of approximately $165.9 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is approximately $830 million). The retrospective premium payment is currently limited to approximately $25 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $165.9 million cap.

NEIL is a utility industry mutual insurance company, owned by its members, including the Utility operating companies and System Energy. NEIL provides onsite property and decontamination coverage. All member plants could be subject to an annual assessment (retrospective premium of up to 10 times current annual premium for all policies) should the NEIL surplus (reserve) be significantly depleted due to insured losses. As of April 1, 2023, the maximum annual assessment amounts total approximately $70 million for the Utility plants.

As mentioned above, as an owner of nuclear power plants, Entergy participates in industry self-insurance programs and could be liable to fund claims should a plant owned by a different company experience a major event. Any resulting liability from a nuclear accident may exceed the applicable primary insurance coverage and require contribution of additional funds through the industry-wide program that could significantly affect the results of operations, financial condition, or liquidity of Entergy, certain of the Utility operating companies, or System Energy.

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The decommissioning trust fund assets for the nuclear power plants owned by certain of the Utility operating companies and System Energy may not be adequate to meet decommissioning obligations if market performance and other changes decrease the value of assets in the decommissioning trusts, if one or more of Entergy’s nuclear power plants is retired earlier than the anticipated shutdown date, if the plants cost more to decommission than estimated, or if current regulatory requirements change, which then could require significant additional funding.

Owners of nuclear generating plants have an obligation to decommission those plants. Certain of the Utility operating companies and System Energy maintain decommissioning trust funds for this purpose. Certain of the Utility operating companies and System Energy collect funds from their customers, which are deposited into the trusts covering the units operated for or on behalf of those companies. Those rate collections, as adjusted from time to time by rate regulators, are generally based upon operating license lives and trust fund balances as well as estimated trust fund earnings and decommissioning costs. Assets in these trust funds are subject to market fluctuations, will yield uncertain returns that may fall below projected return rates, and may result in losses resulting from the recognition of impairments of the value of certain securities held in these trust funds.

Under NRC regulations, nuclear plant owners are permitted to project the NRC-required decommissioning amount, based on an NRC formula or a site-specific estimate, and the amount that will be available in each nuclear power plant’s decommissioning trusts combined with any other decommissioning financial assurances in place. The projections are made based on the operating license expiration date and the mid-point of the subsequent decommissioning process, or the anticipated actual completion of decommissioning if a site-specific estimate is used. If the projected amount of each individual plant’s decommissioning trusts exceeds the NRC-required decommissioning amount, then its NRC license termination decommissioning obligations are considered to be funded in accordance with NRC regulations. If the projected costs do not sufficiently reflect the actual costs required to decommission these nuclear power plants, or if funding is otherwise inadequate, or if the formula, formula inputs, or site-specific estimate is changed to require increased funding, additional resources or commitments would be required. Furthermore, depending upon the level of funding available in the trust funds, the NRC may not permit the trust funds to be used to pay for related costs such as the management of spent nuclear fuel that are not included in the NRC’s formula. The NRC may also require a plan for the provision of separate funding for spent fuel management costs.

Further, federal or state regulatory changes, including mandated increases in decommissioning funding or changes in the methods or standards for decommissioning operations, may also increase the funding requirements of, or accelerate the timing for funding of, the obligations related to the decommissioning of the nuclear generating plant owned by certain of the Utility operating companies or System Energy or may restrict the decommissioning-related costs that can be paid from the decommissioning trusts. Such changes also could result in the need for additional contributions to decommissioning trusts, or the posting of parent guarantees, letters of credit, or other surety mechanisms. As a result, under any of these circumstances, the results of operations, liquidity, and financial condition of Entergy, certain of the Utility operating companies, or System Energy could be materially affected.

An early plant shutdown (either generally or relative to current expectations), poor investment results, or higher than anticipated decommissioning costs (including as a result of changing regulatory requirements) could cause trust fund assets to be insufficient to meet the decommissioning obligations, with the result that certain of the Utility operating companies or System Energy may be required to provide significant additional funds or credit support to satisfy regulatory requirements for decommissioning, which, with respect to these Utility operating companies or System Energy, may not be recoverable from customers in a timely fashion or at all.

For further information regarding nuclear decommissioning costs, see the “Critical Accounting Estimates - Nuclear Decommissioning Costs” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy, and Notes 9 and 16 to the financial statements.

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New or existing safety concerns regarding operating nuclear power plants and nuclear fuel could lead to restrictions upon the operation and decommissioning of Entergy’s nuclear power plants.

New and existing concerns are being expressed in public forums about the safety of nuclear generating units and nuclear fuel. These concerns have led to, and may continue to lead to, various proposals to federal regulators and governing bodies in some localities where Entergy’s subsidiaries own nuclear generating units for legislative and regulatory changes that might lead to the shutdown of nuclear units, additional requirements or restrictions related to spent nuclear fuel on-site storage and eventual disposal, or other adverse effects on owning, operating, and decommissioning nuclear generating units. Entergy vigorously responds to these concerns and proposals. If any of the existing proposals, or any proposals that may arise in the future with respect to legislative and regulatory changes, become effective, they could have a material effect on Entergy’s results of operations and financial condition.

Business Risks

(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Entergy and its Registrant Subsidiaries depend on access to the capital markets and, at times, may face potential liquidity constraints, which could make it more difficult to handle future contingencies such as natural disasters or substantial increases in gas and fuel prices. Disruptions in the capital and credit markets may adversely affect Entergy’s and its subsidiaries’ ability to meet liquidity needs, or to access capital to operate and grow their businesses, and the cost of capital.

Entergy’s business is capital intensive and dependent upon its ability to access capital at reasonable rates and other terms. At times there are also spikes in the price for natural gas and other commodities that increase the liquidity requirements of the Utility operating companies. In addition, Entergy’s and the Registrant Subsidiaries’ liquidity needs could significantly increase in the event of a hurricane or other weather-related or unforeseen disaster similar to that experienced in Entergy’s service area with Hurricane Katrina and Hurricane Rita in 2005, Hurricane Gustav and Hurricane Ike in 2008, Hurricane Isaac in 2012, Hurricane Laura, Hurricane Delta, and Hurricane Zeta in 2020, and Winter Storm Uri and Hurricane Ida in 2021. The occurrence of one or more contingencies, including an adverse decision or a delay in regulatory recovery of fuel or purchased power costs or storm restoration costs, an acceleration of payments or decreased credit lines, less cash flow from operations than expected, changes in regulation or governmental policy (including tax and trade policy), or other unknown or unforeseen events, could cause the financing needs of Entergy and its subsidiaries to increase. In addition, accessing the debt capital markets more frequently in these situations may result in an increase in leverage. Material leverage increases could negatively affect the credit ratings of Entergy, the Utility operating companies, and System Energy, which in turn could negatively affect access to the capital markets.

The inability to raise capital on favorable terms, particularly during times of high interest rates and inflation, and uncertainty or reduced liquidity in the capital markets, could negatively affect Entergy and its subsidiaries’ ability to maintain and to expand their businesses. Access to capital markets could be restricted and/or borrowing costs could be increased due to certain sources of debt and equity capital being unwilling to invest in offerings to fund fossil fuel projects or companies that are impacted by extreme weather events, that rely on fossil fuels, or that are impacted by risks related to climate change. Factors beyond Entergy’s control may create uncertainty that could increase its cost of capital or impair its ability to access the capital markets, including the ability to draw on its bank credit facilities. These factors include depressed economic conditions, a recession, increasing interest rates, inflation, sanctions, trade restrictions, political instability, war, terrorism, and extreme volatility in the debt, equity, or credit markets. Entergy and its subsidiaries are unable to predict the degree of success they will have in renewing or replacing their credit facilities as they come up for renewal. Moreover, the size, terms, and covenants of any new credit facilities may not be comparable to, and may be more restrictive than, existing facilities. If Entergy and its subsidiaries are unable to access the credit and capital markets on terms that are reasonable, they may have to delay

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raising capital, issue shorter-term securities, and/or bear an unfavorable cost of capital, which, in turn, could impact their ability to grow their businesses, decrease earnings, significantly reduce financial flexibility, and/or limit Entergy Corporation’s ability to sustain its current common stock dividend level.

A downgrade in Entergy’s or its Registrant Subsidiaries’ credit ratings could negatively affect Entergy’s and its Registrant Subsidiaries’ ability to access capital or the cost of such capital and/or could require Entergy or its subsidiaries to post collateral, accelerate certain payments, or repay certain indebtedness.

There are a number of factors that rating agencies evaluate to arrive at credit ratings for each of Entergy and the Registrant Subsidiaries, including each Registrant Subsidiary’s regulatory framework, ability to recover costs and earn returns, storm or climate risk exposure, diversification, and financial strength and liquidity. If one or more rating agencies downgrade Entergy’s or any of the Registrant Subsidiaries’ ratings, particularly below investment grade, borrowing costs would increase, the potential pool of investors and funding sources would likely decrease, and cash or letter of credit collateral demands may be triggered by the terms of a number of commodity contracts, leases, and other agreements.

Most of Entergy’s and its subsidiaries’ suppliers and counterparties require sufficient creditworthiness to enter into transactions. If Entergy’s or the Registrant Subsidiaries’ ratings decline, particularly below investment grade, or if certain counterparties believe Entergy or the Utility operating companies are losing creditworthiness and demand adequate assurance under fuel, gas, and purchased power contracts, the counterparties may require posting of collateral in cash or letters of credit, prepayment for fuel, gas or purchased power or accelerated payment, or counterparties may decline business with Entergy or its subsidiaries.

The reputation of Entergy or its Registrant Subsidiaries may be materially adversely affected by negative publicity or the inability to meet its stated goals or commitments, among other potential causes.

As with any company, Entergy’s and its Registrant Subsidiaries’ reputations are an important element of their ability to effectively conduct their businesses. Entergy’s and its Registrant Subsidiaries’ reputations could be harmed by a variety of factors, including: failure of a generating asset or supporting infrastructure; failure to restore power after a hurricane or other severe weather event in a manner perceived as timely by regulators or customers; the incurrence of storm restoration costs perceived as excessive by regulators or customers; failure to effectively manage land and other natural resources; real or perceived violations of environmental regulations, including those related to climate change; real or perceived issues with Entergy’s safety culture or work environment; inability to meet their climate or human capital strategy goals, or failure to demonstrate meaningful progress toward such goals; inability to keep their electricity rates stable; inability to provide quality customer service, including timely and accurate billing; involvement in a class-action or other high-profile lawsuit; significant delays in construction projects; occurrence of or responses to cyber attacks, data breaches or physical- or cyber- security vulnerabilities; acts or omissions of Entergy management or acts or omissions of a contractor or other third party working with or for Entergy or its Registrant Subsidiaries, which actually or perceivably reflect negatively on Entergy or its Registrant Subsidiaries; measures taken to offset reductions in demand or to supply rising demand; a significant dispute with one of Entergy’s or its Registrant Subsidiaries’ customers or other stakeholders; or negative political and public sentiment resulting in a significant amount of adverse press coverage and other adverse statements affecting Entergy or its Registrant Subsidiaries.

Addressing any adverse publicity or regulatory scrutiny is time consuming and expensive and, regardless of the factual basis for the assertions being made (or lack thereof), can have a negative impact on the reputations of Entergy or its Registrant Subsidiaries, on the morale and performance of their employees, and on their relationships with their respective regulators, customers, investors, and commercial counterparties. Adverse publicity or regulatory scrutiny may also have a negative impact on Entergy or its Registrant Subsidiaries’ ability to take timely advantage of various business or market opportunities.

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Deterioration in Entergy’s or its Registrant Subsidiaries’ reputations may harm Entergy’s or its Registrant Subsidiaries’ relationships with their customers, regulators, and other stakeholders, may increase their cost of doing business, may interfere with its ability to attract and retain a qualified, inclusive, and diverse workforce, may impact Entergy’s or its Registrant Subsidiaries’ ability to raise debt capital, and may potentially lead to the enactment of new laws and regulations, or the modification of existing laws and regulations, that negatively affect the way Entergy or its Registrant Subsidiaries conduct their business, or may have a material adverse effect on their financial condition and results of operations.

Recent U.S. tax legislation may materially adversely affect Entergy’s financial condition, results of operations, and cash flows.

The Tax Cuts and Jobs Act of 2017 significantly changed the U.S. Internal Revenue Code, including taxation of U.S. corporations, by, among other things, reducing the federal corporate income tax rate, limiting interest deductions, and altering the expensing of capital expenditures. The Inflation Reduction Act of 2022 further significantly changed the U.S. Internal Revenue Code by, among other things, enacting a new corporate alternative minimum tax and expanding federal tax credits for clean energy production. The interpretive guidance issued by the IRS and state tax authorities may be inconsistent with Entergy’s own interpretation and the legislation could be subject to amendments, which could lessen or increase certain impacts of the legislation. Further, changes in tax legislation or guidance, or uncertainties regarding interpretation of such tax legislation or guidance, could impact interpretation of and negotiations around certain contractual arrangements with counterparties, which could result in unfavorable changes to such arrangements or delays. In addition, the retail regulatory treatment of the expanded tax credits and corporate alternative minimum tax included in the Inflation Reduction Act of 2022 could materially impact Entergy’s future cash flows, and this legislation and pending interpretive guidance could result in unintended consequences not yet identified that could have a material adverse impact on Entergy’s financial results and future cash flows.

Based on initial IRS guidance and current internal forecasts, Entergy and the Registrant Subsidiaries may become subject to the corporate alternative minimum tax included in the Inflation Reduction Act of 2022 beginning in the next two to four years.

The tax rate decrease included in the Tax Cuts and Jobs Act required Entergy to record a regulatory liability for income taxes payable to customers. Such regulatory liability for income taxes is described in Note 3 to the financial statements. Depending on the outcome of IRS examinations or tax positions and elections that Entergy may make, Entergy and the Registrant Subsidiaries may be required to record additional charges or credits to income tax expense.

See Note 3 to the financial statements for discussion of the effects of the Tax Cuts and Jobs Act on 2023, 2022, and 2021 results of operations and financial condition, the provisions of the Tax Cuts and Jobs Act, and the uncertainties associated with accounting for the Tax Cuts and Jobs Act, and Note 2 to the financial statements for discussion of the regulatory proceedings that have considered the effects of the Tax Cuts and Jobs Act. For further discussion of the effects of the Inflation Reduction Act of 2022, see the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 3 to the financial statements.

Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy’s and the Registrant Subsidiaries’ results of operations, financial condition, and liquidity.

Entergy and its subsidiaries make judgments regarding the potential tax effects of various transactions and results of operations to estimate their obligations to taxing authorities, which judgment may prove to be incorrect or may be disputed by regulators or taxing authorities. These tax obligations include income, franchise, real estate, sales and use, and employment-related taxes. These judgments include provisions for potential adverse outcomes

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regarding tax positions that have been taken. Entergy and its subsidiaries also estimate their ability to utilize tax benefits, including those in the form of carryforwards for which the benefits have already been reflected in the financial statements. Changes in federal, state, or local tax laws or interpretive guidance relating thereto, adverse tax audit results or adverse tax rulings on positions taken by Entergy and its subsidiaries could negatively affect Entergy’s and the Registrant Subsidiaries’ results of operations, financial condition, and liquidity. The intended and unintended consequences of recently enacted legislation could have a material adverse impact on Entergy’s financial results and future cash flows. For further information regarding Entergy’s income taxes, see the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 3 to the financial statements.

Entergy and its subsidiaries’ ability to successfully execute on their business strategies, including their ability to complete strategic transactions, is subject to significant risks, and, as a result, they may be unable to achieve some or all of the anticipated results of such strategies, which could materially affect their future prospects, results of operations, and the realization of any anticipated benefits from such transactions.

Entergy and its subsidiaries’ future prospects and results of operations significantly depend on their ability to successfully implement their business strategies, including achieving Entergy’s climate goals and commitments, which are subject to business, regulatory, economic, shareholder activism and other risks and uncertainties, many of which are beyond their control. As a result, Entergy and its subsidiaries may be unable to fully achieve the anticipated results of such strategies.

Additionally, Entergy and its subsidiaries have pursued and may continue to pursue strategic transactions including merger, acquisition, divestiture, joint venture, restructuring, or other strategic transactions. For example, each of Entergy Louisiana and Entergy New Orleans have entered into purchase and sale agreements to sell their respective regulated natural gas local distribution company businesses to a third-party. Also, a significant portion of Entergy’s utility business plan over the next several years includes the construction and/or purchase of a variety of solar facilities. These or other transactions and plans are or may become subject to regulatory approval and other material conditions or contingencies, including increased costs or delays resulting from supply chain disruptions, import tariffs, and other issues. The failure to complete these transactions or plans or any future strategic transaction successfully or on a timely basis could have an adverse effect on Entergy’s or its subsidiaries’ financial condition or results of operations and the market’s perception of Entergy’s ability to execute its strategy. Further, these transactions, and any completed or future strategic transactions, involve substantial risks, including the following:

•acquired businesses or assets may not produce revenues, earnings, or cash flow at anticipated levels;

•acquired businesses or assets could have environmental, permitting, or other problems for which contractual protections prove inadequate;

•Entergy and/or its subsidiaries may assume liabilities that were not disclosed to them, that exceed their estimates, or for which their rights to indemnification from the seller are limited;

•Entergy may experience issues integrating businesses into its internal controls over financial reporting;

•the acquisition or disposition of a business could divert management’s attention from other business concerns;

•Entergy and/or its subsidiaries may be unable to obtain the necessary regulatory or governmental approvals to close a transaction, such approvals may be granted subject to terms that are unacceptable, or Entergy or its subsidiaries otherwise may be unable to achieve anticipated regulatory treatment of any such transaction or acquired business or assets; and

•Entergy or its subsidiaries otherwise may be unable to achieve the full strategic and financial benefits that they anticipate from the transaction, or such benefits may be delayed or may not occur at all.

Entergy and its subsidiaries may not be successful in managing these or any other significant risks that they may encounter in acquiring or divesting a business, or engaging in other strategic transactions, which could have a material effect on their business, financial condition, or results of operations.

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The completion of capital projects, including the construction of power generation facilities, and other capital improvements, involve substantial risks. Should such efforts be unsuccessful, the financial condition, results of operations, or liquidity of Entergy and the Utility operating companies could be materially affected.

Entergy’s and the Utility operating companies’ ability to complete capital projects, including the construction of power generation facilities, or make other capital improvements, such as transmission and distribution infrastructure replacements or upgrades, in a timely and cost-effective manner and within budget is contingent upon many variables and subject to substantial risks. These variables include, but are not limited to, project management expertise, escalating costs for materials, labor, and environmental compliance, reliance on suppliers for timely and satisfactory performance, delays and cost increases, and supply chains and material constraints, including those that may result from major storm events, both within and outside of Entergy’s service area. Delays in obtaining permits, challenges in securing sufficient land for the siting of solar panels and power generation facilities, shortages in materials and qualified labor, levels of public support or opposition, suppliers and contractors not performing as expected or required under their contracts and/or experiencing financial problems that inhibit their ability to fulfill their obligations under contracts, changes in the scope and timing of projects, poor quality initial cost estimates from contractors, the inability to raise capital on favorable terms, changes in commodity prices affecting revenue, fuel costs, or materials costs, downward changes in the economy, changes in law or regulation, including environmental compliance requirements, further direct and indirect trade and tariff issues, including those associated with imported solar panels, supply chain delays or disruptions, and other events beyond the control of the Utility operating companies may occur that may materially affect the schedule, cost, and performance of these projects. If these projects or other capital improvements are significantly delayed or become subject to cost overruns or cancellation, Entergy and the Utility operating companies could incur additional costs and termination payments or face increased risk of potential write-off of the investment in the project. In addition, the Utility operating companies could be exposed to higher costs and market volatility, which could affect cash flow and cost recovery, should their respective regulators decline to approve the construction of the project or new generation needed to meet the reliability needs of customers at the lowest reasonable cost.

For further information regarding capital expenditure plans and other uses of capital in connection with capital projects, including the potential construction and/or purchase of additional generation supply sources within the Utility operating companies’ service areas, see the “Capital Expenditure Plans and Other Uses of Capital” section of Management’s Financial Discussion and Analysis for Entergy and each of the Registrant Subsidiaries.

Failure to attract, retain and manage an appropriately qualified workforce could negatively affect Entergy or its subsidiaries’ results of operations.

Entergy relies on a large and changing workforce, including employees, contractors, and temporary staffing. Certain factors, such as an aging workforce, mismatching of skill sets for current and future needs, failing to appropriately anticipate future workforce needs, workforce impacts from public health concerns, challenges competing with other employers offering fully remote or more flexible work options, rising salary and other labor costs, unavailability of contract resources, and labor disputes and work disruptions may lead to operating challenges and increased costs. The challenges include inability to attract or retain talent, lack of resources, loss of knowledge base, and the time required for skill development. Costs, including costs for contractors to replace employees, productivity costs, and safety costs, may increase. Failure to hire and adequately train replacement employees, or the future availability and cost of contract labor, may adversely affect the ability to manage and operate the business, especially considering the specialized workforce needs associated with nuclear generation facilities and new skills required to develop and operate a modernized, technology-enabled, and lower carbon power grid. If Entergy and its subsidiaries are unable to successfully attract, retain, and manage an appropriately qualified workforce, their results of operations, financial position, and cash flows could be negatively affected.

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Entergy and its subsidiaries, including the Utility operating companies and System Energy, may incur substantial costs to fulfill their obligations related to environmental and other matters.

The businesses in which Entergy’s subsidiaries, including the Utility operating companies and System Energy, operate are subject to extensive environmental regulation by local, state, and federal authorities. These laws and regulations affect the manner in which the Utility operating companies and System Energy conduct their operations and make capital expenditures. These laws and regulations also affect how Entergy’s subsidiaries, including the Utility operating companies and System Energy, manage air emissions, discharges to water, wetlands impacts, solid and hazardous waste storage and disposal, cooling and service water intake, the protection of threatened and endangered species, certain migratory birds and eagles, hazardous materials transportation, and similar matters. Federal, state, and local authorities continually revise these laws and regulations, and the laws and regulations are subject to judicial interpretation and to the permitting and enforcement discretion vested in the implementing agencies. Developing and implementing plans for facility compliance with these requirements can lead to capital, personnel, and operation and maintenance expenditures. Violations of these requirements can subject the Utility operating companies and System Energy to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, remediation and clean-up costs, civil penalties, and exposure to third parties’ claims for alleged health or property damages or for violations of applicable permits or standards. In addition, Entergy and its subsidiaries, including the Utility operating companies and System Energy, are subject to potential liability under these laws for the costs of remediation of environmental contamination of property now or formerly owned or operated by the Utility operating companies and System Energy and of property potentially contaminated by hazardous substances they generate. The Utility operating companies currently are involved in proceedings relating to sites where hazardous substances have been released and may be subject to additional proceedings in the future. Entergy’s subsidiaries, including the Utility operating companies and System Energy, have incurred and expect to incur significant costs related to environmental compliance.

Emissions of nitrogen and sulfur oxides, mercury, particulates, greenhouse gases, and other regulated emissions from generating plants potentially are subject to increased regulation, controls, and mitigation expenses. In addition, existing environmental regulations and programs promulgated by the EPA often are challenged legally, or are revised or withdrawn by the EPA, sometimes resulting in large-scale changes to anticipated regulatory regimes and the resulting need to shift course, both operationally and economically, depending on the nature of the changes. Risks relating to global climate change, initiatives to regulate, or otherwise compel reductions of greenhouse gas emissions, and water availability issues are discussed below.

Entergy and its subsidiaries may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals, or if Entergy and its subsidiaries fail to obtain, maintain, or comply with any such approval, the operation of its facilities could be stopped or become subject to additional costs. For further information regarding environmental regulation and environmental matters, including Entergy’s response to climate change, see the “Regulation of Entergy’s Business – Environmental Regulation” section of Part I, Item 1.

Environmental and regulatory obligations intended to combat the effects of climate change, including by compelling greenhouse gas emission reductions or reporting, increasing clean or renewable energy requirements, or placing a price on greenhouse gas emissions, or the achievement of voluntary climate commitments could materially affect the financial condition, results of operations, and liquidity of Entergy and Entergy’s subsidiaries, including the Utility operating companies and System Energy.

In an effort to address climate change concerns, some federal, state, and local authorities are calling for additional laws and regulations aimed at known or suspected causes of climate change. For example, the EPA, various environmental interest groups, and other organizations have focused considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. The EPA has promulgated regulations controlling greenhouse gas emissions from certain vehicles, and has proposed regulations for new,

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existing, and significantly modified stationary sources of emissions, including electric generating units. Such regulations continue to evolve. Various states and regions of the U.S. have taken action to establish greenhouse gas limitations and trading programs. In Louisiana, the former Office of the Governor announced in 2020 the creation of a Climate Initiatives Task Force and issued an executive order that established a path to net-zero emissions by 2050, while in 2021, the City Council of New Orleans passed a renewable and clean portfolio standard that sets a goal of net-zero emissions by 2040 and absolute zero emissions by 2050. The impact that continued changes in the governmental response to climate change risk and any judicial interpretation thereof will have on existing and pending environmental laws and regulations related to greenhouse gas emissions currently is unclear.

Developing and implementing plans for compliance with greenhouse gas emissions reduction or reporting or clean/renewable energy requirements, or for achieving voluntary climate commitments can lead to additional capital, personnel, and operation and maintenance expenditures and could significantly affect the economic position of existing facilities and proposed projects. The operations of low or non-emitting generating units (such as nuclear units and solar facilities) at lower than expected capacity factors could require increased generation from higher emitting units, thus increasing Entergy’s greenhouse gas emission rate. Moreover, long-term planning to meet environmental requirements can be negatively impacted and costs may increase to the extent laws and regulations change prior to full implementation. These requirements could, in turn, lead to changes in the planning or operations of balancing authorities or organized markets in areas where Entergy’s subsidiaries, including the Utility operating companies or System Energy, do business. Violations of such requirements may subject the Utility operating companies to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, civil penalties, and exposure to third parties’ claims for alleged health or property damages or for violations of applicable permits or standards. Further, real or perceived violations of environmental regulations, including those related to climate change, or inability to meet Entergy’s voluntary climate commitments, could negatively impact Entergy’s reputation or inhibit Entergy’s ability to pursue its decarbonization objectives. To the extent Entergy believes any of these costs are recoverable in rates, however, additional material rate increases for customers could be resisted by Entergy’s regulators and, in extreme cases, Entergy’s regulators might attempt to deny or defer timely recovery of these costs.

Future changes in regulation or policies governing the reporting or emission of CO2 and other greenhouse gases or mix of generation sources could (i) result in significant additional costs to Entergy’s Utility operating companies, their suppliers, or customers, (ii) make some of Entergy’s electric generating units uneconomical to maintain or operate, (iii) result in the early retirement of generation facilities and stranded costs if Entergy’s Utility operating companies are unable to fully recover the costs and investment in generation, and (iv) increase the difficulty that Entergy and its Utility operating companies have with obtaining or maintaining required environmental regulatory approvals, each of which could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries. In addition, lawsuits have occurred or are reasonably expected against emitters of greenhouse gases alleging that these companies are liable for personal injuries and property damage caused by climate change. These lawsuits may seek injunctive relief, monetary compensation, and punitive damages.

In March 2019, Entergy voluntarily set a climate goal to achieve a 50 percent reduction in its carbon emission rate from the year 2000 by 2030. In September 2020, Entergy voluntarily committed to achieving net zero carbon emissions by 2050. In November 2022, Entergy voluntarily set a climate goal to achieve 50 percent carbon-free energy capacity by 2030. Risks to achieving the 2030 and 2050 goals include, among other things, the ability to execute on renewable resource plans, regulatory approvals, customer demand for carbon-free energy that exceeds Entergy’s or its Utility operating companies’ ability to add lower carbon or carbon-free capacity, load growth, potential tariffs, carbon policy and regulation at the federal or state level, including mandates related to reliability standards, and supply chain costs and constraints. Technology research and development, innovation, and advancements in carbon-free generation are also critical to Entergy’s ability to achieve its 2050 commitment. Entergy cannot predict the ultimate impact of achieving these objectives, or the various implementation aspects, on its system reliability, or its results of operations, financial condition, or liquidity.

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The physical effects of climate change could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries.

Potential physical risks from climate change include an increase in sea level, wind and storm surge damages, more frequent or intense hurricanes and wildfires, wetland and barrier island erosion, flooding and changes in weather conditions (such as increases in precipitation, drought, or changes in average temperatures), and potential increased impacts of extreme weather conditions or storms. Entergy’s subsidiaries own assets in, and serve, communities that are at risk from sea level rise, changes in weather conditions, storms, floods, and loss of the protection offered by coastal wetlands. A significant portion of the nation’s oil and gas infrastructure is located in these areas and susceptible to storm damage that could be aggravated by the physical impacts of climate change, which could give rise to fuel supply interruptions and price spikes. Entergy and its subsidiaries also face the risk that climate change could impact the availability and quality of water supplies necessary for operations.

Due in part to the recent increase in frequency and intensity of major storm activity along the Gulf Coast, Entergy is pursuing plans to accelerate investments that would enhance the resilience of the electric systems of the Utility operating companies to enable them to better withstand major storms or other significant weather events, to mitigate the cost of restoration of the electric system after major storms or other significant events, to enable more rapid restoration of electricity after major storm or other significant adverse events, and to deliver electricity to critical customers more immediately after such events. These plans are generally subject to approval by the Utility operating companies’ retail regulators and may not be approved in full or at all. The need for this investment and these expenditures could give rise to liquidity, capital or other financing-related risks as well as result in upward pressure on the retail rates of the Utility operating companies, which, particularly when combined with upward pressure resulting from the recovery of the costs of recent and future storms, may result in adverse actions by the Utility operating companies’ retail regulators or effectively limit the ability to make other planned capital or other investments.

Additionally, prolonged drought conditions and shifting weather patterns resulting from climate change as well as, among other things, buildup of dry vegetation in areas severely impacted by drought may increase the risk of severe wildfire events within the Utility operating companies’ service areas. Catastrophic wildfires occurring in the Utility operating companies’ service areas could give rise to large damage claims against Entergy or its subsidiaries for fire-related losses alleged to be the result of utility practices and/or the failure of electric and other utility equipment and could also cause Entergy or its subsidiaries to suffer reputational harm or face a more challenging operating, political and regulatory environment.

These and other physical changes could result in, among other things, changes in customer demand, increased costs associated with repairing and maintaining generation facilities and transmission and distribution systems resulting in increased maintenance and capital costs (and potential increased financing needs), limits on the Entergy system’s ability to meet peak customer demand, more frequent and longer lasting outages, increased regulatory oversight, criticism or adverse publicity, and lower customer satisfaction. Also, to the extent that climate change adversely impacts the economic health of a region or results in energy conservation or demand side management programs, it may adversely impact customer demand and revenues. Such physical or operational risks could have a material effect on Entergy’s and its subsidiaries’ financial condition, results of operations, and liquidity.

A decline in the continued and future availability and quality of water for cooling, process, and sanitary uses could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries.

Water is a vital natural resource that is also critical to Entergy and its subsidiaries. Entergy’s and its subsidiaries’ facilities use water for cooling, boiler make-up, sanitary uses, potable supply, and many other uses. Entergy’s Utility operating companies also own and/or operate hydroelectric facilities. Accordingly, water

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availability and quality are critical to Entergy’s and its subsidiaries’ business operations. Impacts to water availability or quality could negatively impact both operations and revenues.

Entergy and its subsidiaries secure water through various mechanisms (ground water wells, surface waters intakes, municipal supply, etc.) and operate under the provisions and conditions set forth by the provider and/or regulatory authorities. Entergy and its subsidiaries also obtain and operate in substantial compliance with water discharge permits issued under various provisions of the Clean Water Act and/or state water pollution control provisions. Regulations and authorizations for both water intake and use and for waste discharge can become more stringent in times of water shortages, low flows in rivers, low lake levels, low groundwater aquifer volumes, and similar conditions. The increased use of water by industry, agriculture, and the population at large, population growth, saltwater intrusion, and the potential impacts of climate change on the availability of water resources may cause water use restrictions that affect Entergy and its subsidiaries.

The Utility operating companies, System Energy, and Entergy’s non-utility operations may incur substantial costs related to reliability standards.

Entergy’s business is subject to extensive and mandatory reliability standards. Such standards, which are established by the NERC, the SERC, and other regional enforcement entities, are approved by the FERC and frequently are reviewed, amended, and supplemented. Failure to comply with such standards could result in the imposition of fines or civil penalties, and potential exposure to third party claims for alleged violations of such standards. The standards, as well as the laws and regulations that govern them, are subject to judicial interpretation and to the enforcement discretion vested in the implementing agencies. In addition to exposure to civil penalties and fines, the Utility operating companies have incurred and expect to incur significant costs related to compliance with new and existing reliability standards, including costs associated with the Utility operating companies’ transmission system and generation assets. In addition, the retail regulators of the Utility operating companies possess the jurisdiction, and in some cases have exercised such jurisdiction, to impose standards governing the reliable operation of the Utility operating companies’ distribution systems, including penalties if these standards are not met. The changes to the reliability standards applicable to the electric power industry are ongoing, and Entergy cannot predict the ultimate effect that the reliability standards will have on its Utility and Entergy’s non-utility operations.

Entergy and its subsidiaries may not be adequately hedged against changes in commodity prices, which could materially affect Entergy’s and its subsidiaries’ results of operations, financial condition, and liquidity.

To manage near-term and medium-term financial exposure related to commodity price fluctuations, Entergy and its subsidiaries, including the Utility operating companies, may enter into contracts to hedge portions of their purchase and sale commitments, fuel requirements, and inventories of natural gas, uranium and its conversion and enrichment, coal, refined products, and other commodities, within established risk management guidelines. As part of this strategy, Entergy and its subsidiaries may utilize fixed- and variable-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. However, Entergy and its subsidiaries normally cover only a portion of the exposure of their assets and positions to market price volatility, and the coverage will vary over time. In addition, Entergy also elects to leave certain volumes during certain years unhedged. To the extent Entergy and its subsidiaries have unhedged positions, fluctuating commodity prices can materially affect Entergy’s and its subsidiaries’ results of operations and financial position.

Although Entergy and its subsidiaries devote a considerable effort to these risk management strategies, they cannot eliminate all the risks associated with these activities. As a result of these and other factors, Entergy and its subsidiaries cannot predict with precision the impact that risk management decisions may have on their business, results of operations, or financial position.

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Entergy’s over-the-counter financial derivatives are subject to rules implementing the Dodd-Frank Wall Street Reform and Consumer Protection Act that are designed to promote transparency, mitigate systemic risk, and protect against market abuse. Entergy cannot predict the impact any proposed or not fully-implemented final rules will have on its ability to hedge its commodity price risk or on over-the-counter derivatives markets as a whole, but such rules and regulations could have a material effect on Entergy's risk exposure, as well as reduce market liquidity and further increase the cost of hedging activities.

Entergy has guaranteed or indemnified the performance of a portion of the obligations relating to hedging and risk management activities. Reductions in Entergy’s or its subsidiaries’ credit quality or changes in the market prices of energy commodities could increase the cash or letter of credit collateral required to be posted in connection with hedging and risk management activities, which could materially affect Entergy’s or its subsidiaries’ liquidity and financial position.

The Utility operating companies and Entergy’s non-utility business are exposed to the risk that counterparties may not meet their obligations, which may materially affect the Utility operating companies and Entergy’s non-utility business.

The hedging and risk management practices of the Utility operating companies and Entergy's non-utility business are exposed to the risk that counterparties that owe Entergy and its subsidiaries money, energy, or other commodities will not perform their obligations. Currently, some hedging agreements contain provisions that require the counterparties to provide credit support to secure all or part of their obligations to Entergy or its subsidiaries. If the counterparties to these arrangements fail to perform, Entergy or its subsidiaries may enforce and recover the proceeds from the credit support provided and acquire alternative hedging arrangements, which credit support may not always be adequate to cover the related obligations. In such event, Entergy and its subsidiaries might incur losses in addition to amounts, if any, already paid to the counterparties. In addition, the credit commitments of Entergy’s lenders under its bank facilities may not be honored for a variety of reasons, including unexpected periods of financial distress affecting such lenders, which could materially affect the adequacy of its liquidity sources.

Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding and result in increased benefit plan costs.

The performance of the capital markets affects the values of the assets held in trust under Entergy’s pension and postretirement benefits plans. A decline in the market value of the assets may increase the funding requirements relating to Entergy’s benefit plan liabilities and also result in higher benefit costs. As the value of the assets decreases, the “expected return on assets” component of benefit costs decreases, resulting in higher benefits costs. Additionally, asset losses are incorporated into benefit costs over time, thus increasing benefits costs. Volatility in the capital markets has affected the market value of these assets, which has affected and may affect Entergy’s planned levels of contributions in the future. Additionally, changes in interest rates affect the liabilities under Entergy’s pension and postretirement benefits plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding and recognition of higher liability carrying costs. The funding requirements of the obligations related to the pension benefit plans can also increase as a result of changes in, among other factors, retirement rates, life expectancy assumptions, or federal regulations. For further information regarding Entergy’s pension and other postretirement benefits plans, refer to the “Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits” section of Management’s Financial Discussion and Analysis for Entergy and each of its Registrant Subsidiaries and Note 11 to the financial statements.

The litigation environment in the states in which the Registrant Subsidiaries operate poses a significant risk to those businesses.

Entergy and its subsidiaries and related entities are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, asbestos, hazardous material and customer matters, and injuries and damages issues, among other matters. The states in which Entergy and the Registrant Subsidiaries operate have

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proven to be unusually litigious environments. Judges and juries in these states have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. Entergy and its subsidiaries use legal and appropriate means to contest litigation threatened or filed against them, but the litigation environment in these states poses a significant business risk.

Terrorist attacks and sabotage, physical attacks, cyber attacks, system failures, data breaches or other disruptions of Entergy’s and its subsidiaries’ or their suppliers’ infrastructure or technology systems, including disruptions affecting other third parties ultimately connected to Entergy and its subsidiaries or their suppliers through the transmission grid, may adversely affect Entergy’s business and results of operations.

As an operator of critical infrastructure, Entergy and its subsidiaries face a heightened risk of physical attacks or acts or threats of terrorism, cyber attacks, including ransomware attacks, and data breaches, whether as a direct or indirect act against one of Entergy’s generation, transmission or distribution facilities, operations centers, infrastructure, or information technology systems used to manage, monitor, and transport power to customers and perform day-to-day business functions as well as against the systems of critical suppliers and contractors or other third parties interconnected through the grid. Like many businesses and operators of critical infrastructure, Entergy and its subsidiaries and their third-party suppliers have in the past and, will in the future, continue to be subject to cyber attacks, cybersecurity threats and attempts to compromise and penetrate the information technology systems of Entergy and its subsidiaries and disrupt their operations.

Entergy and its subsidiaries operate in a business that requires evolving information technology systems that include sophisticated data collection, processing systems, software, network infrastructure, and other technologies that are becoming more complex and may be subject to mandatory and prescriptive reliability and security standards. The functionality of Entergy’s technology systems depends on its own and its suppliers’ and their contractors’ technology. Suppliers’ and their contractors’ technology systems to which Entergy is connected directly or indirectly support a variety of business processes and activities to store sensitive data, including (i) intellectual property, (ii) proprietary business information, (iii) personally identifiable information of customers, employees, and others, and (iv) data with respect to invoicing and the collection of payments, accounting, procurement, and supply-chain activities. Any significant failure or malfunction of such information technology systems could result in loss of or inappropriate access to data or disruptions of operations.

There have been attacks and threats of attacks on energy infrastructure by cyber actors, including those associated with foreign governments. Further, attacks may become more frequent in the future as technology becomes more prevalent in energy infrastructure. An attack could affect Entergy’s or its subsidiaries’ ability to operate, including its ability to operate the information technology systems and network infrastructure on which it relies to conduct business.

Given the rapid technological advancements of existing and emerging threats, including threats fueled by artificial intelligence, Entergy’s technology systems remain inherently vulnerable despite implementations and enhancements of the multiple layers of security and controls. In addition, the prevalent use of smartphones, tablets, and other wireless devices, as well as ongoing remote or hybrid work-from-home arrangement for a significant portion of Entergy’s employees and those of its contractors and vendors may also heighten these risks. If Entergy’s or its subsidiaries’ technology systems, or those of critical suppliers or contractors or other third parties interconnected through the grid, were compromised and unable to detect or recover in a timely fashion to a normal state of operations, Entergy or its subsidiaries could be unable to perform critical business functions that are essential to the company’s well-being and could result in a loss of or inappropriate access to its confidential, sensitive, and proprietary information, including personal information of its customers, employees, suppliers, and others in Entergy’s care. We cannot anticipate, detect, or implement fully preventive measures against all cybersecurity threats.

Any such attacks, failures, or data breaches could have a material effect on Entergy’s and the Registrant Subsidiaries’ business, financial condition, results of operations or reputation. Although Entergy and the Registrant

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Subsidiaries purchase insurance for cyber attacks and data breaches, such insurance prices have increased substantially, and coverage may not be adequate to cover all losses that might arise in connection with these incidents. Such incidents may also expose Entergy to an increased risk of litigation (and associated damages and fines). For information on our cybersecurity risk management, strategy, and governance, see “Item 1C. Cybersecurity” in Part I, Item 1C.

Entergy and the Registrant Subsidiaries are subject to risks associated with their ability to obtain adequate insurance at acceptable costs.

The global economic cost to insurers resulting from cyber attacks, natural disasters, and other catastrophic events, in addition to an increased focus on climate issues, could have disruptive effects on insurance markets. The availability of insurance capacity may decrease, and the insurance policies that Entergy or the Registrant Subsidiaries are able to obtain may have higher deductibles, higher premiums, and more restrictive terms and conditions. Further, the insurance policies of Entergy or the Registrant Subsidiaries may not cover all of their potential exposures or actual amounts of losses incurred.

Significant increases in commodity prices, other materials and supplies, and operation and maintenance expenses may adversely affect Entergy's results of operations, financial condition, and liquidity.

Entergy and its subsidiaries have observed and expect continued inflationary pressures related to commodity prices, other materials and supplies, and operation and maintenance expenses, including in the areas of labor, health care, and pension costs. The contracts for the construction of certain of the Utility operating companies’ generation facilities also have included, and in the future may include, price adjustment provisions that, subject to certain limitations, may enable the contractor to increase the contract price to reflect increases in certain costs of constructing the facility. These inflationary pressures could impact the ability of Entergy and its subsidiaries to control costs and/or make substantial investments in their businesses, including their ability to recover costs and investments, and to earn their allowed return on equity within frameworks established by their regulators while maintaining affordability of their services for their customers, in addition to having unpredictable effects on Entergy’s customers. Increases in commodity prices, other materials and supplies, and operation and maintenance expenses, including increasing labor costs and costs and funding requirements associated with Entergy's defined benefit retirement plans, health care plans, and other employee benefits, could increase their financing needs and otherwise adversely affect their results of operations, financial condition, and liquidity.

(Entergy New Orleans)

The effect of higher purchased gas cost charges to customers taking gas service may adversely affect Entergy New Orleans’s results of operations and liquidity.

Gas rates charged to retail gas customers are comprised primarily of purchased gas cost charges, which provide no return or profit to Entergy New Orleans, and distribution charges, which provide a return or profit to the utility. Distribution charges recover fixed costs on a volumetric basis and, thus, are affected by the amount of gas sold to customers. When purchased gas cost charges increase due to higher gas procurement costs, customer usage may decrease, especially in weaker economic times, resulting in lower distribution charges for Entergy New Orleans, which, given its relatively smaller size, could adversely affect results of operations. Purchased gas cost charges, which comprise most of a customer’s bill and may be adjusted monthly, represent gas commodity costs that Entergy New Orleans recovers from its customers. Entergy New Orleans’s cash flows can be affected by differences between the time when gas is purchased and the time when ultimate recovery from customers occurs.

(Entergy Corporation and System Energy)

System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on sales to affiliated companies for all of its revenues. Certain contractual arrangements relating to

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System Energy, the affiliated companies, and these revenues are the subject of ongoing litigation and regulatory proceedings. The aggregate amount of refunds claimed in these proceedings, after reduction for settlements reached with the MPSC and the APSC (subject in the latter case to approval by the FERC), exceeds the current net book value of System Energy. In the event of an adverse decision in one or more of these proceedings requiring the payment of substantial additional refunds, System Energy would be required to seek financing to pay such refunds which financing may not be available on terms acceptable to System Energy when required.

System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf. Charges under the Unit Power Sales Agreement are paid by the Utility operating companies (other than Entergy Texas) as consideration for their respective entitlements to receive capacity and energy. The useful economic life of Grand Gulf is finite and is limited by the terms of its operating license, which currently expires in November 2044. System Energy’s financial condition depends both on the receipt of payments from the Utility operating companies (other than Entergy Texas) under the Unit Power Sales Agreement and on the continued commercial operation of Grand Gulf. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC (or on appeal from the FERC to the United States Court of Appeals for the Fifth Circuit), including challenges with respect to System Energy’s authorized return on equity and capital structure, renewal of its sale-leaseback arrangement, treatment of uncertain tax positions, a broader investigation of rates under the Unit Power Sales Agreement, and two prudence complaints, one challenging the extended power uprate completed at Grand Gulf in 2012 and the operation and management of Grand Gulf, particularly in the 2016-2020 time period, and the second challenging the operation and management of Grand Gulf in the 2021-2022 time period.

The claims in these proceedings include claims for refunds and claims for rate adjustments. The aggregate amount of refunds claimed in these proceedings, after reduction for settlements reached with the MPSC and the APSC (subject in the latter case to approval by the FERC), exceeds the current net book value of System Energy. Entergy Corporation is not obligated to provide funding to System Energy to enable it to pay any such refunds. In the event that an adverse decision in one or more of these proceedings required the payment of substantial additional refunds, System Energy would need to source additional financing to pay such refunds. Such financing may not be available on terms acceptable to System Energy when required. System Energy and its debt securities have been subject to downgrade by rating agencies in the past, most recently in May 2023. Any further downgrade by one or more rating agencies could adversely affect the market prices of System Energy’s debt securities and otherwise adversely affect System Energy’s financial condition.

In addition, an order requiring System Energy to pay substantial additional refunds could result in a default and, in certain cases, acceleration under one or more of System Energy’s existing bond indentures, credit agreements, or other financing arrangements. Certain events constituting events of default under System Energy’s financing agreements may also result in defaults under, or acceleration with respect to, financing arrangements involving certain credit agreement and guarantee obligations of Entergy Corporation.

These proceedings are pending before their respective adjudicators and no final decisions have been reached. Thus, Entergy cannot predict with certainty the outcome of any of these proceedings, or the magnitude of any refunds or rate adjustments, and an adverse outcome in any of them could have a material adverse effect on Entergy’s or System Energy’s results of operations, financial condition, or liquidity. See Note 2 to the financial statements for further discussion of the proceedings. The Utility operating companies (other than Entergy Texas) have agreed to implement certain protocols for providing retail regulators with information regarding rates billed under the Unit Power Sales Agreement.

For information regarding the Unit Power Sales Agreement, the sale and leaseback transactions and certain other agreements relating to certain Entergy System companies’ support of System Energy, see Notes 5 and 8 to the financial statements and the “Utility - System Energy and Related Agreements” section of Part I, Item 1.

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(Entergy Corporation)

Entergy’s non-utility operations are subject to substantial governmental regulation and may be adversely affected by legislative, regulatory, or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.

Entergy’s non-utility operations are subject to regulation under federal, state, and local laws. Compliance with the requirements under these various regulatory regimes may cause Entergy’s non-utility operations to incur significant additional costs, and failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of liens, fines, and/or civil or criminal liability.

Public utilities under the Federal Power Act are required to obtain FERC acceptance of their rate schedules for wholesale sales of electricity. Entergy’s non-utility operations include legal entities that meet the definition of a “public utility” under the Federal Power Act by virtue of making wholesale sales of electric energy and/or owning wholesale electric transmission facilities. The FERC has granted those entities the authority to sell electricity at market-based rates. The FERC’s orders that grant those entities market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that those entities can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, market-based sales are subject to certain market behavior rules, and if one of those entities were deemed to have violated one of those rules, they would be subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority and potential penalties of up to $1.496 million per day per violation. If one of those entities were to lose their market-based rate authority, it would be required to obtain the FERC’s acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have an adverse effect on the rates those entities charge for power from its facilities.

Entergy’s non-utility operations are also affected by legislative and regulatory changes, as well as by changes to market design, market rules, tariffs, cost allocations, and bidding rules imposed by the existing Independent System Operator. The Independent System Operator that oversees the relevant wholesale power market has imposed, and in the future may continue to impose, mitigation, including price limitations, offer caps and other mechanisms, to address some of the volatility and the potential exercise of market power in that market. These types of price limitations and other regulatory mechanisms may have an adverse effect on the profitability of Entergy’s non-utility operations’ generation facilities that sell energy and capacity into the wholesale power markets.

The regulatory environment applicable to the electric power industry is subject to changes as a result of restructuring initiatives at both the state and federal levels. Entergy cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on Entergy’s non-utility operations. In addition, in some of these markets, interested parties have proposed material market design changes, including the elimination of a single clearing price mechanism, have raised claims that the competitive marketplace is not working, and have made proposals to re-regulate the markets, impose a generation tax, or require divestitures by generating companies to reduce their market share. Other proposals to re-regulate may be made and legislative or other attention to the electric power market restructuring process may delay or reverse the deregulation process, which could require material changes to business planning models. If competitive restructuring of the electric power markets is reversed, modified, discontinued, or delayed, Entergy’s non-utility operations’ results of operations, financial condition, and liquidity could be materially affected.

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As a holding company, Entergy Corporation depends on cash distributions from its subsidiaries to meet its debt service and other financial obligations and to pay dividends on its common stock, and has provided, and may continue to provide, capital contributions or debt financing to its subsidiaries, which would reduce the funds available to meet its other financial obligations.

Entergy Corporation is a holding company with no material revenue generating operations of its own or material assets other than the stock of its subsidiaries. Accordingly, all of its operations are conducted by its subsidiaries. Entergy Corporation has provided, and may continue to provide, capital contributions or debt financing to its subsidiaries, which would reduce the funds available to meet its financial obligations, including making interest and principal payments on outstanding indebtedness, and to pay dividends on Entergy’s common stock. Entergy Corporation’s ability to satisfy its financial obligations, including the payment of interest and principal on its outstanding debt, and to pay dividends on its common stock depends on the payment to it of dividends or distributions by its subsidiaries. The subsidiaries of Entergy Corporation are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any dividends or make distributions to Entergy Corporation. The ability of such subsidiaries to make payments of dividends or distributions to Entergy Corporation depends on their results of operations and cash flows and other items affecting retained earnings, and on any applicable legal, regulatory, or contractual limitations on subsidiaries’ ability to pay such dividends or distributions. Prior to providing funds to Entergy Corporation, such subsidiaries have financial and regulatory obligations that must be satisfied, including among others, debt service and, in the case of Entergy Utility Holding Company, LLC and Entergy Texas, dividends and distributions on preferred securities. Any distributions from the Registrant Subsidiaries other than Entergy Texas and System Energy are paid directly to Entergy Utility Holding Company, LLC and are therefore subject to prior payment of distributions on its preferred securities.

The hazardous activities associated with power generation could adversely impact our results of operations and financial condition.

Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. In addition to natural risks, such as earthquakes, floods, lightning, hurricanes and wind, hazards, such as fire, explosion, collapse, and machinery failure, are inherent risks in our operations which may occur as a result of inadequate internal processes, technological flaws, human error, or actions of third parties or other external events. The control and management of these risks depend upon adequate development and training of personnel and on operational procedures, preventative maintenance plans, and specific programs supported by quality control systems, which may not prevent the occurrence and impact of these risks.

The hazards described above, along with other safety hazards associated with our operations, can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in our being named as a defendant in lawsuits asserting claims for substantial damages, environmental cleanup costs, personal injury, and fines and/or penalties and may adversely affect our reputation.

Item 1B. Unresolved Staff Comments

None.

Item 1C. Cybersecurity

Risk Management and Strategy

Entergy and the Registrant Subsidiaries maintain a security-risk-management system with defined roles, duties, governance, and accountability. Under this physical- and cyber-risk model, Entergy and the Registrant Subsidiaries streamline security into a centralized program. The Chief Security Officer (CSO) is responsible for

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establishing the security and reliability risk strategy, setting policies, monitoring controls and compliance, providing support activities, and reporting on the security program. The Chief Information Security Officer (CISO) is responsible for establishing the cybersecurity strategy and implementing physical and cyber security systems for the security program. The Chief Ethics & Compliance Officer works with the CSO to address requirements of external security-related regulations, and where applicable, incorporate them into business policies. Management is responsible for identifying and managing risk directly through execution of the security program and compliance with security policies. Entergy and the Registrant Subsidiaries’ risk management model addresses compliance with certain regulatory constructs, such as the NERC Reliability Standards, the NRC Code of Federal Regulations, the Payment Card Industry Data Security Standard, and the Health Insurance Portability and Accountability Act, among other regulations. Entergy and the Registrant Subsidiaries’ risk management model continuously evolves to improve and implement protections, controls, and monitoring to mitigate risks to their part of North America’s electric grid, to protect sensitive information, and to maintain secure business operations. Entergy and the Registrant Subsidiaries manage cybersecurity threats as an enterprise risk with close coordination and information sharing with its federal, state, and local partners. Entergy and the Registrant Subsidiaries also engage with local, state, and federal law enforcement agencies on initiatives to share threat information and participate in a wide range of industry collaborations and classified briefings on cybersecurity developments and evolving risks.

Entergy and the Registrant Subsidiaries maintain access-management controls, including a layered multi-factor authentication process for network and system access, and a defense-in-depth security ecosystem that includes advanced threat detection from independent third parties and federal agencies, security logging and monitoring, and independent third-party penetration and vulnerability assessments. Relevant employees and contractors must complete cybersecurity trainings periodically to heighten security and threat awareness, promote best practices, and meet regulatory requirements. Additional multi-layered prevention and detection processes and technologies to mitigate and minimize the effects of cybersecurity risks include email security, continuous monitoring, vulnerability scanning, anti-virus and anti-malware software, backups and recovery strategy, network segregation, third-party security, and information protection.

Entergy and the Registrant Subsidiaries have incorporated certain cyber-specific response protocols and procedures into their Entergy Incident Management System framework for responding to emergency incidents. This includes the Entergy Incident Response Team Plan, which outlines Entergy’s procedures, steps, and responsibilities for preparing for, detecting, containing, and recovering from an incident. The plan details the roles and responsibilities of Entergy’s officers who would be engaged in such a response to an emergency incident, including key questions to be addressed, critical decision points, and sources of key information to support decision-making. Senior management and the Emergency Incident Response Team periodically review and drill on the plan.

As cybersecurity risks continue to evolve with multiple threat vectors, Entergy and the Registrant Subsidiaries maintain a comprehensive security strategy to keep current with the changing threats. To inform this effort, Entergy and the Registrant Subsidiaries utilize the National Institute of Standards and Technology Cybersecurity Framework, which consists of standards, guidelines, and best practices to manage cybersecurity risk across the enterprise. A risk-based approach is used to direct security initiatives to the most significant risks and provide the most value in terms of risk reduction and protection. Entergy and the Registrant Subsidiaries use a vendor risk management program to assess and monitor security risks that arise from third-party vendors. In addition, Entergy and the Registrant Subsidiaries utilize technology and threat intelligence services to assess and continuously monitor the cybersecurity risk of key vendors, as identified through the vendor risk management program.

While Entergy and the Registrant Subsidiaries have experienced cybersecurity incidents, except as otherwise summarized above or discussed elsewhere in this report, the risks from cybersecurity threats, including as a result of any previous cybersecurity incidents, have not materially affected them including their business strategy, results of operations, or financial condition. See “Item 1A. Risk Factors” in Part I, Item 1A for a detailed description of the risks related to cybersecurity.

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Corporate Governance

The Board of Directors is responsible for oversight of the identification, management, and mitigation of enterprise-wide risk, including cybersecurity risk. The Audit Committee has the primary responsibility for overseeing risk management, including oversight of cybersecurity risk management practices and performance. The Audit Committee generally receives reports at each regular quarterly meeting provided by the Chief Information Officer, the CSO, the CISO, and the General Auditor on the cybersecurity management program. The reports focus on the programs and protocols in place to mitigate cybersecurity risks, led by the CSO. Among other things, the reports may include: recent cyber risk and cybersecurity developments; industry engagement activities; legislative and regulatory developments; cyber-risk governance and oversight; selected cyber risk metrics and activities; cyber risk incident response plans and strategies; cybersecurity drills and exercises; assessments by third party experts and Internal Audit; and major projects and initiatives.

While the Board of Directors and Audit Committee oversee cybersecurity risk management, Entergy’s management is responsible for managing cybersecurity risk. Entergy and the Registrant Subsidiaries’ security-risk-management system, as discussed above, is comprised of a three lines of defense model to enhance risk management efforts and define roles in the security program. The first line of defense, comprised of business units performing operational functions, including the CISO, is responsible for identification and management of security and reliability risks directly through design, implementation, and execution of control activities. The second line of defense, comprised of the CSO and Chief Security Office, performs and supports security and reliability risk management and governs and oversees the execution of security and reliability controls by the first line of defense. Ownership of specific security operations may migrate from a business unit in the first line of defense to the second line of defense, as determined to be appropriate by the Chief Security Office. The third line of defense, which includes Internal Audit, independent third parties, and certain regulatory constructs, such as the NERC Reliability Standards and the NRC Cyber Rule, provides assurance of selective actions taken by the first and second lines of defense to senior management and the Board of Directors.

Entergy’s CSO is responsible for overseeing physical, cyber, and reliability risk, including governance, compliance, and threat intelligence. The CSO’s background includes serving as the Global Lead Business Information Security Officer for a multinational pharmaceutical and biotechnology company, Vice President of Cybersecurity Solutions for an international consulting firm, and an operations manager for a multinational technology company. The CSO is also a former intelligence officer in the U.S. Marine Corps, with experience in the Fleet Marine Force, Joint Staff J-2/Defense Intelligence Agency, and Headquarters Marine Corps Command, Control, Communications, and Computers (C4I). The CSO participated in numerous exercises and crisis operations during his time in the military. The CSO is a certified Information Security Manager from the Information Systems Audit and Control Association and a certified Information Privacy Manager from the International Association of Privacy Professionals. The CSO also completed the Harvard Kennedy School Executive Education Program in Cybersecurity and the FBI Domestic Security Executive Academy.

Entergy’s CISO is responsible for enterprise strategic and operational cybersecurity, physical security systems, and regulatory compliance. The CISO oversees investments in tools, resources, and processes that allow for the continuous improvement and maturity of Entergy’s cybersecurity posture. The CISO has expertise spanning more than 25 years in the realm of information technology, information security, and cyber/physical security management. The CISO’s background includes serving as the Vice President and Chief Information Security Officer for an electric utility with responsibility for enterprise cybersecurity covering corporate, electric, nuclear, and gas operations. Additionally, the CISO served as the Chief Security Officer for the Electric Reliability Council of Texas with overall responsibility for its cybersecurity, physical security, and emergency management programs. Her previous experience includes multiple technical, managerial, and strategic roles within industries ranging from energy, telecommunication, software development, and cybersecurity consulting. The CISO is a Certified Information Systems Security Professional, Certified Information Security Manager, and Certified in Risk and Information Systems Control.

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Part I Item 1A, 1B, and 1C

Entergy Corporation, Utility operating companies, and System Energy

In the event of a suspected or actual cybersecurity incident, the Security Incident Response Team (SIRT), which includes the CISO, has primary responsibility for initial identification and evaluation of potential business impacts and escalation of the incident’s severity classification using pre-established criteria with a specified communication matrix and escalation thresholds. The Security Incident Commander, which role is served by rotating leaders in the CISO organization, provides tactical leadership and oversight management at the cross-functional level for the incident. The SIRT remains engaged throughout the incident response lifecycle, including detection and analysis, containment, eradication and recovery, and post-incident remediation, and coordinates with the impacted business functions, if warranted. Once a cyber incident is confirmed, the SIRT is responsible for maintaining situational awareness and continuous monitoring of the need for escalation or de-escalation of the incident’s severity classification. As certain escalation thresholds are exceeded, additional levels of management notification are required by the SIRT, including notification of and recurring communication with Entergy’s Incident Response Team, which includes the Chief Executive Officer, the Chief Operating Officer, the CSO, other executive management, and members of the affected business functions. Depending upon the facts, analysis, materiality, and anticipated or current impacts, the Chief Executive Officer and the General Counsel will determine the timing and cadence for communication of the cyber incident with the Board of Directors or Audit Committee.

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ENTERGY ARKANSAS, LLC AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

2023 Compared to 2022

Net Income

Net income increased $104 million primarily due to a $159.6 million reduction in income tax expense in 2023 as a result of the resolution of the 2016-2018 IRS audit, higher retail electric price, lower other operation and maintenance expenses, and higher other income. The increase was partially offset by write-offs of $78.4 million ($58.8 million net-of-tax) in third quarter 2023 as a result of Entergy Arkansas’s approved motion to forgo recovery related to the 2013 ANO stator incident, higher interest expense, lower volume/weather, and higher depreciation and amortization expenses. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit. See Note 8 to the financial statements for further discussion of the ANO stator incident and the approved motion to forgo recovery.

Operating Revenues

Following is an analysis of the change in operating revenues comparing 2023 to 2022:

Amount

(In Millions)

2022 operating revenues$2,673.2

Fuel, rider, and other revenues that do not significantly affect net income(75.0)

Volume/weather(31.4)

Retail electric price79.6

2023 operating revenues$2,646.4

Entergy Arkansas’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.

The volume/weather variance is primarily due to the effect of less favorable weather on residential sales and a decrease in weather-adjusted residential usage, partially offset by an increase in industrial usage. The increase in industrial usage is primarily due to an increase in demand from small industrial customers and an increase in demand from expansion projects, primarily in the metals industry.

The retail electric price variance is primarily due to an increase in formula rate plan rates effective January 2023. See Note 2 to the financial statements for further discussion of the 2022 formula rate plan filing.

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Entergy Arkansas, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Total electric energy sales for Entergy Arkansas for the years ended December 31, 2023 and 2022 are as follows:

20232022% Change

(GWh)

Residential7,610 8,147 (7)

Commercial5,584 5,615 (1)

Industrial9,095 8,493 7

Governmental192 218 (12)

Total retail 22,481 22,473 —

Sales for resale:

Associated companies2,218 1,906 16

Non-associated companies5,777 6,520 (11)

Total30,476 30,899 (1)

See Note 19 to the financial statements for additional discussion of Entergy Arkansas’s operating revenues.

Other Income Statement Variances

Other operation and maintenance expenses decreased primarily due to:

•a decrease of $17.1 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits service costs as a result of an increase in the discount rates used to value the benefits liabilities, lower health and welfare costs, including higher prescription drug rebates in second quarter 2023, and a revision to estimated incentive compensation expense in first quarter 2023. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs;

•a decrease of $10.5 million in transmission costs allocated by MISO;

•the effects of recording a final judgment in first quarter 2023 to resolve claims in the ANO damages case against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $10.3 million of spent nuclear fuel storage costs previously recorded as other operation and maintenance expenses. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and

•a decrease of $9.6 million in non-nuclear generation expenses primarily due to a lower scope of work, including during plant outages, performed in 2023 as compared to 2022.

The decrease was partially offset by:

•an increase of $10.4 million in contract costs related to operational performance, customer service, and organizational health initiatives;

•an increase of $9.2 million in insurance expenses primarily due to lower nuclear insurance refunds received in 2023;

•an increase of $5.2 million in nuclear generation expenses primarily due to a higher scope of work performed in 2023 as compared to 2022 and higher nuclear labor costs; and

•several individually insignificant items.

Asset write-offs includes the effects of Entergy Arkansas forgoing recovery of identified costs resulting from the 2013 ANO stator incident. In third quarter 2023, Entergy Arkansas recorded write-offs of its regulatory asset for deferred fuel of $68.9 million and the undepreciated balance of $9.5 million in capital costs related to the

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Management’s Financial Discussion and Analysis

ANO stator incident. See Note 8 to the financial statements for further discussion of the ANO stator incident and the approved motion to forgo recovery.

Depreciation and amortization expenses increased primarily due to additions to plant in service.

Entergy Arkansas records a regulatory charge or credit for the difference between asset retirement obligation-related expenses and nuclear decommissioning trust earnings plus asset retirement obligation-related costs collected in revenue.

Other income increased primarily due to:

•higher interest earned on money pool investments;

•an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2023; and

•a decrease in charitable donations in 2023 as compared to 2022.

Interest expense increased primarily due to the issuance of $425 million of 5.15% Series mortgage bonds in January 2023 and higher interest accrued on spent nuclear fuel disposal costs.

The effective income tax rates were (33.3%) for 2023 and 21.6% for 2022. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates and for additional discussion regarding income taxes.

2022 Compared to 2021

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy Arkansas’s Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 24, 2023, for discussion of results of operations for 2022 compared to 2021.

Income Tax Legislation and Regulation

See the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of income tax legislation and regulation.

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2023, 2022, and 2021 were as follows:

202320222021

(In Thousands)

Cash and cash equivalents at beginning of period$5,278 $12,915 $192,128

Net cash provided by (used in):

Operating activities941,021 699,732 549,216

Investing activities(1,032,952)(852,794)(898,193)

Financing activities90,285 145,425 169,764

Net decrease in cash and cash equivalents(1,646)(7,637)(179,213)

Cash and cash equivalents at end of period$3,632 $5,278 $12,915

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Entergy Arkansas, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

2023 Compared to 2022

Operating Activities

Net cash flow provided by operating activities increased $241.3 million in 2023 primarily due to:

•lower fuel costs and the timing of recovery of fuel and purchased power costs. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery;

•higher collections from customers;

•the refund of $41.7 million received from System Energy in January 2023 related to the sale-leaseback renewal costs and depreciation litigation as calculated in System Energy’s January 2023 compliance report filed with the FERC. The refund was subsequently applied to the under-recovered deferred fuel balance. See Note 2 to the financial statements for further discussion of the refund and the related proceedings;

•a decrease of $38.5 million in pension contributions in 2023. See “Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding; and

•$23.2 million in proceeds received from the DOE in April 2023 resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.

The increase was partially offset by:

•the timing of payments to vendors;

•an increase of $25.4 million in storm spending in 2023 as compared to 2022; and

•an increase of $22.1 million in interest paid.

Investing Activities

Net cash flow used in investing activities increased $180.2 million in 2023 primarily due to:

•an increase of $122.9 million in distribution construction expenditures primarily due to higher capital expenditures for storm restoration in 2023;

•an increase of $86.6 million in transmission construction expenditures primarily due to increased investment in the reliability and infrastructure of Entergy Arkansas’s transmission system; and

•an increase of $43.2 million as a result of fluctuations in nuclear fuel activity due to variations from year to year in the timing and pricing of fuel reload requirements, materials and services deliveries, and the timing of cash payments during the nuclear fuel cycle.

The increase was partially offset by:

•a decrease of $38.3 million in nuclear construction expenditures primarily due to decreased spending on various nuclear projects in 2023;

•$17.9 million in proceeds received from the DOE in April 2023 resulting from litigation regarding spent nuclear fuel storage costs that were previously recorded as plant. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and

•a decrease of $14.1 million in information technology capital expenditures primarily due to decreased spending on various technology projects in 2023.

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Entergy Arkansas, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Financing Activities

Net cash flow provided by financing activities decreased $55.1 million in 2023 primarily due to:

•an increase of $331 million in common equity distributions paid in 2023 in order to maintain Entergy Arkansas’s capital structure;

•the repayment, at maturity, of $250 million of 3.05% Series mortgage bonds in June 2023;

•the issuance of $200 million of 4.20% Series mortgage bonds in March 2022;

•the repayment, at maturity, of $40 million of 3.17% Series M notes by the Entergy Arkansas nuclear fuel company variable interest entity in December 2023; and

•money pool activity.

The decrease was partially offset by:

•the issuance of $425 million of 5.15% Series mortgage bonds in January 2023;

•the issuance of $300 million of 5.30% Series mortgage bonds in August 2023;

•net long-term borrowings of $70.2 million in 2023 as compared to net repayments of $4.8 million in 2022 on the nuclear fuel company variable interest entity’s credit facility; and

•an increase of $61.3 million in prepaid deposits related to contributions-in-aid-of-construction primarily for customer and generator interconnection agreements.

Decreases in Entergy Arkansas’s payable to the money pool are a use of cash flow, and Entergy Arkansas’s payable to the money pool decreased $35.4 million in 2023 compared to increasing by $40.9 million in 2022. The money pool is an intercompany cash management program that makes possible intercompany borrowing and lending arrangements, and the money pool and other borrowing arrangements are designed to reduce the Registrant Subsidiaries’ dependence on external short-term borrowings.

See Note 5 to the financial statements for further details of long-term debt.

2022 Compared to 2021

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Arkansas’s Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 24, 2023, for discussion of operating, investing, and financing cash flow activities for 2022 compared to 2021.

Capital Structure

Entergy Arkansas’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio for Entergy Arkansas is primarily due to the net issuance of long-term debt in 2023.

December 31,2023December 31,2022

Debt to capital55.5 %52.5 %

Effect of subtracting cash— %— %

Net debt to net capital (non-GAAP)55.5 %52.5 %

Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. Entergy Arkansas uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition. The net debt to net capital ratio is a non-GAAP measure.

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Entergy Arkansas, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Entergy Arkansas also uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition because net debt indicates Entergy Arkansas’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

Entergy Arkansas seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a distribution, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Arkansas may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reduced distributions, Entergy Arkansas may receive equity contributions to maintain its capital structure.

Uses of Capital

Entergy Arkansas requires capital resources for:

•construction and other capital investments;

•debt maturities or retirements;

•working capital purposes, including the financing of fuel and purchased power costs; and

•distribution and interest payments.

Following are the amounts of Entergy Arkansas’s planned construction and other capital investments.

202420252026

(In Millions)

Planned construction and capital investment:

Generation$1,090 $355 $240

Transmission135 85 80

Distribution415 535 480

Utility Support65 65 65

Total$1,705 $1,040 $865

In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Arkansas includes investments in generation projects to modernize, decarbonize, and diversify Entergy Arkansas’s portfolio, including Walnut Bend Solar, West Memphis Solar, and Driver Solar; investments in ANO 1 and 2; distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to improve reliability and resilience while also supporting renewables expansion; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, government actions, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.

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Entergy Arkansas, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Following are the amounts of Entergy Arkansas’s existing debt and lease obligations (includes estimated interest payments).

2024202520262027-2028 After 2028

(In Millions)

Long-term debt (a)$546 $233 $835 $619 $5,514

Operating leases (b)$17 $16 $14 $15 $5

Finance leases (b)$5 $4 $4 $5 $3

(a)Long-term debt is discussed in Note 5 to the financial statements.

(b)Lease obligations are discussed in Note 10 to the financial statements.

Other Obligations

Entergy Arkansas currently expects to contribute approximately $55.1 million to its qualified pension plans and approximately $529 thousand to its other postretirement health care and life insurance plans in 2024, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024, valuations are completed, which is expected by April 1, 2024. See “Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

Entergy Arkansas has $34.5 million of unrecognized tax benefits net of unused tax attributes plus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

In addition, Entergy Arkansas enters into fuel and purchased power agreements that contain minimum purchase obligations. Entergy Arkansas has rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations. See Note 8 to the financial statements for discussion of Entergy Arkansas’s obligations under the Unit Power Sales Agreement.

As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Arkansas pays distributions from its earnings at a percentage determined monthly.

Renewables

Walnut Bend Solar

In October 2020, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 100 MW Walnut Bend Solar facility is in the public interest. Entergy Arkansas primarily requested cost recovery through the formula rate plan rider. In July 2021 the APSC granted Entergy Arkansas’s petition and approved the acquisition of the resource and cost recovery through the formula rate plan rider. In addition, the APSC directed Entergy Arkansas to file a report within 180 days detailing its efforts to obtain a tax equity partnership. In January 2022, Entergy Arkansas filed its tax equity partnership status report and will file subsequent reports until a tax equity partnership is obtained or a tax equity partnership is no longer sought. The counterparty notified Entergy Arkansas that it was terminating the project, though it was willing to consider an alternative for the site. Entergy Arkansas disputed the right of termination. Negotiations were conducted, including with respect to cost and schedule and to updates arising as a result of the Inflation Reduction Act of 2022. In April 2023, Entergy Arkansas filed an application for an amended certificate of environmental compatibility and public need with the APSC seeking approval by June 2023 for the updates to the cost and schedule that were previously approved by the APSC. In June 2023, Entergy Arkansas, the APSC general staff, and the Arkansas Attorney General filed a unanimous settlement supporting that the approval of the Walnut Bend Solar facility is in the public interest based on the terms

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Entergy Arkansas, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

in the settlement, including the treatment for the production tax credits associated with the facility. In July 2023, after requesting further testimony and purporting to modify several terms in the settlement and upon rehearing, the APSC approved the settlement largely on the terms submitted, including a 30-year amortization period for the production tax credits. In February 2024, Entergy Arkansas made an initial payment of approximately $169.7 million to acquire the facility. The project will achieve commercial operation once testing is completed and the project has achieved substantial completion. Entergy Arkansas currently expects the project to achieve commercial operation in the first half of 2024, at which time a substantial completion payment of approximately $20 million is expected.

West Memphis Solar

In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 180 MW West Memphis Solar facility is in the public interest. In October 2021 the APSC granted Entergy Arkansas’s petition and approved the acquisition of the West Memphis Solar facility and cost recovery through the formula rate plan rider. In addition, the APSC directed Entergy Arkansas to file a report within 180 days detailing its efforts to obtain a tax equity partnership. In April 2022, Entergy Arkansas filed its tax equity partnership status report and will file subsequent reports until a tax equity partnership is obtained or a tax equity partnership is no longer sought. In March 2022 the counterparty notified Entergy Arkansas that it was seeking changes to certain terms of the build-own-transfer agreement, including both cost and schedule. In January 2023, Entergy Arkansas filed a supplemental application with the APSC seeking approval for a change in the transmission route and updates to the cost and schedule that were previously approved by the APSC. In March 2023 the APSC approved Entergy Arkansas’s supplemental application. The project is currently expected to achieve commercial operation by the end of 2024.

Driver Solar

In April 2022, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 250 MW Driver Solar facility is in the public interest and requested cost recovery through the formula rate plan rider. The APSC established a procedural schedule with a hearing scheduled in June 2022, but the parties later agreed to waive the hearing and submit the matter to the APSC for a decision consistent with the filed record. In August 2022 the APSC granted Entergy Arkansas’s petition and approved the acquisition of Driver Solar and cost recovery through the formula rate plan rider. In addition, the APSC directed Entergy Arkansas to inform the APSC as to the status of a tax equity partnership once construction is commenced. The parties are evaluating the effects of certain matters related to the Inflation Reduction Act of 2022, including the viability of a tax equity partnership. The project is expected to achieve commercial operation as early as mid-2024.

Sources of Capital

Entergy Arkansas’s sources to meet its capital requirements include:

•internally generated funds;

•cash on hand;

•the Entergy system money pool;

•debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;

•capital contributions; and

•bank financing under new or existing facilities.

Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations,

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Entergy Arkansas, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Entergy Arkansas expects to continue, when economically feasible, to retire higher-cost debt and replace it with lower-cost debt if market conditions permit.

All debt and common and preferred membership interest issuances by Entergy Arkansas require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in Entergy Arkansas’s bond indenture and other agreements. Entergy Arkansas has sufficient capacity under these tests to meet its foreseeable capital needs for the next twelve months and beyond.

Entergy Arkansas’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.

2023202220212020

(In Thousands)

($145,385)($180,795)($139,904)$3,110

See Note 4 to the financial statements for a description of the money pool.

Entergy Arkansas has a credit facility in the amount of $150 million scheduled to expire in June 2028. Entergy Arkansas also has a $25 million credit facility scheduled to expire in April 2024. The $150 million credit facility includes fronting commitments for the issuance of letters of credit against $5 million of the borrowing capacity of the facility. As of December 31, 2023, there were no cash borrowings and no letters of credit outstanding under the credit facilities. In addition, Entergy Arkansas is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2023, $5.8 million in letters of credit were outstanding under Entergy Arkansas’s uncommitted letter of credit facility. See Note 4 to the financial statements for further discussion of the credit facilities.

The Entergy Arkansas nuclear fuel company variable interest entity has a credit facility in the amount of $80 million scheduled to expire in June 2025. As of December 31, 2023, $70.2 million in loans were outstanding under the credit facility for the Entergy Arkansas nuclear fuel company variable interest entity. See Note 4 to the financial statements for further discussion of the nuclear fuel company variable interest entity credit facility.

Entergy Arkansas obtained authorization from the FERC through April 2025 for short-term borrowings not to exceed an aggregate amount of $250 million at any time outstanding and borrowings by its nuclear fuel company variable interest entity. See Note 4 to the financial statements for further discussion of Entergy Arkansas’s short-term borrowing limits. The long-term securities issuances of Entergy Arkansas are limited to amounts authorized by the FERC. The APSC has concurrent jurisdiction over Entergy Arkansas’s first mortgage bond/secured issuances. Entergy Arkansas has obtained long-term financing authorization from the FERC that extends through April 2025. Entergy Arkansas has obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2025.

State and Local Rate Regulation and Fuel-Cost Recovery

The rates that Entergy Arkansas charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Arkansas is regulated, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the APSC, is primarily responsible for approval of the rates charged to customers.

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Entergy Arkansas, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Retail Rates

2020 Formula Rate Plan Filing

In July 2020, Entergy Arkansas filed with the APSC its 2020 formula rate plan filing to set its formula rate for the 2021 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2021, as amended through subsequent filings in the proceeding, and a netting adjustment for the historical year 2019. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2021 projected year was 8.22% resulting in a revenue deficiency of $64.3 million. The earned rate of return on common equity for the 2019 historical year was 9.07% resulting in a $23.9 million netting adjustment. The total proposed revenue change for the 2021 projected year and 2019 historical year netting adjustment was $88.2 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $74.3 million. As part of the formula rate plan tariff the calculation for the revenue constraint was updated based on actual revenues which had the effect of reducing the initially-proposed $74.3 million revenue requirement increase to $72.6 million. In October 2020, Entergy Arkansas filed with the APSC a unanimous settlement agreement reached with the other parties that resolved all but one issue. As a result of the settlement agreement, Entergy Arkansas’s requested revenue increase was $68.4 million, including a $44.5 million increase for the projected 2021 year and a $23.9 million netting adjustment. The remaining issue litigated concerned the methodology used to calculate the netting adjustment within the formula rate plan. In December 2020 the APSC issued an order rejecting the netting adjustment method used by Entergy Arkansas. Applying the approach ordered by the APSC changed the netting adjustment for the 2019 historical year from a $23.9 million deficiency to $43.5 million excess. Overall, the decision reduced Entergy Arkansas’s revenue adjustment for 2021 to $1 million. In December 2020, Entergy Arkansas filed a petition for rehearing of the APSC’s decision in the 2020 formula rate plan proceeding regarding the 2019 netting adjustment, and in January 2021 the APSC granted further consideration of Entergy Arkansas’s petition. Based on the progress of the proceeding at that point, in December 2020, Entergy Arkansas recorded a regulatory liability of $43.5 million to reflect the netting adjustment for 2019, as included in the APSC’s December 2020 order, which would be returned to customers in 2021. Entergy Arkansas also requested an extension of the formula rate plan rider for a second five-year term. In March 2021 the Arkansas Governor signed HB1662 into law (Act 404). Act 404 clarified aspects of the original formula rate plan legislation enacted in 2015, including with respect to the extension of a formula rate plan, the methodology for the netting adjustment, and debt and equity levels; it also reaffirmed the customer protections of the original formula rate plan legislation, including the cap on annual formula rate plan rate changes. Pursuant to Act 404, Entergy Arkansas’s formula rate plan rider was extended for a second five-year term. Entergy Arkansas filed a compliance tariff in its formula rate plan docket in April 2021 to effectuate the netting provisions of Act 404, which reflected a net change in required formula rate plan rider revenue of $39.8 million, effective with the first billing cycle of May 2021. In April 2021 the APSC issued an order approving the compliance tariff and recognizing the formula rate plan extension. Also in April 2021, Entergy Arkansas filed for approval of modifications to the formula rate plan tariff incorporating the provisions in Act 404, and the APSC approved the tariff modifications in April 2021. Given the APSC general staff’s support for the expedited approval of these filings by the APSC, Entergy Arkansas supported an amendment to Act 404 to achieve a reduced return on equity from 9.75% to 9.65% to apply for years applicable to the extension term; that amendment was signed by the Arkansas Governor in April 2021 and is now Act 894. Based on the APSC’s order issued in April 2021, in the first quarter 2021, Entergy Arkansas reversed the remaining regulatory liability for the netting adjustment for 2019. In June 2021, Entergy Arkansas filed another compliance tariff in its formula rate plan proceeding to effectuate the additional provisions of Act 894, and the APSC approved the second compliance tariff filing in July 2021.

2021 Formula Rate Plan Filing

In July 2021, Entergy Arkansas filed with the APSC its 2021 formula rate plan filing to set its formula rate for the 2022 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2022 and a netting adjustment for the historical year 2020. The filing showed that Entergy Arkansas’s earned rate

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Management’s Financial Discussion and Analysis

of return on common equity for the 2022 projected year was 7.65% resulting in a revenue deficiency of $89.2 million. The earned rate of return on common equity for the 2020 historical year was 7.92% resulting in a $19.4 million netting adjustment. The total proposed revenue change for the 2022 projected year and 2020 historical year netting adjustment was $108.7 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $72.4 million. In October 2021, Entergy Arkansas filed with the APSC a settlement agreement reached with other parties resolving all issues in the proceeding. As a result of the settlement agreement, the total proposed revenue change was $82.2 million, including a $62.8 million increase for the projected 2022 year and a $19.4 million netting adjustment. Because Entergy Arkansas’s revenue requirement exceeded the constraint, the resulting increase was limited to $72.1 million. In December 2021 the APSC approved the settlement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2022.

2022 Formula Rate Plan Filing

In July 2022, Entergy Arkansas filed with the APSC its 2022 formula rate plan filing to set its formula rate for the 2023 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2023 and a netting adjustment for the historical year 2021. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2023 projected year was 7.40% resulting in a revenue deficiency of $104.8 million. The earned rate of return on common equity for the 2021 historical year was 8.38% resulting in a $15.2 million netting adjustment. The total proposed revenue change for the 2023 projected year and 2021 historical year netting adjustment was $119.9 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $79.3 million. In October 2022 other parties filed their testimony recommending various adjustments to Entergy Arkansas’s overall proposed revenue deficiency, and Entergy Arkansas filed a response including an update to actual revenues through August 2022, which raised the constraint to $79.8 million. In November 2022, Entergy Arkansas filed with the APSC a settlement agreement reached with other parties resolving all issues in the proceeding. As a result of the settlement agreement, the total revenue change was $102.8 million, including a $87.7 million increase for the 2023 projected year and a $15.2 million netting adjustment. Because Entergy Arkansas’s revenue requirement exceeded the constraint, the resulting increase was limited to $79.8 million. In December 2022 the APSC approved the settlement agreement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2023.

2023 Formula Rate Plan Filing

In July 2023, Entergy Arkansas filed with the APSC its 2023 formula rate plan filing to set its formula rate for the 2024 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2024 and a netting adjustment for the historical year 2022. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2024 projected year was 8.11% resulting in a revenue deficiency of $80.5 million. The earned rate of return on common equity for the 2022 historical year was 7.29% resulting in a $49.8 million netting adjustment. The total proposed revenue change for the 2024 projected year and 2022 historical year netting adjustment is $130.3 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $88.6 million. The APSC general staff and intervenors filed their errors and objections in October 2023, proposing certain adjustments, including the APSC general staff’s update to annual filing year revenues which lowers the constraint to $87.7 million. Entergy Arkansas filed its rebuttal in October 2023. In October 2023, Entergy Arkansas filed with the APSC a settlement agreement reached with other parties resolving all issues in the proceeding, none of which affected Entergy Arkansas’s requested recovery up to the cap constraint of $87.7 million. The settlement agreement provided for amortization of the approximately $39 million regulatory asset for costs associated with the COVID-19 pandemic over a 10-year period as well as recovery of $34.9 million related to the

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resolution of the 2016 and 2017 IRS audits from previous tax positions that are no longer uncertain, partially offset by $24.7 million in excess accumulated deferred income taxes from reductions in state income tax rates, each before consideration of their respective tax gross-up. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit and the State of Arkansas corporate income tax rate changes. In December 2023 the APSC approved the settlement agreement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2024.

Energy Cost Recovery Rider

Entergy Arkansas’s retail rates include an energy cost recovery rider to recover fuel and purchased energy costs in monthly customer bills. The rider utilizes the prior calendar-year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over- or under-recovery, including carrying charges, of the energy costs for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs.

In January 2014, Entergy Arkansas filed a motion with the APSC relating to its upcoming energy cost rate redetermination filing that was made in March 2014. In that motion, Entergy Arkansas requested that the APSC authorize Entergy Arkansas to exclude from the redetermination of its 2014 energy cost rate $65.9 million of incremental fuel and replacement energy costs incurred in 2013 as a result of the ANO stator incident. Entergy Arkansas requested that the APSC authorize Entergy Arkansas to retain that amount in its deferred fuel balance, with recovery to be reviewed in a later period after more information was available regarding various claims associated with the ANO stator incident. In February 2014 the APSC approved Entergy Arkansas’s request to retain that amount in its deferred fuel balance. In July 2017, Entergy Arkansas filed for a change in rates pursuant to its formula rate plan rider. In that proceeding, the APSC approved a settlement agreement agreed upon by the parties, including a provision that requires Entergy Arkansas to initiate a regulatory proceeding for the purpose of recovering funds currently withheld from rates and related to the stator incident, including the $65.9 million of deferred fuel and purchased energy costs and costs related to the incremental oversight previously noted, subject to certain timelines and conditions set forth in the settlement agreement. In October 2023, Entergy Arkansas made a commitment to the APSC to make a filing to forgo its opportunity to seek recovery of the incremental fuel and purchased energy expense, among other identified costs, resulting from the ANO stator incident. As a result, in third quarter 2023, Entergy Arkansas recorded a write-off of its regulatory asset for deferred fuel of $68.9 million, which includes interest, related to the ANO stator incident. Consistent with its October 2023 commitment, Entergy Arkansas filed a motion to forgo recovery in November 2023, and the motion was approved by the APSC in December 2023. See “ANO Damage, Outage, and NRC Reviews” in Note 8 to the financial statements for further discussion of the ANO stator incident and the approved motion to forgo recovery.

In March 2017, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01164 per kWh to $0.01547 per kWh. The APSC staff filed testimony in March 2017 recommending that the redetermined rate be implemented with the first billing cycle of April 2017 under the normal operation of the tariff. Accordingly, the redetermined rate went into effect on March 31, 2017 pursuant to the tariff. In July 2017 the Arkansas Attorney General requested additional information to support certain of the costs included in Entergy Arkansas’s 2017 energy cost rate redetermination.

In March 2018, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01547 per kWh to $0.01882 per kWh. The Arkansas Attorney General filed a response to Entergy Arkansas’s annual redetermination filing requesting that the APSC suspend the proposed tariff to investigate the amount of the redetermination or, alternatively, to allow recovery subject to refund. Among the reasons the Attorney General cited for suspension were questions pertaining to how Entergy Arkansas forecasted sales and potential implications of the Tax Cuts and Jobs Act. Entergy Arkansas replied to the Attorney General’s filing and stated that, to the extent there are questions pertaining to its

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load forecasting or the operation of the energy cost recovery rider, those issues exceed the scope of the instant rate redetermination. Entergy Arkansas also stated that potential effects of the Tax Cuts and Jobs Act are appropriately considered in the APSC’s separate proceeding regarding potential implications of the tax law. The APSC general staff filed a reply to the Attorney General’s filing and agreed that Entergy Arkansas’s filing complied with the terms of the energy cost recovery rider. The redetermined rate became effective with the first billing cycle of April 2018. Subsequently in April 2018 the APSC issued an order declining to suspend Entergy Arkansas’s energy cost recovery rider rate and declining to require further investigation at that time of the issues suggested by the Attorney General in the proceeding. Following a period of discovery, the Attorney General filed a supplemental response in October 2018 raising new issues with Entergy Arkansas’s March 2018 rate redetermination and asserting that $45.7 million of the increase should be collected subject to refund pending further investigation. Entergy Arkansas filed to dismiss the Attorney General’s supplemental response, the APSC general staff filed a motion to strike the Attorney General’s filing, and the Attorney General filed a supplemental response disputing Entergy Arkansas and the APSC staff’s filing. Applicable APSC rules and processes authorize its general staff to initiate periodic audits of Entergy Arkansas’s energy cost recovery rider. In late-2018 the APSC general staff notified Entergy Arkansas it has initiated an audit of the 2017 fuel costs. The time in which the audit will be complete is uncertain at this time.

In March 2021, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $0.01052 per kWh to $0.00959 per kWh. The redetermined rate calculation also included an adjustment to account for a portion of the increased fuel costs resulting from the February 2021 winter storms. The redetermined rate became effective with the first billing cycle in April 2021 through the normal operation of the tariff.

In March 2022, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase from $0.00959 per kWh to $0.01785 per kWh. The primary reason for the rate increase was a large under-recovered balance as a result of higher natural gas prices in 2021, particularly in the fourth quarter 2021. At the request of the APSC general staff, Entergy Arkansas deferred its request for recovery of $32 million from the under-recovery related to the February 2021 winter storms until the 2023 energy cost rate redetermination, unless a request for an interim adjustment to the energy cost recovery rider is necessary. This resulted in a redetermined rate of $0.016390 per kWh, which became effective with the first billing cycle in April 2022 through the normal operation of the tariff. In February 2023 the APSC issued orders initiating proceedings with the utilities under its jurisdiction to address the prudence of costs incurred and appropriate cost allocation of the February 2021 winter storms. With respect to any prudence review of Entergy Arkansas fuel costs, as part of the APSC’s draft report issued in its February 2021 winter storms investigation docket, the APSC included findings that the load shedding plans of the investor-owned utilities and some cooperatives were appropriate and comprehensive, and, further, that Entergy Arkansas’s emergency plan was comprehensive and had a multilayered approach supported by a system-wide response plan, which is considered an industry standard. In September 2023 the APSC issued an order in Entergy Arkansas's company-specific proceeding and found that Entergy Arkansas’s practices during the winter storms were prudent.

In March 2023, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase from $0.01639 per kWh to $0.01883 per kWh. The primary reason for the rate increase is a large under-recovered balance as a result of higher natural gas prices in 2022 and a $32 million deferral related to the February 2021 winter storms consistent with the APSC general staff’s request in 2022. The under-recovered balance included in the filing was partially offset by the proceeds of the $41.7 million refund that System Energy made to Entergy Arkansas in January 2023 related to the sale-leaseback renewal costs and depreciation litigation as calculated in System Energy’s January 2023 compliance report filed with the FERC. See “Complaints Against System Energy - Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue” in Note 2 to the financial statements for discussion of the compliance report filed by System Energy with the FERC in January 2023. The redetermined rate of $0.01883 per kWh became effective with the first billing cycle in April 2023 through the normal operation of the tariff.

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Opportunity Sales Proceeding

In June 2009 the LPSC filed a complaint requesting that the FERC determine that certain of Entergy Arkansas’s sales of electric energy to third parties: (a) violated the provisions of the System Agreement that allocated the energy generated by Entergy System resources; (b) imprudently denied the Entergy System and its ultimate consumers the benefits of low-cost Entergy System generating capacity; and (c) violated the provision of the System Agreement that prohibited sales to third parties by individual companies absent an offer of a right-of-first-refusal to other Utility operating companies. The LPSC’s complaint challenged sales made beginning in 2002 and requested refunds. In July 2009 the Utility operating companies filed a response to the complaint arguing among other things that the System Agreement contemplates that the Utility operating companies may make sales to third parties for their own account, subject to the requirement that those sales be included in the load (or load shape) for the applicable Utility operating company. The FERC subsequently ordered a hearing in the proceeding.

After a hearing, the ALJ issued an initial decision in December 2010. The ALJ found that the System Agreement allowed for Entergy Arkansas to make the sales to third parties but concluded that the sales should be accounted for in the same manner as joint account sales. The ALJ concluded that “shareholders” should make refunds of the damages to the Utility operating companies, along with interest. Entergy disagreed with several aspects of the ALJ’s initial decision and in January 2011 filed with the FERC exceptions to the decision.

The FERC issued a decision in June 2012 and held that, while the System Agreement is ambiguous, it does provide authority for individual Utility operating companies to make opportunity sales for their own account and Entergy Arkansas made and priced these sales in good faith. The FERC found, however, that the System Agreement does not provide authority for an individual Utility operating company to allocate the energy associated with such opportunity sales as part of its load but provides a different allocation authority. The FERC further found that the after-the-fact accounting methodology used to allocate the energy used to supply the sales was inconsistent with the System Agreement. The FERC in its decision established further hearing procedures to quantify the effect of repricing the opportunity sales in accordance with the FERC’s June 2012 decision. The hearing was held in May 2013 and the ALJ issued an initial decision in August 2013. The LPSC, the APSC, the City Council, and FERC staff filed briefs on exceptions and/or briefs opposing exceptions. Entergy filed a brief on exceptions requesting that the FERC reverse the initial decision and a brief opposing certain exceptions taken by the LPSC and FERC staff.

In April 2016 the FERC issued orders addressing requests for rehearing filed in July 2012 and the ALJ’s August 2013 initial decision. The first order denied Entergy’s request for rehearing and affirmed the FERC’s earlier rulings that Entergy’s original methodology for allocating energy costs to the opportunity sales was incorrect and, as a result, Entergy Arkansas must make payments to the other Utility operating companies to put them in the same position that they would have been in absent the incorrect allocation. The FERC clarified that interest should be included with the payments. The second order affirmed in part, and reversed in part, the rulings in the ALJ’s August 2013 initial decision regarding the methodology that should be used to calculate the payments Entergy Arkansas is to make to the other Utility operating companies. The FERC affirmed the ALJ’s ruling that a full re-run of intra-system bills should be performed but required that methodology be modified so that the sales have the same priority for purposes of energy allocation as joint account sales. The FERC reversed the ALJ’s decision that any payments by Entergy Arkansas should be reduced by 20%. The FERC also reversed the ALJ’s decision that adjustments to other System Agreement service schedules and excess bandwidth payments should not be taken into account when calculating the payments to be made by Entergy Arkansas. The FERC held that such adjustments and excess bandwidth payments should be taken into account but ordered further proceedings before an ALJ to address whether a cap on any reduction due to bandwidth payments was necessary and to implement the other adjustments to the calculation methodology.

In May 2016, Entergy Services filed a request for rehearing of the FERC’s April 2016 order arguing that payments made by Entergy Arkansas should be reduced as a result of the timing of the LPSC’s approval of certain contracts. Entergy Services also filed a request for clarification and/or rehearing of the FERC’s April 2016 order

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addressing the ALJ’s August 2013 initial decision. The APSC and the LPSC also filed requests for rehearing of the FERC’s April 2016 order. In September 2017 the FERC issued an order denying the request for rehearing on the issue of whether any payments by Entergy Arkansas to the other Utility operating companies should be reduced due to the timing of the LPSC’s approval of Entergy Arkansas’s wholesale baseload contract with Entergy Louisiana. In November 2017 the FERC issued an order denying all of the remaining requests for rehearing of the April 2016 order. In November 2017, Entergy Services filed a petition for review in the D.C. Circuit of the FERC’s orders in the first two phases of the opportunity sales case. In December 2017 the D.C. Circuit granted Entergy Services’ request to hold the appeal in abeyance pending final resolution of the related proceeding before the FERC. In January 2018 the APSC and the LPSC filed separate petitions for review in the D.C. Circuit, and the D.C. Circuit consolidated the appeals with Entergy Services’ appeal.

The hearing required by the FERC’s April 2016 order was held in May 2017. In July 2017 the ALJ issued an initial decision addressing whether a cap on any reduction due to bandwidth payments was necessary and whether to implement the other adjustments to the calculation methodology. In August 2017 the Utility operating companies, the LPSC, the APSC, and FERC staff filed individual briefs on exceptions challenging various aspects of the initial decision. In September 2017 the Utility operating companies, the LPSC, the APSC, the MPSC, the City Council, and FERC staff filed separate briefs opposing exceptions taken by various parties.

Based on testimony previously submitted in the case and its assessment of the April 2016 FERC orders, in the first quarter 2016, Entergy Arkansas recorded a liability of $87 million, which included interest, for its estimated increased costs and payment to the other Utility operating companies, and a deferred fuel regulatory asset of $75 million. Following its assessment of the course of the proceedings, including the FERC’s denial of rehearing in November 2017 described above, in the fourth quarter 2017, Entergy Arkansas recorded an additional liability of $35 million and a regulatory asset of $31 million.

In October 2018 the FERC issued an order addressing the ALJ’s July 2017 initial decision. The FERC reversed the ALJ’s decision to cap the reduction in Entergy Arkansas’s payment to account for the increased bandwidth payments that Entergy Arkansas made to the other operating companies. The FERC also reversed the ALJ’s decision that Grand Gulf sales from January through September 2000 should be included in the calculation of Entergy Arkansas’s payment. The FERC affirmed on other grounds the ALJ’s rejection of the LPSC’s claim that certain joint account sales should be accounted for as part of the calculation of Entergy Arkansas’s payment. In November 2018 the LPSC requested rehearing of the FERC’s October 2018 decision. In December 2019 the FERC denied the LPSC’s request for rehearing. In January 2020 the LPSC appealed the December 2019 decision to the D.C. Circuit.

In December 2018, Entergy made a compliance filing in response to the FERC’s October 2018 order. The compliance filing provided a final calculation of Entergy Arkansas’s payments to the other Utility operating companies, including interest. No protests were filed in response to the December 2018 compliance filing. Refunds and interest in the following amounts were paid by Entergy Arkansas to the other operating companies in December 2018:

Total refunds including interest

Payment/(Receipt)

(In Millions)

PrincipalInterestTotal

Entergy Arkansas$68$67$135

Entergy Louisiana($30)($29)($59)

Entergy Mississippi($18)($18)($36)

Entergy New Orleans($3)($4)($7)

Entergy Texas($17)($16)($33)

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Entergy Arkansas previously recognized a regulatory asset with a balance of $116 million as of December 31, 2018 for a portion of the payments due as a result of this proceeding.

As described above, the FERC’s opportunity sales orders were appealed to the D.C. Circuit. In February 2020 all of the appeals were consolidated and in April 2020 the D.C. Circuit established a briefing schedule. Briefing was completed in September 2020 and oral argument was heard in December 2020. In July 2021 the D.C. Circuit issued a decision denying all of the petitions for review filed in response to the FERC’s opportunity sales orders.

In February 2019 the LPSC filed a new complaint relating to two issues that were raised in the opportunity sales proceeding, but that, in its October 2018 order, the FERC held were outside the scope of the proceeding. In March 2019, Entergy Services filed an answer and motion to dismiss the new complaint. In November 2019 the FERC issued an order denying the LPSC’s complaint. The order concluded that the settlement agreement approved by the FERC in December 2015 terminating the System Agreement barred the LPSC’s new complaint. In December 2019 the LPSC requested rehearing of the FERC’s November 2019 order, and in July 2020 the FERC issued an order dismissing the LPSC’s request for rehearing. In September 2020 the LPSC appealed to the D.C. Circuit the FERC’s orders dismissing the new opportunity sales complaint. In November 2020 the D.C. Circuit issued an order establishing that briefing will occur in January 2021 through April 2021. Oral argument was held in September 2021. In December 2021 the D.C. Circuit denied the LPSC’s Petition for Review of the new opportunity sales complaint. The opportunity sales cases are complete at FERC and at the D.C. Circuit and no additional refund amounts are owed by Entergy Arkansas.

In May 2019, Entergy Arkansas filed an application and supporting testimony with the APSC requesting approval of a special rider tariff to recover the costs of these payments from its retail customers over a 24-month period. The application requested that the APSC approve the rider to take effect within 30 days or, if suspended by the APSC as allowed by commission rule, approve the rider to take effect in the first billing cycle of the first month occurring 30 days after issuance of the APSC’s order approving the rider. In June 2019 the APSC suspended Entergy Arkansas’s tariff and granted Entergy Arkansas’s motion asking the APSC to establish the proceeding as the single designated proceeding in which interested parties may assert claims related to the appropriate retail rate treatment of the FERC’s October 2018 order and related FERC orders in the opportunity sales proceeding. In January 2020 the APSC adopted a procedural schedule with a hearing in April 2020. In January 2020 the Attorney General and Arkansas Electric Energy Consumers, Inc. filed a joint motion seeking to dismiss Entergy Arkansas’s application alleging that the APSC, in a prior proceeding, ruled on the issues addressed in the application and determined that Entergy Arkansas’s requested relief violates the filed rate doctrine and the prohibition against retroactive ratemaking. Entergy Arkansas responded to the joint motion in February 2020 rebutting these arguments, including demonstrating that the claims in this proceeding differ substantially from those the APSC addressed previously and that the payment resulting from a FERC tariff violation for which Entergy Arkansas seeks retail cost recovery in this proceeding differs materially from the refunds resulting from a FERC tariff amendment that the APSC previously rejected on filed rate doctrine and the retroactive ratemaking grounds. In addition, in January 2020 the Attorney General and Arkansas Electric Energy Consumers, Inc. filed testimony opposing the recovery by Entergy Arkansas of the opportunity sales payment but also claiming that certain components of the payment should be segregated and refunded to customers. In March 2020, Entergy Arkansas filed rebuttal testimony.

In July 2020 the APSC issued a decision finding that Entergy Arkansas’s application is not in the public interest. The order also directed Entergy Arkansas to refund to its retail customers within 30 days of the order the FERC-determined over-collection of $13.7 million, plus interest, associated with a recalculated bandwidth remedy. In addition to these primary findings, the order also denied the Attorney General’s request for Entergy Arkansas to prepare a compliance filing detailing all of the retail impacts from the opportunity sales and denied a request by the Arkansas Electric Energy Consumers to recalculate all costs using the revised responsibility ratio. Entergy Arkansas filed a motion for temporary stay of the 30-day requirement to allow Entergy Arkansas a reasonable opportunity to seek rehearing of the APSC order, but in July 2020 the APSC denied Entergy Arkansas’s request for

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a stay and directed Entergy Arkansas to refund to its retail customers the component of the total FERC-determined opportunity sales payment that was associated with increased bandwidth remedy payments of $13.7 million, plus interest. The refunds were issued in the August 2020 billing cycle. While the APSC denied Entergy Arkansas’s stay request, Entergy Arkansas believes its actions were prudent and, therefore, the costs, including the $13.7 million, plus interest, are recoverable. In July 2020, Entergy Arkansas requested rehearing of the APSC order, which rehearing was denied by the APSC in August 2020. In September 2020, Entergy Arkansas filed a complaint in the U.S. District Court for the Eastern District of Arkansas challenging the APSC’s order denying Entergy Arkansas’s request to recover the costs of these payments. In October 2020 the APSC filed a motion to dismiss Entergy Arkansas’s complaint, to which Entergy Arkansas responded. Also in December 2020, Entergy Arkansas and the APSC held a pre-trial conference, and filed a report with the court in January 2021. The court held a hearing in February 2021 regarding issues addressed in the pre-trial conference report, and in June 2021 the court stayed all discovery until it rules on pending motions, after which the court will issue an amended schedule if necessary. In March 2022 the court denied the APSC’s motion to dismiss, and, in April 2022, issued a scheduling order including a trial date in February 2023. In June 2022, Entergy Arkansas filed a motion asserting that it is entitled to summary judgment because Entergy Arkansas’s position that the APSC’s order is pre-empted by the filed rate doctrine and violates the Dormant Commerce Clause is premised on facts that are not subject to genuine dispute. In July 2022, Arkansas Electric Energy Consumers, Inc., an industrial customer association, filed a motion to intervene and to hold Entergy Arkansas’s motion for summary judgment in abeyance pending a ruling on the motion to intervene. Entergy Arkansas filed a consolidated opposition to both motions. In August 2022 the APSC filed a motion for summary judgment arguing that there is no genuine issue as to any material fact and the APSC is entitled to judgment as a matter of law. In September 2022, Entergy Arkansas filed an opposition to the motion. In October 2022 the APSC filed a motion asking the court to hold further proceedings in abeyance pending a decision on the motions for summary judgment filed by Entergy Arkansas and the APSC. Also in October 2022, Entergy Arkansas filed an opposition to the motion, and the APSC filed a reply in support of its motion for summary judgment. In January 2023 the judge assigned to the case, on her own motion, identified facts that may present a conflict and recused herself; a new judge was assigned to the case, but he also recused due to a conflict. The case again was reassigned to a new judge. In January 2023 the court denied all pending motions (including those described above) except for a motion by the APSC to exclude certain testimony and further ruled that the matter would proceed to trial. In January 2023, Arkansas Electric Energy Consumers, Inc. filed a notice of appeal of the court’s order denying its motion to intervene to the United States Court of Appeals for the Eighth Circuit and a motion with the district court to stay the proceedings pending the appeal, which was denied. In February 2023, Arkansas Electric Energy Consumers, Inc. filed a motion with the United States Court of Appeals for the Eighth District to stay the proceedings pending the appeal, which also was denied. The trial was held in February 2023. Following the trial, Entergy Arkansas filed a motion with the United States Court of Appeals for the Eighth District to expedite the appeal filed by Arkansas Electric Energy Consumers, Inc. The United States Court of Appeals for the Eighth District granted Entergy Arkansas’s request, and oral arguments were held in June 2023. In August 2023 the United States Court of Appeals for the Eighth District affirmed the order of the court denying Arkansas Electric Energy Consumers, Inc.’s motion to intervene. An order from the district court is pending and is anticipated in 2024.

Net Metering Legislation

An Arkansas law was enacted effective July 2019 that, among other things, expands the definition of a “net metering customer” to include two additional types of customers: (1) customers that lease net metering facilities, subject to certain leasing arrangements, and (2) government entities or other entities exempt from state and federal income taxes that enter into a service contract for a net metering facility. The latter provision allows eligible entities, many of whom are small and large general service customers, to purchase renewable energy directly from third party providers and receive bill credits for these purchases. The APSC was given authority under this law to address certain matters, such as cost shifting and the appropriate compensation for net metered energy and initiated proceedings for this purpose. Because of the size and number of customers eligible under this new law, there is a risk of loss of load and the shifting of costs to customers. A hearing was held in December 2019, with utilities, including Entergy Arkansas, cooperatives, the Arkansas Attorney General, and industrial customers advocating the

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need for establishment of a reasonable rate structure that takes into account impacts to non-net metering customers; an additional hearing was conducted in February 2020 for purposes of public comment only. The APSC issued an order in June 2020, and in July 2020 several parties, including Entergy Arkansas, filed for rehearing on multiple grounds, including for the reasons that it imposes an unreasonable rate structure and allows facilities to net meter that do not meet the statutory definition of net metering facilities. After granting the rehearing requests, the APSC issued an order in September 2020 largely upholding its June 2020 order. In October 2020, Entergy Arkansas and several other parties filed an appeal of the APSC’s September 2020 order. In January 2021, Entergy Arkansas, pursuant to an APSC order, filed an updated net metering tariff, which was approved in February 2021. In May 2021, Entergy Arkansas filed a motion to dismiss its pending judicial appeal of the APSC’s September 2020 order on rehearing in the proceeding addressing its net metering rules. In June 2021 the Arkansas Court of Appeals granted the motion and dismissed Entergy Arkansas’s appeal, although other appeals of the September 2020 APSC order remained before the court. In May 2022 the court issued an order affirming the APSC’s decision in part and reversing in part. In June 2022 the APSC sought rehearing from the court with respect to the court’s ruling on a grid charge, which the court of appeals denied in July 2022. One of the cooperative appellants filed a further appeal to the Arkansas Supreme Court in July 2022, which the court decided not to hear.

Separately, as directed by the APSC general staff, the APSC opened a proceeding to compel utilities to amend their net metering tariffs to incorporate the provisions of the legislation that the APSC general staff considered “black letter law.” Entergy Arkansas, the Arkansas Attorney General, and other intervenors opposed this directive pending the development of the rules for implementation that are being considered in the separate net metering rulemaking docket. Nevertheless, reserving its rights, Entergy Arkansas has complied with the directive to amend its tariffs. Asserting procedural and due process violations, in January 2020, Entergy Arkansas and the Arkansas Attorney General separately appealed certain APSC orders in the proceeding. In December 2021 the Arkansas Court of Appeals dismissed the appeal on procedural grounds and without prejudice.

Since the enactment of the net metering legislation, the APSC has approved numerous applications allowing Entergy Arkansas customers to enter into purchase power agreements with third parties and to utilize these purchase power agreements to offset power usage by Entergy Arkansas, despite the lack of proximity between the purchase power agreement and the end-use customer. The APSC also has allowed the aggregation of accounts by net metering customers. These decisions by the APSC have created subsidies in favor of eligible net metering customers to the detriment of non-participating customers. The level of this subsidy continues to grow as additional net metering applications are approved by the APSC.

In August 2022 the APSC opened a rulemaking concerning proposed amendments to the net metering rules to address the expiration on December 31, 2022 of the automatic grandfathering of the existing net metering rate structure. Entergy Arkansas and other utility parties filed initial briefs and comments setting forth that the statute imposing the expiration of the automatic grandfathering is not ambiguous and that the APSC does not have the authority to extend the grandfathering period, and the hearing was held in October 2022. In December 2022 the APSC issued an order attempting to modify the net metering rules and purporting to allow for the potential for grandfathering after December 31, 2022. More than thirty applicants filed individual net metering applications in December 2022 seeking to be considered under the APSC’s order, although the APSC issued an order in January 2023 holding those applications in abeyance. Several parties, including Entergy Arkansas, sought rehearing, and the Arkansas’s Governor’s executive order limiting new rulemakings calls into question how the APSC’s order to adopt new rules may be effectuated.

In September 2022 the APSC opened another proceeding to investigate the issue of potential cost shifting arising as a result of net metering. Investor owned utilities and some cooperatives were required to make and did make filings in October 2022 with supporting documentation as to the amount and extent of cost shifting and the manner in which they would design tariffs to recover those costs on behalf of non-net metering customers. Responses to the utility and cooperative filings were filed in January 2023, and utilities filed their further responses in February 2023.

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An Arkansas law was enacted effective March 2023 that revises the billing arrangements for net metering facilities in order to reduce the cost shift to non-net metering customers. The new law also imposes a new limit of 5 MW for future net metering facilities, allows utilities to recover net metering credits in the same manner as fuel, and grandfathers certain net metering facilities that are online or in process to be online by September 2024. Entergy Arkansas joined other utilities in a motion in April 2023 to close the current APSC docket related to potential cost shifting in light of the new law, and the APSC also canceled the remaining procedural schedule in this docket in April 2023. Because of the new law, in May 2023, the APSC also closed the grandfathering rulemaking that it opened in August 2022. Under the new law, the APSC must approve revisions to the utilities’ tariffs to conform to the new law no later than December 2023. The APSC opened a new rulemaking in April 2023 to consider implementation of the new law and tariffs. In October 2023 the APSC issued new net metering rules to conform to the new law, and utilities, including Entergy Arkansas, filed revised net metering tariffs to comply with the new rules on October 16, 2023. Entergy Arkansas’s revised net metering tariff was approved by the APSC in December 2023.

Federal Regulation

See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.

Nuclear Matters

Entergy Arkansas owns and, through an affiliate, operates the ANO 1 and 2 nuclear generating plants and is, therefore, subject to the risks related to such ownership and operation. These include risks related to: the use, storage, and handling and disposal of high-level and low-level radioactive materials; the substantial financial requirements, both for capital investments and operational needs, including the financial requirements to address emerging issues related to equipment reliability, to position Entergy Arkansas’s nuclear fleet to meet its operational goals; the performance and capacity factors of these nuclear plants; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license amendments, and decommissioning; the availability of interim or permanent sites for the disposal of spent nuclear fuel and nuclear waste, including the fees charged for such disposal; the sufficiency of nuclear decommissioning trust fund assets and earnings to complete decommissioning of each site when required; and limitations on the amounts of insurance recoveries for losses in connection with nuclear plant operations and catastrophic events such as a nuclear accident. In the event of an unanticipated early shutdown of either ANO 1 or 2, Entergy Arkansas may be required to file with the APSC a rate mechanism to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. ANO 1’s operating license expires in 2034 and ANO 2’s operating license expires in 2038.

Environmental Risks

Entergy Arkansas’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Arkansas is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Critical Accounting Estimates

The preparation of Entergy Arkansas’s financial statements in conformity with GAAP requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following

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Entergy Arkansas, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

accounting estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in these assumptions and measurements could produce estimates that would have a material effect on the presentation of Entergy Arkansas’s financial position, results of operations, or cash flows.

Nuclear Decommissioning Costs

See “Nuclear Decommissioning Costs” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.

Utility Regulatory Accounting

See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.

Taxation and Uncertain Tax Positions

See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.

Qualified Pension and Other Postretirement Benefits

Entergy Arkansas’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are affected by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.

Costs Sensitivity

The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).

Actuarial AssumptionChange in AssumptionImpact on 2024 Qualified Pension CostImpact on 2023 Qualified Projected Benefit Obligation

Increase/(Decrease)

Discount rate(0.25%)$929$26,189

Rate of return on plan assets(0.25%)$2,567$—

Rate of increase in compensation0.25%$985$4,963

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Entergy Arkansas, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

The following chart reflects the sensitivity of postretirement benefits cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).

Actuarial AssumptionChange in AssumptionImpact on 2024 Postretirement Benefits CostImpact on 2023 Accumulated Postretirement Benefit Obligation

Increase/(Decrease)

Discount rate(0.25%)($56)$3,841

Health care cost trend0.25%$217$2,600

Each fluctuation above assumes that the other components of the calculation are held constant.

Costs and Employer Contributions

Total qualified pension cost for Entergy Arkansas in 2023 was $49.5 million, including $26.1 million in settlement costs. Entergy Arkansas anticipates 2024 qualified pension cost to be $19.6 million. Entergy Arkansas contributed $54.5 million to its qualified pension plans in 2023 and estimates pension contributions will be approximately $55.1 million in 2024, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024 valuations are completed, which is expected by April 1, 2024.

Total other postretirement health care and life insurance benefit income for Entergy Arkansas in 2023 was $1.9 million. Entergy Arkansas expects 2024 postretirement health care and life insurance benefit income of approximately $5.5 million. Entergy Arkansas contributed $582 thousand to its other postretirement plans in 2023 and estimates 2024 contributions will be approximately $529 thousand.

Other Contingencies

See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.

New Accounting Pronouncements

See the “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.

333

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the member and Board of Directors of

Entergy Arkansas, LLC and Subsidiaries

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Entergy Arkansas, LLC and Subsidiaries (the “Company”) as of December 31, 2023 and 2022, the related consolidated statements of income, cash flows and changes in equity (pages 336 through 340 and applicable items in pages 47 through 238), for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Rate and Regulatory Matters — Entergy Arkansas, LLC and Subsidiaries — Refer to Note 2 to the financial statements

Critical Audit Matter Description

The Company is subject to rate regulation by the Arkansas Public Service Commission (the “APSC”), which has jurisdiction with respect to the rates of electric companies in Arkansas, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.

334

The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the APSC and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the APSC and the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.

We identified the impact of rate regulation as a critical audit matter due to the judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs and refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the APSC and the FERC, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities involved specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and auditor judgment to evaluate management estimates and the subjectivity of audit evidence.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertainty of future decisions by the APSC and the FERC, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities included the following, among others:

•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

•We read relevant regulatory orders issued by the APSC and the FERC for the Company to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the APSC’s and the FERC’s treatment of similar costs under similar circumstances. We evaluated external information and compared to management’s recorded regulatory asset and liability balances for completeness.

•For regulatory matters in process, we inspected the Company’s filings with the APSC and the FERC and orders issued, and considered the filings with the APSC and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.

•We obtained an analysis from management and support from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.

•We obtained representation from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management’s assertion that amounts are probable of recovery, refund, or a future reduction in rates.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 23, 2024

We have served as the Company’s auditor since 2001.

335

ENTERGY ARKANSAS, LLC AND SUBSIDIARIES

CONSOLIDATED INCOME STATEMENTS

For the Years Ended December 31,

202320222021

(In Thousands)

OPERATING REVENUES

Electric$2,646,396 $2,673,194 $2,338,590

OPERATING EXPENSES

Operation and Maintenance:

Fuel, fuel-related expenses, and gas purchased for resale514,885 640,344 347,166

Purchased power257,890 201,726 280,504

Nuclear refueling outage expenses59,973 53,438 51,141

Other operation and maintenance737,649 754,293 687,418

Asset write-offs78,434 — —

Decommissioning87,321 82,326 77,696

Taxes other than income taxes141,502 136,565 127,249

Depreciation and amortization400,944 386,272 361,479

Other regulatory charges (credits) - net(87,409)(89,418)(31,501)

TOTAL2,191,189 2,165,546 1,901,152

OPERATING INCOME455,207 507,648 437,438

OTHER INCOME

Allowance for equity funds used during construction20,587 17,787 15,273

Interest and investment income25,024 19,554 76,953

Miscellaneous - net(23,216)(27,348)(22,278)

TOTAL22,395 9,993 69,948

INTEREST EXPENSE

Interest expense188,232 150,928 140,348

Allowance for borrowed funds used during construction(8,270)(7,070)(6,641)

TOTAL179,962 143,858 133,707

INCOME BEFORE INCOME TAXES297,640 373,783 373,679

Income taxes(99,210)80,896 75,195

NET INCOME396,850 292,887 298,484

Net loss attributable to noncontrolling interest(5,231)(4,358)(18,092)

EARNINGS APPLICABLE TO MEMBER'S EQUITY$402,081 $297,245 $316,576

See Notes to Financial Statements.

336

ENTERGY ARKANSAS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31,

202320222021

(In Thousands)

OPERATING ACTIVITIES

Net income$396,850 $292,887 $298,484

Adjustments to reconcile net income to net cash flow provided by operating activities:

Depreciation, amortization, and decommissioning, including nuclear fuel amortization556,780 532,291 503,539

Deferred income taxes, investment tax credits, and non-current taxes accrued(102,070)78,958 100,459

Asset write-offs78,434 — —

Changes in assets and liabilities:

Receivables(84,428)(73,579)17,682

Fuel inventory(6,351)(252)(7,081)

Accounts payable(69,947)64,944 27,967

Taxes accrued4,625 10,936 7,753

Interest accrued16,554 1,708 (5,637)

Deferred fuel costs228,021 (31,009)(162,458)

Other working capital accounts(29,690)(29,789)(53,343)

Provisions for estimated losses(21,039)2,914 6,915

Regulatory assets(6,197)(120,603)142,706

Other regulatory liabilities240,762 (264,054)21,066

Pension and other postretirement liabilities(109,077)(67,783)(175,863)

Other assets and liabilities(152,206)302,163 (172,973)

Net cash flow provided by operating activities941,021 699,732 549,216

INVESTING ACTIVITIES

Construction expenditures(946,244)(785,168)(722,628)

Allowance for equity funds used during construction20,587 17,787 15,273

Nuclear fuel purchases(137,616)(98,635)(84,302)

Proceeds from sale of nuclear fuel32,937 37,198 16,279

Proceeds from nuclear decommissioning trust fund sales117,123 248,191 530,628

Investment in nuclear decommissioning trust funds(139,280)(269,497)(524,783)

Payment for purchase of assets— (1,044)(131,770)

Change in money pool receivable - net— — 3,110

Litigation proceeds for reimbursement of spent nuclear fuel storage costs17,933 — —

Decrease (increase) in other investments1,608 (1,626)—

Net cash flow used in investing activities(1,032,952)(852,794)(898,193)

FINANCING ACTIVITIES

Proceeds from the issuance of long-term debt1,093,253 232,731 719,284

Retirement of long-term debt(597,720)(28,521)(728,917)

Capital contributions from noncontrolling interest— — 51,202

Changes in money pool payable - net(35,410)40,891 139,904

Common equity distributions paid(417,000)(86,000)(50,000)

Other47,162 (13,676)38,291

Net cash flow provided by financing activities90,285 145,425 169,764

Net decrease in cash and cash equivalents(1,646)(7,637)(179,213)

Cash and cash equivalents at beginning of period5,278 12,915 192,128

Cash and cash equivalents at end of period$3,632 $5,278 $12,915

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:

Cash paid (received) during the period for:

Interest - net of amount capitalized$169,173 $147,060 $143,561

Income taxes$2,705 ($2,753)($18,933)

Noncash investing activities:

Accrued construction expenditures$36,264 $93,189 $35,616

See Notes to Financial Statements.

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ENTERGY ARKANSAS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31,

20232022

(In Thousands)

CURRENT ASSETS

Cash and cash equivalents:

Cash$520 $1,911

Temporary cash investments3,112 3,367

Total cash and cash equivalents3,632 5,278

Accounts receivable:

Customer157,520 140,513

Allowance for doubtful accounts(7,182)(6,528)

Associated companies124,672 45,336

Other89,532 101,096

Accrued unbilled revenues117,119 116,816

Total accounts receivable481,661 397,233

Deferred fuel costs— 139,739

Fuel inventory - at average cost57,495 51,144

Materials and supplies - at average cost358,302 288,260

Deferred nuclear refueling outage costs35,463 56,443

Prepayments and other40,866 26,576

TOTAL977,419 964,673

OTHER PROPERTY AND INVESTMENTS

Decommissioning trust funds1,414,009 1,199,860

Other801 2,414

TOTAL1,414,810 1,202,274

UTILITY PLANT

Electric14,821,814 14,077,844

Construction work in progress340,601 417,244

Nuclear fuel213,722 176,174

TOTAL UTILITY PLANT15,376,137 14,671,262

Less - accumulated depreciation and amortization6,002,203 5,729,304

UTILITY PLANT - NET9,373,934 8,941,958

DEFERRED DEBITS AND OTHER ASSETS

Regulatory assets:

Other regulatory assets1,885,361 1,810,281

Deferred fuel costs— 68,883

Other21,334 18,507

TOTAL1,906,695 1,897,671

TOTAL ASSETS$13,672,858 $13,006,576

See Notes to Financial Statements.

338

ENTERGY ARKANSAS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

December 31,

20232022

(In Thousands)

CURRENT LIABILITIES

Currently maturing long-term debt$375,000 $290,000

Accounts payable:

Associated companies225,344 276,362

Other215,502 310,339

Customer deposits113,186 102,799

Taxes accrued105,151 100,526

Interest accrued35,370 18,816

Deferred fuel costs88,282 —

Other55,683 43,394

TOTAL1,213,518 1,142,236

NON-CURRENT LIABILITIES

Accumulated deferred income taxes and taxes accrued1,437,053 1,498,234

Accumulated deferred investment tax credits27,270 28,472

Regulatory liability for income taxes - net392,496 435,157

Other regulatory liabilities759,181 475,758

Decommissioning1,560,057 1,472,736

Accumulated provisions58,959 79,998

Pension and other postretirement liabilities8,901 118,020

Long-term debt4,298,080 3,876,500

Other156,673 97,650

TOTAL8,698,670 8,082,525

Commitments and Contingencies

EQUITY

Member's equity3,739,071 3,753,990

Noncontrolling interest21,599 27,825

TOTAL3,760,670 3,781,815

TOTAL LIABILITIES AND EQUITY$13,672,858 $13,006,576

See Notes to Financial Statements.

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ENTERGY ARKANSAS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Years Ended December 31, 2023, 2022, and 2021

Noncontrolling InterestMember's EquityTotal

(In Thousands)

Balance at December 31, 2020$— $3,276,169 $3,276,169

Net income (loss)(18,092)316,576 298,484

Common equity distributions— (50,000)(50,000)

Capital contributions from noncontrolling interest51,202 — 51,202

Balance at December 31, 2021$33,110 $3,542,745 $3,575,855

Net income (loss)(4,358)297,245 292,887

Common equity distributions— (86,000)(86,000)

Distributions to noncontrolling interest(927)— (927)

Balance at December 31, 2022$27,825 $3,753,990 $3,781,815

Net income (loss)(5,231)402,081 396,850

Common equity distributions— (417,000)(417,000)

Distributions to noncontrolling interest(995)— (995)

Balance at December 31, 2023$21,599 $3,739,071 $3,760,670

See Notes to Financial Statements.

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ENTERGY LOUISIANA, LLC AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

2023 Compared to 2022

Net Income

Net income increased $417.5 million primarily due to the net effects of Entergy Louisiana’s storm cost securitization in March 2023, including a $133.4 million reduction in income tax expense, partially offset by a $103.4 million ($76.4 million net-of-tax) regulatory charge to reflect Entergy Louisiana’s obligation to provide credits to its customers as described in an LPSC ancillary order issued as part of the securitization regulatory proceeding; a $179.1 million reduction in income tax expense in 2023 as a result of the resolution of the 2016-2018 IRS audit, partially offset by a $38 million regulatory charge ($27.8 million net-of-tax) to reflect credits expected to be provided to customers; the reversal of a $105.6 million regulatory liability, associated with the Hurricane Isaac securitization, recognized in 2017 as a result of the Tax Cuts and Jobs Act, recorded in fourth quarter 2023, as part of the settlement of Entergy Louisiana’s test year 2017 formula rate plan filing; higher retail electric price; higher other income; lower other operation and maintenance expenses; and higher volume/weather. The net income increase was partially offset by the net effects of Entergy Louisiana’s storm cost securitization in May 2022, including a $290 million reduction in income tax expense, partially offset by a $224.4 million ($165.4 million net-of-tax) regulatory charge to reflect Entergy Louisiana’s obligation to provide credits to its customers as described in an LPSC ancillary order issued as part of the securitization regulatory proceeding, and higher depreciation and amortization expenses. See Note 2 to the financial statements for further discussion of the storm cost securitizations and the formula rate plan global settlement. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit.

Operating Revenues

Following is an analysis of the change in operating revenues comparing 2023 to 2022:

Amount

(In Millions)

2022 operating revenues$6,338.8

Fuel, rider, and other revenues that do not significantly affect net income(1,368.1)

Storm restoration carrying costs(6.9)

Return of unprotected excess accumulated deferred income taxes to customers24.6

Volume/weather40.8

Retail electric price118.6

2023 operating revenues$5,147.8

Entergy Louisiana’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.

Storm restoration carrying costs represent the equity component of storm restoration carrying costs recognized as part of the securitization of Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and

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Entergy Louisiana, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Hurricane Ida restoration costs in May 2022 and the equity component of storm restoration carrying costs recognized as part of the securitization of Hurricane Ida restoration costs in March 2023. See Note 2 to the financial statements for discussion of the storm cost securitizations.

The return of unprotected excess accumulated deferred income taxes to customers resulted from the return of unprotected excess accumulated deferred income taxes through changes in the formula rate plan effective May 2018 in response to the enactment of the Tax Cuts and Jobs Act. In 2022, $24.6 million was returned to customers through reductions in operating revenues. There was no return of unprotected excess accumulated deferred income taxes to customers in 2023. There was no effect on net income as the reductions in operating revenues were offset by reductions in income tax expense. See Note 2 to the financial statements for discussion of regulatory activity regarding the Tax Cuts and Jobs Act.

The volume/weather variance is primarily due to the effect of more favorable weather on residential and commercial sales.

The retail electric price variance is primarily due to increases in formula rate plan revenues, including increases in the distribution and transmission recovery mechanisms, effective September 2022 and September 2023. See Note 2 to the financial statements for further discussion of the formula rate plan proceedings.

Total electric energy sales for Entergy Louisiana for the years ended December 31, 2023 and 2022 are as follows:

20232022% Change

(GWh)

Residential14,207 14,119 1

Commercial11,074 10,927 1

Industrial31,599 31,666 —

Governmental801 820 (2)

Total retail 57,681 57,532 —

Sales for resale:

Associated companies4,406 5,416 (19)

Non-associated companies1,534 3,423 (55)

Total63,621 66,371 (4)

See Note 19 to the financial statements for additional discussion of Entergy Louisiana’s operating revenues.

Other Income Statement Variances

Other operation and maintenance expenses decreased primarily due to:

•a decrease of $27.9 million in compensation and benefits costs primarily due to lower health and welfare costs, including higher prescription drug rebates in second quarter 2023, a decrease in net periodic pension and other postretirement benefits service costs as a result of an increase in the discount rates used to value the benefits liabilities, and a revision to estimated incentive compensation expense in first quarter 2023. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs;

•a decrease of $25.1 million in transmission costs allocated by MISO. See Note 2 to the financial statements for further information on the recovery of these costs;

•a decrease of $12.3 million in non-nuclear generation expenses primarily due to a lower scope of work, including during plant outages, performed in 2023 as compared to 2022;

342

Entergy Louisiana, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

•a decrease of $8.2 million in nuclear generation expenses primarily due to a lower scope of work performed in 2023 as compared to 2022, lower nuclear labor costs, and lower costs associated with materials and supplies in 2023 as compared to 2022; and

•a decrease of $7.2 million in customer service center support costs primarily due to lower contract costs.

The decrease was partially offset by:

•an increase of $15.9 million in contract costs related to operational performance, customer service, and organizational health initiatives;

•an increase of $6.1 million in insurance expenses primarily due to lower nuclear insurance refunds received in 2023; and

•several individually insignificant items.

Depreciation and amortization expenses increased primarily due to additions to plant in service.

Other regulatory charges (credits) - net includes:

•a regulatory charge of $103.4 million, recorded in first quarter 2023, to reflect Entergy Louisiana’s obligation to provide credits to its customers as described in an LPSC ancillary order issued in the Hurricane Ida securitization regulatory proceeding. See Note 2 to the financial statements for discussion of the March 2023 storm cost securitization;

•a regulatory charge of $224.4 million, recorded in second quarter 2022, to reflect Entergy Louisiana’s obligation to provide credits to its customers as described in an LPSC ancillary order issued in the Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida securitization regulatory proceeding. See Note 2 to the financial statements for discussion of the May 2022 storm cost securitization; and

•a regulatory charge of $38 million, recorded in fourth quarter 2023, to reflect credits expected to be provided to customers as a result of the resolution of the 2016-2018 IRS audit. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit.

In addition, Entergy Louisiana records a regulatory charge or credit for the difference between asset retirement obligation-related expenses and nuclear decommissioning trust earnings plus asset retirement obligation-related costs collected in revenue.

Other income increased primarily due to:

•an increase of $113 million in affiliated dividend income from affiliated preferred membership interests related to storm cost securitizations;

•a $31.6 million charge, recorded in second quarter 2022, for the LURC’s 1% beneficial interest in the storm trust I established as part of the Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida May 2022 storm cost securitization as compared to a $14.6 million charge, recorded in first quarter 2023, for the LURC’s 1% beneficial interest in the storm trust II established as part of the Hurricane Ida March 2023 storm cost securitization. See Note 2 to the financial statements for discussion of the storm cost securitizations;

•changes in decommissioning trust fund activity, including portfolio rebalancing of certain decommissioning trust funds in 2022; and

•an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2023.

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Entergy Louisiana, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

The increase was partially offset by:

•a decrease of $20.6 million in the amount of storm restoration carrying costs recognized in 2023 as compared to 2022, primarily related to Hurricane Ida. See Note 2 to the financial statements for discussion of the storm cost securitizations; and

•lower interest income from carrying costs related to the deferred fuel balance.

The effective income tax rates were (19.3%) for 2023 and (23.5%) for 2022. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates and for additional discussion regarding income taxes.

2022 Compared to 2021

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy Louisiana’s Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 24, 2023, for discussion of results of operations for 2022 compared to 2021.

Income Tax Legislation and Regulation

See the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of income tax legislation and regulation.

Planned Sale of Gas Distribution Business

See the “Planned Sale of Gas Distribution Businesses” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the purchase and sale agreement for the sale of Entergy Louisiana’s gas distribution business.

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2023, 2022, and 2021 were as follows:

202320222021

(In Thousands)

Cash and cash equivalents at beginning of period$56,613 $18,573 $728,020

Net cash provided by (used in):

Operating activities2,032,120 1,177,508 1,052,526

Investing activities(3,039,456)(4,707,711)(3,700,199)

Financing activities953,495 3,568,243 1,938,226

Net increase (decrease) in cash and cash equivalents(53,841)38,040 (709,447)

Cash and cash equivalents at end of period$2,772 $56,613 $18,573

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2023 Compared to 2022

Operating Activities

Net cash flow provided by operating activities increased $854.6 million in 2023 primarily due to:

•a decrease of $236.7 million in storm spending primarily due to Hurricane Ida restoration efforts in 2022;

•an increase of $42.4 million in interest received primarily due to shorter-term financing interest earnings and interest on storm reserve escrow accounts. See Note 2 to the financial statements for a discussion of shorter-term financing interest earnings;

•the refund of $27.8 million received from System Energy in January 2023 related to the sale-leaseback renewal costs and depreciation litigation as calculated in System Energy’s January 2023 compliance report filed with the FERC. See Note 2 to the financial statements for further discussion of the refund and the related proceedings;

•a decrease of $9.1 million in pension contributions in 2023. See “Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding;

•lower fuel costs and the timing of recovery of fuel and purchased power costs. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery; and

•the timing of payments to vendors.

The increase was partially offset by lower collections from customers and an increase of $14.4 million in interest paid.

Investing Activities

Net cash flow used in investing activities decreased $1,668.3 million in 2023 primarily due to:

•an increase in investment in affiliates in 2022 due to the $3,163.6 million purchase by the storm trust I of preferred membership interests issued by an Entergy affiliate, partially offset by the $1,390.6 million redemption of preferred membership interests. See Note 2 to the financial statements for a discussion of the May 2022 storm cost securitization;

•a decrease of $727 million in distribution construction expenditures primarily due to lower capital expenditures for storm restoration in 2023. The decrease in storm restoration expenditures is primarily due to Hurricane Ida restoration efforts in 2022;

•a decrease of $265.4 million in transmission construction expenditures primarily due to lower capital expenditures for storm restoration in 2023 and decreased spending on various transmission projects in 2023. The decrease in storm restoration expenditures is primarily due to Hurricane Ida restoration efforts in 2022;

•$125 million of redemptions in 2023 of preferred membership interests held by the storm trust I, as part of periodic redemptions that are expected to occur, subject to certain conditions, for the preferred membership interests that were issued in connection with the May 2022 storm cost securitization. See Note 2 to the financial statements for a discussion of the May 2022 storm cost securitization and the storm trust I’s investment in preferred membership interests; and

•net receipts from storm reserve escrow accounts of $49.6 million in 2023 as compared to net payments to storm reserve escrow accounts of $293.4 million in 2022.

The decrease was partially offset by:

•an increase in investment in affiliates in 2023 due to the $1,457.7 million purchase by the storm trust II of preferred membership interests issued by an Entergy affiliate. See Note 2 to the financial statements for a discussion of the March 2023 storm cost securitization and the storm trust II’s investment in preferred membership interests;

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•an increase of $110.2 million in nuclear construction expenditures primarily due to increased spending on various nuclear projects in 2023;

•an increase of $47.5 million as a result of fluctuations in nuclear fuel activity due to variations from year to year in the timing and pricing of fuel reload requirements, materials and services deliveries, and the timing of cash payments during the nuclear fuel cycle; and

•money pool activity.

Decreases in Entergy Louisiana’s receivables from the money pool are a source of cash flow, and Entergy Louisiana’s receivable from the money pool decreased $14.5 million in 2022. The money pool is an intercompany cash management program that makes possible intercompany borrowing and lending arrangements, and the money pool and other borrowing arrangements are designed to reduce the Registrant Subsidiaries’ dependence on external short-term borrowings.

Financing Activities

Net cash flow provided by financing activities decreased $2,614.7 million in 2023 primarily due to:

•proceeds from securitization of $1.5 billion received by the storm trust II in 2023 as compared to proceeds from securitization of $3.2 billion received by the storm trust I in 2022;

•the repayment, at maturity, of $665 million of 0.62% Series mortgage bonds in November 2023;

•the issuance of $500 million of 4.75% Series mortgage bonds in August 2022;

•the repayment, at maturity, of $325 million of 4.05% Series mortgage bonds in September 2023;

•the repayment, prior to maturity, of $300 million of 5.59% Series mortgage bonds in December 2023;

•an increase of $36.8 million in common equity distributions paid in 2023 in order to maintain Entergy Louisiana’s capital structure;

•the repayment, at maturity, of $20 million of 3.22% Series I notes by the Entergy Louisiana Waterford variable interest entity in December 2023; and

•money pool activity.

The decrease was partially offset by:

•a capital contribution of approximately $1.5 billion in 2023 as compared to a capital contribution of approximately $1 billion in 2022, both received indirectly from Entergy Corporation and related to the March 2023 storm cost securitization and the May 2022 storm cost securitization, respectively;

•the repayment, prior to maturity, of $435 million, a portion of the outstanding principal, of 0.62% Series mortgage bonds in May 2022;

•the repayment, at maturity, of $200 million of 3.3% Series mortgage bonds in December 2022;

•the issuance of $70 million of 5.94% Series J notes by the Entergy Louisiana Waterford variable interest entity in September 2023; and

•a decrease of $25 million in 2023 in net repayments on Entergy Louisiana’s revolving credit facility.

Decreases in Entergy Louisiana’s payable to the money pool are a use of cash flow, and Entergy Louisiana’s payable to the money pool decreased $69.9 million in 2023 compared to increasing by $226.1 million in 2022.

See Note 5 to the financial statements for details of long-term debt. See Note 2 to the financial statements for discussion of the storm cost securitizations.

2022 Compared to 2021

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Louisiana’s Annual Report on Form 10-K for the year ended

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December 31, 2022, filed with the SEC on February 24, 2023, for discussion of operating, investing, and financing cash flow activities for 2022 compared to 2021.

Capital Structure

Entergy Louisiana’s debt to capital ratio is shown in the following table. The decrease in the debt to capital ratio for Entergy Louisiana is primarily due to the $1.5 billion capital contribution received indirectly from Entergy Corporation in March 2023 and the net retirement of long-term debt in 2023.

December 31,2023December 31,2022

Debt to capital44.9 %53.0 %

Effect of subtracting cash0.0 %(0.1 %)

Net debt to net capital (non-GAAP)44.9 %52.9 %

Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and common equity. Net capital consists of capital less cash and cash equivalents. Entergy Louisiana uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Louisiana’s financial condition. The net debt to net capital ratio is a non-GAAP measure. Entergy Louisiana also uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Louisiana’s financial condition because net debt indicates Entergy Louisiana’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

Entergy Louisiana seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a distribution, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Louisiana may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reduced distributions, Entergy Louisiana may receive equity contributions to maintain its capital structure.

Uses of Capital

Entergy Louisiana requires capital resources for:

•construction and other capital investments;

•debt maturities or retirements;

•working capital purposes, including the financing of fuel and purchased power costs; and

•distribution and interest payments.

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Following are the amounts of Entergy Louisiana’s planned construction and other capital investments.

202420252026

(In Millions)

Planned construction and capital investment:

Generation$435 $805 $780

Transmission520 775 1,220

Distribution775 790 755

Utility Support100 95 95

Total$1,830 $2,465 $2,850

In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Louisiana includes investments in generation projects to modernize, decarbonize, and diversify Entergy Louisiana’s portfolio; investments in River Bend and Waterford 3; distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to improve reliability and resilience while also supporting renewables expansion and customer growth; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, government actions, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.

Following are the amounts of Entergy Louisiana’s existing debt and lease obligations (includes estimated interest payments).

2024202520262027-2028 After 2028

(In Millions)

Long-term debt (a)$1,719 $659 $983 $1,419 $9,635

Operating leases (b)$17 $14 $11 $13 $4

Finance leases (b)$6 $5 $4 $6 $3

(a)Long-term debt is discussed in Note 5 to the financial statements.

(b)Lease obligations are discussed in Note 10 to the financial statements.

Other Obligations

Entergy Louisiana currently expects to contribute approximately $48.4 million to its qualified pension plans and approximately $15 million to its other postretirement health care and life insurance plans in 2024, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024, valuations are completed, which is expected by April 1, 2024. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

Entergy Louisiana has $128.4 million of unrecognized tax benefits net of unused tax attributes plus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

In addition, Entergy Louisiana enters into fuel and purchased power agreements that contain minimum purchase obligations. Entergy Louisiana has rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations. See Note 8 to the financial statements for discussion of Entergy Louisiana’s obligations under the Unit Power Sales Agreement and the Vidalia purchased power agreement.

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As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Louisiana pays distributions from its earnings at a percentage determined monthly.

2021 Solar Certification and the Geaux Green Option

In November 2021, Entergy Louisiana filed an application with the LPSC seeking certification of and approval for the addition of four new solar photovoltaic resources with a combined nameplate capacity of 475 megawatts (the 2021 Solar Portfolio) and the implementation of a new green tariff, the Geaux Green Option (Rider GGO). The 2021 Solar Portfolio consists of four resources that are expected to provide $242 million in net benefits to Entergy Louisiana’s customers. These resources, all of which would be constructed in Louisiana, include (i) the Vacherie Facility, a 150 megawatt resource in St. James Parish; (ii) the Sunlight Road Facility, a 50 megawatt resource in Washington Parish; (iii) the St. Jacques Facility, a 150 megawatt resource in St. James Parish; and (iv) the Elizabeth Facility, a 125 megawatt resource in Allen Parish. The St. Jacques Facility would be acquired through a build-own-transfer agreement; the remaining resources involve power purchase agreements. The Sunlight Road Facility and the Elizabeth Facility have estimated in service dates in 2024, and the Vacherie Facility and the St. Jacques Facility originally had estimated in service dates in 2025, but are now expected to be no sooner than 2027. The filing proposed to recover the costs of the power purchase agreements through the fuel adjustment clause and the formula rate plan and the acquisition costs through the formula rate plan.

The proposed Rider GGO is a voluntary rate schedule that will enhance Entergy Louisiana’s ability to help customers meet their sustainability goals by allowing customers to align some or all of their electricity requirements with renewable energy from the resources. Because subscription fees from Rider GGO participants are expected to help offset the cost of the resources, the design of Rider GGO also preserves the benefits of the 2021 Solar Portfolio for non-participants by providing them with the reliability and capacity benefits of locally-sited solar generation at a discounted price.

In March 2022 direct testimony from Walmart, the Louisiana Energy Users Group (LEUG), and the LPSC staff was filed. Each party recommended that the LPSC approve the resources proposed in Entergy Louisiana’s application, and the LPSC staff witness indicated that the process through which Entergy Louisiana solicited or obtained the proposals for the resources complied with applicable LPSC orders. The LPSC staff and LEUG’s witnesses made recommendations to modify the proposed Rider GGO and Entergy Louisiana’s proposed rate relief. In April 2022 the LPSC staff and LEUG filed cross-answering testimony concerning each other’s proposed modifications to Rider GGO and the proposed rate recovery. Entergy Louisiana filed rebuttal testimony in June 2022. In August 2022 the parties reached a settlement certifying the 2021 Solar Portfolio and approving implementation of Rider GGO. In September 2022 the LPSC approved the settlement. Following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities until the later of March 2023 or the completion of an environmental and economic impact study. In November 2023, St. James Parish lifted the moratorium and adopted an ordinance modifying the parish’s land use plan to establish solar as an approved land use and defining corresponding solar regulations. Entergy Louisiana is in discussions with the counterparties to the Vacherie and St. Jacques facilities regarding amendments to the respective agreements to address the impact of the St. James Parish ordinance, and the facilities are expected to reach commercial operation no sooner than 2027, depending upon agreement by the parties on the terms of the amendments. In September 2023, Entergy Louisiana reported to the LPSC that it also entered into amended agreements related to the Sunlight Road and Elizabeth facilities. Both facilities are still expected to achieve commercial operation in 2024.

2022 Solar Portfolio and Expansion of the Geaux Green Option

In February 2023, Entergy Louisiana filed an application with the LPSC seeking certification of the Iberville/Coastal Prairie facility, which will provide 175 MW of capacity through a PPA with a third party, and the Sterlington facility, a 49 MW self-build project located near the deactivated Sterlington power plant (the 2022 Solar Portfolio). Entergy Louisiana is seeking to include these resources within the portfolio supporting the Rider GGO

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rate schedule to help fulfill customer interest in access to renewable energy. Entergy Louisiana has requested the costs of these facilities, as offset by Rider GGO revenues, be deemed eligible for recovery in accordance with the terms of the formula rate plan and fuel adjustment clause rate mechanisms that exist at the time the facilities are placed into service. In January 2024, the parties filed an uncontested stipulated settlement agreement on the key issues in the case, which stated that the 2022 Solar Portfolio should be constructed, found that Entergy Louisiana’s proposed cost recovery mechanisms were appropriate, and confirmed the resources’ eligibility for inclusion in Rider GGO. The settlement was approved by the LPSC in January 2024. The Sterlington facility is expected to achieve commercial operation in January 2026.

Alternative RFP and Certification

In March 2023, Entergy Louisiana made the first phase of a bifurcated filing to seek approval from the LPSC for an alternative to the requests for proposals (RFP) process that would enable the acquisition of up to 3 GW of solar resources on a faster timeline than the current RFP and certification process allows. The initial phase of the filing established the need for the acquisition of additional resources and the need for an alternative to the RFP process. The second phase of the filing, which contains the details of the proposal for the alternative competitive procurement process and the information necessary to support certification, was filed in May 2023. In addition to the acquisition of up to 3 GW of solar resources, the filing also seeks approval of a new renewable energy credits-based tariff, Rider Geaux ZERO. Several parties have intervened, and a procedural schedule was established in May 2023 with a hearing scheduled for March 2024. In October 2023 the LPSC staff and intervenors filed testimony, with the LPSC staff supporting the amount of solar resources to be acquired and the alternative RFP process. The LPSC staff also supported, subject to certain recommendations, the proposed framework for evaluation and certification of the solar resources by the LPSC and the proposed tariff.

System Resilience and Storm Hardening

In December 2022, Entergy Louisiana filed an application with the LPSC seeking a public interest finding regarding Phase I of Entergy Louisiana’s Future Ready resilience plan and approval of a rider mechanism to recover the program’s costs. Phase I reflects the first five years of a ten-year resilience plan and includes investment of approximately $5 billion, including hardening investment, transmission dead-end structures, enhanced vegetation management, and telecommunications improvement. In April 2023 a procedural schedule was established with a hearing scheduled for January 2024. The LPSC staff and certain intervenors filed direct testimony in August, September, and October 2023. The LPSC staff filed cross-answering testimony in October 2023. The testimony largely supports implementation of some level of accelerated investment in resilience, but raises various issues related to the magnitude of the investment, the cost recovery mechanism applicable to the investment, and the ratemaking for the investment. In January 2024 the hearing in this matter was rescheduled to April 2024.

The LPSC had previously opened a formal rulemaking proceeding in December 2021 to investigate efforts to improve resilience of electric utility infrastructure. In April 2023 the LPSC staff issued a draft rule in the rulemaking proceeding related to a requirement to file a grid resilience plan. The procedural schedule entered in the rulemaking proceeding contemplated adoption of a final rule in October 2023, but this did not occur, and a new date has not been set. The LPSC also has pending rulemakings addressing issues related to pole viability and grid maintenance practices. In December 2023, in those rulemakings, the LPSC staff issued a report and recommendation proposing to impose significant new reporting and compliance obligations related to jurisdictional utilities’ distribution and transmission operations, including new obligations related to grid hardening plans, pole inspections, pole replacement, vegetation management, storm restoration plans, new reliability metrics, software for handling customer complaints and complaint resolution, required use of drone technology, and new penalties and incentives for reliability performance and for compliance with the new obligations. In February 2024, Entergy Louisiana and other parties filed comments on the LPSC staff’s report.

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Sources of Capital

Entergy Louisiana’s sources to meet its capital requirements include:

•internally generated funds;

•cash on hand;

•the Entergy system money pool;

•storm reserve escrow accounts;

•debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;

•capital contributions; and

•bank financing under new or existing facilities.

Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations, Entergy Louisiana expects to continue, when economically feasible, to retire higher-cost debt and replace it with lower-cost debt if market conditions permit.

All debt and common and preferred membership interest issuances by Entergy Louisiana require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in its bond indentures and other agreements. Entergy Louisiana has sufficient capacity under these tests to meet its foreseeable capital needs for the next twelve months and beyond.

Entergy Louisiana’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.

2023202220212020

(In Thousands)

($156,166)($226,114)$14,539$13,426

See Note 4 to the financial statements for a description of the money pool.

Entergy Louisiana has a credit facility in the amount of $350 million scheduled to expire in June 2028. The credit facility includes fronting commitments for the issuance of letters of credit against $15 million of the borrowing capacity of the facility. As of December 31, 2023, there were no cash borrowings and no letters of credit outstanding under the credit facility. In addition, Entergy Louisiana is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2023, $17.1 million in letters of credit were outstanding under Entergy Louisiana’s uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.

The Entergy Louisiana nuclear fuel company variable interest entities have two separate credit facilities, each in the amount of $105 million and scheduled to expire in June 2025. As of December 31, 2023, $46.6 million in loans were outstanding under the credit facility for the Entergy Louisiana River Bend nuclear fuel company variable interest entity. As of December 31, 2023, $29.5 million in loans were outstanding under the Entergy Louisiana Waterford nuclear fuel company variable interest entity credit facility. See Note 4 to the financial statements for additional discussion of the nuclear fuel company variable interest entity credit facilities.

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Entergy Louisiana obtained authorizations from the FERC through April 2025 for the following:

•short-term borrowings not to exceed an aggregate amount of $450 million at any time outstanding;

•long-term borrowings and security issuances; and

•borrowings by its nuclear fuel company variable interest entities.

See Note 4 to the financial statements for further discussion of Entergy Louisiana’s short-term borrowing limits.

Hurricane Ida

As discussed in Note 2 to the financial statements, in August 2020 and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of Entergy Louisiana’s service area. In February 2021 two winter storms (collectively, Winter Storm Uri) brought freezing rain and ice to Louisiana. In August 2021, Hurricane Ida caused extensive damage to Entergy Louisiana’s distribution and, to a lesser extent, transmission systems resulting in widespread power outages.

In April 2022, Entergy Louisiana filed an application with the LPSC relating to Hurricane Ida restoration costs. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by Hurricane Ida were estimated to be approximately $2.54 billion, including approximately $1.96 billion in capital costs and approximately $586 million in non-capital costs. Including carrying costs of $57 million through December 2022, Entergy Louisiana was seeking an LPSC determination that $2.60 billion was prudently incurred and, therefore, eligible for recovery from customers. As part of this filing, Entergy Louisiana also was seeking an LPSC determination that an additional $32 million in costs associated with the restoration of Entergy Louisiana’s electric facilities damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta as well as Winter Storm Uri was prudently incurred. This amount was exclusive of the requested $3 million in carrying costs through December 2022. In total, Entergy Louisiana was requesting an LPSC determination that $2.64 billion was prudently incurred and, therefore, eligible for recovery from customers. As discussed in Note 2 to the financial statements, in March 2022 the LPSC approved financing of a $1 billion storm escrow account from which funds were withdrawn to finance costs associated with Hurricane Ida restoration. In June 2022, Entergy Louisiana supplemented the application with a request regarding the financing and recovery of the recoverable storm restoration costs. Specifically, Entergy Louisiana requested approval to securitize its restoration costs pursuant to Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021. In October 2022 the LPSC staff recommended a finding that the requested storm restoration costs of $2.64 billion, including associated carrying costs of $59.1 million, were prudently incurred and eligible for recovery from customers. The LPSC staff further recommended approval of Entergy Louisiana’s plans to securitize these costs, net of the $1 billion in funds withdrawn from the storm escrow account described above. The parties negotiated and executed an uncontested stipulated settlement which was filed with the LPSC in December 2022. The settlement agreement contains the following key terms: $2.57 billion of restoration costs from Hurricane Ida, Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri were prudently incurred and eligible for recovery; carrying costs of $59.2 million were recoverable; and Entergy Louisiana was authorized to finance $1.657 billion utilizing the securitization process authorized by Act 55, as supplemented by Act 293. A procedural motion to consider the uncontested settlement at the December 2022 LPSC meeting did not pass and the settlement was not voted on. In January 2023 an ALJ with the LPSC conducted a settlement hearing to receive the uncontested settlement and supporting testimony into evidence and issued a report of proceedings, which allows the LPSC to consider the uncontested settlement without the procedural motion that did not pass in December. In January 2023, the LPSC approved the stipulated settlement subject to certain modifications. These modifications include the recognition of accumulated deferred income tax benefits related to damaged assets and system restoration costs as a reduction of the amount authorized to be financed utilizing the securitization process authorized by Act 55, as supplemented by Act 293, from $1.657 billion to $1.491 billion. These modifications did not affect the LPSC’s conclusion that all system restoration costs sought by Entergy Louisiana were reasonable and prudent. In February 2023 the Louisiana Bond Commission voted to authorize the Louisiana Local Government Facilities and Community Development Authority (LCDA) to issue the bonds authorized in the LPSC’s financing order.

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Entergy Louisiana, LLC and Subsidiaries

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In March 2023 the Hurricane Ida securitization financing closed, resulting in the issuance of approximately $1.491 billion principal amount of bonds by the LCDA and a remaining regulatory asset of $180 million to be recovered through the exclusion of the accumulated deferred income taxes related to damaged assets and system restoration costs from the determination of future rates. The securitization was authorized pursuant to the Louisiana Utilities Restoration Corporation Act, Part VIII of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021. The LCDA loaned the proceeds to the LURC. Pursuant to Act 293, the LURC contributed the net bond proceeds to a State legislatively authorized and LURC-sponsored trust, Restoration Law Trust II (the storm trust II).

Pursuant to Act 293, the net proceeds of the bonds were used by the storm trust II to purchase 14,576,757.48 Class B preferred, non-voting membership interest units (the preferred membership interests) issued by Entergy Finance Company, LLC, a majority owned indirect subsidiary of Entergy. Entergy Finance Company is required to make annual distributions (dividends) commencing on December 15, 2023 on the preferred membership interests issued to the storm trust II. These annual dividends received by the storm trust II will be distributed to Entergy Louisiana and the LURC, as beneficiaries of the storm trust II. Specifically, 1% of the annual dividends received by the storm trust II will be distributed to the LURC for the benefit of customers, and 99% will be distributed to Entergy Louisiana, net of storm trust expenses. The preferred membership interests have a stated annual cumulative cash dividend rate of 7.5% and a liquidation price of $100 per unit. The terms of the preferred membership interests include certain financial covenants to which Entergy Finance Company is subject. Semi-annual redemptions of the preferred membership interests, subject to certain conditions, are expected to occur over the next 15 years.

Entergy and Entergy Louisiana do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA. The bonds are secured by system restoration property, which is the right granted by law to the LURC to collect a system restoration charge from customers. The system restoration charge is adjusted at least semi-annually to ensure that it is sufficient to service the bonds. Entergy Louisiana collects the system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee. Entergy Louisiana began collecting the system restoration charge effective with the first billing cycle of April 2023 and the system restoration charge is expected to remain in place for up to 15 years. Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as a billing and collection agent for the LCDA and the LURC. In the remote possibility that the system restoration charge, as well as any funds in the excess subaccount and funds in the debt service reserve account, are insufficient to service the bonds resulting in a payment default, the storm trust II is required to liquidate Entergy Finance Company preferred membership interests in an amount equal to what would be required to cure the default. The estimated value of this indirect guarantee is immaterial.

From the proceeds from the issuance of the preferred membership interests, Entergy Finance Company loaned approximately $1.5 billion to Entergy, which was indirectly contributed to Entergy Louisiana as a capital contribution.

As discussed in Note 3 to the financial statements, the securitization resulted in recognition of a net reduction of income tax expense of approximately $133 million, after taking into account a provision for uncertain tax positions, by Entergy Louisiana. Entergy’s recognition of reduced income tax expense was offset by other tax charges resulting in a net reduction of income tax expense of $129 million, after taking into account a provision for uncertain tax positions. In recognition of its obligations described in an LPSC ancillary order issued as part of the securitization regulatory proceeding, Entergy Louisiana recorded in first quarter 2023 a $103 million ($76 million net-of-tax) regulatory charge and a corresponding regulatory liability to reflect its obligation to provide credits to its customers.

As discussed in Note 6 and Note 17 to the financial statements, Entergy Louisiana consolidates the storm trust II as a variable interest entity and the LURC’s 1% beneficial interest is presented as noncontrolling interest in

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the financial statements. In first quarter 2023, Entergy Louisiana recorded a charge of $14.6 million in other income to reflect the LURC’s beneficial interest in the storm trust II.

Nelson Industrial Steam Company

Entergy Louisiana is a partner in the Nelson Industrial Steam Company (NISCO) partnership which owns two petroleum coke generating units. In April 2023 these generating units suspended operations in the MISO market, and Entergy Louisiana currently is working to wind up the NISCO partnership, which will ultimately result in ownership of the generating units transferring to Entergy Louisiana. In November 2023 the FERC issued an order providing Section 203 of the Federal Power Act approval for any subsequent transfer of the facilities to Entergy Louisiana. Entergy Louisiana is evaluating the effect of the transaction on its results of operations, cash flows, and financial condition, but at this time does not expect the effect to be material.

State and Local Rate Regulation and Fuel-Cost Recovery

The rates that Entergy Louisiana charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Louisiana is regulated, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the LPSC, is primarily responsible for approval of the rates charged to customers.

Retail Rates - Electric

Filings with the LPSC

2017 Formula Rate Plan Filing

In June 2018, Entergy Louisiana filed its formula rate plan evaluation report for its 2017 calendar year operations. The 2017 test year evaluation report produced an earned return on equity of 8.16%, due in large part to revenue-neutral realignments to other recovery mechanisms. Without these realignments, the evaluation report produces an earned return on equity of 9.88% and a resulting base rider formula rate plan revenue increase of $4.8 million. Excluding the Tax Cuts and Jobs Act credits provided for by the tax reform adjustment mechanisms, total formula rate plan revenues were further increased by a total of $98 million as a result of the evaluation report due to adjustments to the additional capacity and MISO cost recovery mechanisms of the formula rate plan, and implementation of the transmission recovery mechanism. In August 2018, Entergy Louisiana filed a supplemental formula rate plan evaluation report to reflect changes from the 2016 test year formula rate plan proceedings, a decrease to the transmission recovery mechanism to reflect lower actual capital additions, and a decrease to evaluation period expenses to reflect the terms of a new power sales agreement. Based on the August 2018 update, Entergy Louisiana recognized a total decrease in formula rate plan revenue of approximately $17.6 million. Results of the updated 2017 evaluation report filing were implemented with the September 2018 billing month subject to refund and review by the LPSC staff and intervenors. In accordance with the terms of the formula rate plan, in September 2018 the LPSC staff filed its report of objections/reservations and intervenors submitted their responses to Entergy Louisiana’s original formula rate plan evaluation report and supplemental compliance updates. In August 2021 the LPSC staff issued a letter updating its objections/reservations for the 2017 test year formula rate plan evaluation report. In its letter, the LPSC staff reiterated its original objections/reservations. The LPSC staff further reserved its rights for future proceedings and to dispute future proposed adjustments to the 2017 test year formula rate plan evaluation report. The LPSC staff withdrew all other objections/reservations.

In November 2023 the LPSC approved a global settlement which resolved all outstanding issues related to the 2017, 2018, and 2019 formula rate plan filings and resolved certain issues with respect to the 2020 and 2021 formula rate plan filings. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement.

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2018 Formula Rate Plan Filing

In May 2019, Entergy Louisiana filed its formula rate plan evaluation report for its 2018 calendar year operations. The 2018 test year evaluation report produced an earned return on common equity of 10.61% leading to a base rider formula rate plan revenue decrease of $8.9 million. While base rider formula rate plan revenue decreased as a result of this filing, overall formula rate plan revenues increased by approximately $118.7 million. This outcome was primarily driven by a reduction to the credits previously flowed through the tax reform adjustment mechanism and an increase in the transmission recovery mechanism, partially offset by reductions in the additional capacity mechanism revenue requirements and extraordinary cost items. The filing was subject to review by the LPSC. Resulting rates were implemented in September 2019, subject to refund.

Several parties intervened in the proceeding and the LPSC staff filed its report of objections/reservations in accordance with the applicable provisions of the formula rate plan. In August 2021 the LPSC staff issued a letter updating its objections/reservations for the 2018 test year formula rate plan evaluation report. In its letter, the LPSC staff reiterated its original objection/reservation pertaining to test year expenses billed from Entergy Services to Entergy Louisiana and outstanding issues from the 2017 test year formula rate plan evaluation report. The LPSC staff withdrew all other objections/reservations.

Commercial operation at Lake Charles Power Station commenced in March 2020. In March 2020, Entergy Louisiana filed an update to its 2018 formula rate plan evaluation report to include the estimated first-year revenue requirement of $108 million associated with the Lake Charles Power Station. The resulting interim adjustment to rates became effective with the first billing cycle of April 2020.

In November 2023 the LPSC approved a global settlement which resolved all outstanding issues related to the 2017, 2018, and 2019 formula rate plan filings and resolved certain issues with respect to the 2020 and 2021 formula rate plan filings. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement.

2019 Formula Rate Plan Filing

In May 2020, Entergy Louisiana filed with the LPSC its formula rate plan evaluation report for its 2019 calendar year operations. The 2019 test year evaluation report produced an earned return on common equity of 9.66%. As such, no change to base rider formula rate plan revenue is required. Although base rider formula rate plan revenue did not change as a result of this filing, overall formula rate plan revenues increased by approximately $103 million. This outcome is driven by the removal of prior year credits associated with the sale of the Willow Glen Power Station and an increase in the transmission recovery mechanism. Also contributing to the overall change was an increase in legacy formula rate plan revenue requirements driven by legacy Entergy Louisiana capacity cost true-ups and higher annualized legacy Entergy Gulf States Louisiana revenues due to higher billing determinants, offset by reductions in MISO cost recovery mechanism and tax reform adjustment mechanism revenue requirements. In August 2020 the LPSC staff submitted a list of items for which it needs additional information to confirm the accuracy and compliance of the 2019 test year evaluation report. The LPSC staff objected to a proposed revenue neutral adjustment regarding a certain rider as being beyond the scope of permitted formula rate plan adjustments. Rates reflected in the May 2020 filing, with the exception of a revenue neutral rider adjustment, and as updated in an August 2020 filing, were implemented in September 2020, subject to refund. In August 2021 the LPSC staff issued a letter updating its objections/reservations for the 2019 test year formula rate plan filing. In its letter, the LPSC staff disputed Entergy Louisiana’s exclusion of approximately $251 thousand of interest income allocated from Entergy Operations and Entergy Services to Entergy Louisiana to the extent that there are other adjustments that would move Entergy Louisiana out of the formula rate plan deadband. The LPSC staff reserved the right to further contest the issue in future proceedings. The LPSC staff further reserved outstanding issues from the 2017 and 2018 formula rate plan evaluation reports and withdrew all other remaining objections/reservations.

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In November 2023 the LPSC approved a global settlement which resolved all outstanding issues related to the 2017, 2018, and 2019 formula rate plan filings and resolved certain issues with respect to the 2020 and 2021 formula rate plan filings. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement.

Request for Extension and Modification of Formula Rate Plan

In May 2020, Entergy Louisiana filed with the LPSC its application for authority to extend its formula rate plan. In its application, Entergy Louisiana sought to maintain a 9.8% return on equity, with a bandwidth of 60 basis points above and below the midpoint, with a first-year midpoint reset. The parties reached a settlement in April 2021 regarding Entergy Louisiana’s proposed formula rate plan extension. In May 2021 the LPSC approved the uncontested settlement. Key terms of the settlement include: a three year term (test years 2020, 2021, and 2022) covering a rate-effective period of September 2021 through August 2024; a 9.50% return on equity, with a smaller, 50 basis point deadband above and below (9.0%-10.0%); elimination of sharing if earnings are outside the deadband; a $63 million rate increase for test year 2020 (exclusive of riders); continuation of existing riders (transmission, additional capacity, etc.); addition of a distribution recovery mechanism permitting $225 million per year of distribution investment above a baseline level to be recovered dollar for dollar; modification of the tax mechanism to allow timely rate changes in the event the federal corporate income tax rate is changed from 21%; a cumulative rate increase limit of $70 million (exclusive of riders) for test years 2021 and 2022; and deferral of up to $7 million per year in 2021 and 2022 of expenditures on vegetation management for outside of right of way hazard trees.

2020 Formula Rate Plan Filing

In June 2021, Entergy Louisiana filed its formula rate plan evaluation report for its 2020 calendar year operations. The 2020 test year evaluation report produced an earned return on common equity of 8.45%, with a base formula rate plan revenue increase of $63 million. Certain reductions in formula rate plan revenue driven by lower sales volumes, reductions in capacity cost and net MISO cost, and higher credits resulting from the Tax Cuts and Jobs Act offset the base formula rate plan revenue increase, leading to a net increase in formula rate plan revenue of $50.7 million. The report also included multiple new adjustments to account for, among other things, the calculation of distribution recovery mechanism revenues. The effects of the changes to total formula rate plan revenue were different for each legacy company, primarily due to differences in the legacy companies’ capacity cost changes, including the effect of true-ups. Legacy Entergy Louisiana formula rate plan revenues increased by $27 million and legacy Entergy Gulf States Louisiana formula rate plan revenues increased by $23.7 million. Subject to LPSC review, the resulting changes became effective for bills rendered during the first billing cycle of September 2021, subject to refund. Discovery commenced in the proceeding. In August 2021, Entergy Louisiana submitted an update to its evaluation report to account for various changes. Relative to the June 2021 filing, the total formula rate plan revenue increased by $14.2 million to an updated total of $64.9 million. Legacy Entergy Louisiana formula rate plan revenues increased by $32.8 million and legacy Entergy Gulf States Louisiana formula rate plan revenues increased by $32.1 million. The results of the 2020 test year evaluation report bandwidth calculation were unchanged as there was no change in the earned return on common equity of 8.45%. In September 2021 the LPSC staff filed a letter with a general statement of objections/reservations because it had not completed its review and indicated it would update the letter once its review was complete. Should the parties be unable to resolve any objections, those issues will be set for hearing, with recovery of the associated costs subject to refund.

In November 2023 the LPSC approved a global settlement which resolved all outstanding issues related to the 2017, 2018, and 2019 formula rate plan filings and resolved certain issues with respect to the 2020 and 2021 formula rate plan filings. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement.

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2021 Formula Rate Plan Filing

In May 2022, Entergy Louisiana filed its formula rate plan evaluation report for its 2021 calendar year operations. The 2021 test year evaluation report produced an earned return on common equity of 8.33%, with a base formula rate plan revenue increase of $65.3 million. Other increases in formula rate plan revenue driven by reductions in Tax Cut and Jobs Act credits and additions to transmission and distribution plant in service reflected through the transmission recovery mechanism and distribution recovery mechanism are partly offset by an increase in net MISO revenues, leading to a net increase in formula rate plan revenue of $152.9 million. The effects of the changes to total formula rate plan revenue are different for each legacy company, primarily due to differences in the legacy companies’ capacity cost changes, including the effect of true-ups. Legacy Entergy Louisiana formula rate plan revenues increased by $86 million and legacy Entergy Gulf States Louisiana formula rate plan revenues increased by $66.9 million. In August 2022 the LPSC staff filed a list of objections/reservations, including outstanding issues from the test years 2017-2020 formula rate plan filings, utilizing the extraordinary cost mechanism to address one-time changes such as state tax rate changes, and failing to include an adjustment for revenues not received as a result of Hurricane Ida. Subject to LPSC review, the resulting changes to formula rate plan revenues became effective for bills rendered during the first billing cycle of September 2022, subject to refund.

In November 2023 the LPSC approved a global settlement which resolved all outstanding issues related to the 2017, 2018, and 2019 formula rate plan filings and resolved certain issues with respect to the 2020 and 2021 formula rate plan filings. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement.

2022 Formula Rate Plan Filing

In May 2023, Entergy Louisiana filed its formula rate plan evaluation report for its 2022 calendar year operations. The 2022 test year evaluation report produced an earned return on common equity of 8.33%, requiring an approximately $70.7 million increase to base rider revenue. Due to a cap for the 2021 and 2022 test years, however, base rider formula rate plan revenues are only being increased by approximately $4.9 million, resulting in a revenue deficiency of approximately $65.9 million and providing for prospective return on common equity opportunity of approximately 8.38%. Other changes in formula rate plan revenue driven by increases in capacity costs, primarily legacy capacity costs, additions eligible for recovery through the transmission recovery mechanism and distribution recovery mechanism, and higher sales during the test period are offset by reductions in net MISO costs as well as credits for FERC-ordered refunds. Also included in the 2022 test year distribution recovery mechanism revenue requirement is a $6 million credit relating to the distribution recovery mechanism performance accountability standards and requirements. In total, the net increase in formula rate plan revenues, including base formula rate plan revenues inside the formula rate plan bandwidth and subject to the cap, as well as other formula rate plan revenues outside of the bandwidth, is $85.2 million. In August 2023 the LPSC staff filed a list of objections/reservations, including outstanding issues from the test years 2017-2021 formula rate plan filings, the calculation of certain refunds from System Energy, and certain calculations relating to the tax reform adjustment mechanism. Subject to LPSC review, the resulting net increase in formula rate plan revenues of $85.2 million became effective for bills rendered during the first billing cycle of September 2023, subject to refund.

2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request

In August 2023, Entergy Louisiana filed an application for approval of a regulatory blueprint necessary for it to strengthen the electric grid for the State of Louisiana, which contains a dual-path request to update rates through either: (1) extension of Entergy Louisiana’s current formula rate plan (with certain modifications) for three years (the Rate Mitigation Proposal), which is Entergy Louisiana’s recommended path; or (2) implementation of rates resulting from a cost-of-service study (the Rate Case path). The application complies with Entergy Louisiana’s previous formula rate plan extension order requiring that for Entergy Louisiana to obtain another extension of its formula rate plan that included a rate reset, Entergy Louisiana would need to submit a full cost-of-

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service/rate case. Entergy Louisiana’s filing supports the need to extend Entergy Louisiana’s formula rate plan with credit supportive mechanisms to facilitate investment in the distribution, transmission, and generation functions.

The Rate Case path proposes a 2024-2026 test year formula rate plan with an initial revenue requirement increase of $430 million, net of $17 million of one-time credits, and a return on common equity of 10.5%. Depreciation rates would be updated for all asset classes. The Rate Mitigation Proposal proposes a 2023-2025 test year formula rate plan with an expected initial revenue requirement increase of $173 million, also net of $17 million of one-time credits, based on a 2023 formula rate plan test year, and a return on common equity of 10.0%. Depreciation rates would be updated only for nuclear assets and would be phased in over three years.

Under both paths, Entergy Louisiana’s filing proposes removing the cap on amounts allowed to be recovered through the distribution recovery mechanism and continuing the distribution recovery mechanism performance accountability targets, which tie Entergy Louisiana’s ability to fully recover its distribution recovery mechanism investments to its reliability performance. Entergy Louisiana’s filing also includes new customer-centric programs specifically focused on affordability, including reducing late fees and certain other fees assessed to customers, lowering additional facilities charge rates, providing eligible low-income seniors with monthly discounts on their electric bill, and adding new voluntary customer options to support new transportation electrification technologies. A status conference was held in October 2023 at which a procedural schedule was adopted that includes three technical conferences, the last of which is in March 2024, and a hearing date in August 2024.

Formula Rate Plan Global Settlement

In October 2023 the LPSC staff and Entergy Louisiana reached a global settlement which resolved all outstanding issues related to the 2017, 2018, and 2019 formula rate plan filings and resolved certain issues with respect to the 2020 and 2021 formula rate plan filings. The settlement was approved by the LPSC in November 2023. The settlement resulted in a one-time cost of service credit to customers of $5.8 million, allowed Entergy Louisiana to retain approximately $6.2 million of securitization over-collection as recovery of a regulatory asset associated with late fees related to the 2016 Baton Rouge flood, and resulted in Entergy Louisiana recording the reversal of a $105.6 million regulatory liability, associated with the Hurricane Isaac securitization, recognized in 2017 as a result of the Tax Cuts and Jobs Act. See Note 3 to the financial statements for further discussion of the reversal of the regulatory liability.

Investigation of Costs Billed by Entergy Services

In November 2018 the LPSC issued a notice of proceeding initiating an investigation into costs incurred by Entergy Services that are included in the retail rates of Entergy Louisiana. As stated in the notice of proceeding, the LPSC observed an increase in capital construction-related costs incurred by Entergy Services. Discovery was issued and included efforts to seek highly detailed information on a broad range of matters unrelated to the scope of the audit. There has been no further activity in the investigation since May 2019.

Fuel and purchased power cost recovery

Entergy Louisiana recovers electric fuel and purchased power costs for the billing month based upon the level of such costs incurred two months prior to the billing month. Entergy Louisiana’s purchased gas adjustments include estimates for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.

In February 2021, Entergy Louisiana incurred extraordinary fuel costs associated with the February 2021 winter storms. To mitigate the effect of these costs on customer bills, in March 2021, Entergy Louisiana requested and the LPSC approved the deferral and recovery of $166 million in incremental fuel costs over five months beginning in April 2021. The incremental fuel costs remain subject to review for reasonableness and eligibility for recovery through the fuel adjustment clause mechanism. The final amount of incremental fuel costs is subject to

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change through the resettlement process. At its April 2021 meeting, the LPSC authorized its staff to review the prudence of the February 2021 fuel costs incurred by all LPSC-jurisdictional utilities, including both gas and electric utilities. At its June 2021 meeting, the LPSC approved the hiring of consultants to assist its staff in this review. In May 2022 the LPSC staff issued an audit report regarding Entergy Louisiana’s fuel adjustment clause charges (for its electric operations) recommending no financial disallowances, but including several prospective recommendations. Responsive testimony was filed by one intervenor and the parties agreed to suspend any procedural schedule and move toward settlement discussions to close the matter. Also in May 2022 the LPSC staff issued an audit report regarding Entergy Louisiana’s purchased gas adjustment charges (for its gas operations) that did not propose any financial disallowances. The LPSC staff and Entergy Louisiana submitted a joint report on the audit report and draft order to the LPSC concluding that Entergy Louisiana’s gas distribution operations and fuel costs were not significantly adversely affected by the February 2021 winter storms and the resulting increase in natural gas prices. The LPSC issued an order approving the joint report in October 2022.

In March 2021 the LPSC staff provided notice of an audit of Entergy Louisiana’s purchased gas adjustment clause filings covering the period January 2018 through December 2020. The audit included a review of the reasonableness of charges flowed through Entergy Louisiana’s purchased gas adjustment clause for that period. In August 2023 the LPSC submitted its audit report and found that materially all costs recovered through the purchased gas adjustment filings were reasonable and eligible for recovery through the purchased gas adjustment clause. The LPSC approved the report in December 2023.

To mitigate high electric bills, primarily driven by high summer usage and elevated gas prices, Entergy Louisiana deferred approximately $225 million of fuel expense incurred in April, May, June, July, August, and September 2022 (as reflected on June, July, August, September, October, and November 2022 bills). These deferrals were included in the over/under calculation of the fuel adjustment clause, which is intended to recover the full amount of the costs included on a rolling twelve-month basis.

In January 2023 the LPSC staff provided notice of an audit of Entergy Louisiana’s purchased gas adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s purchased gas adjustment clause for the period from 2021 through 2022. Discovery is ongoing, and no audit report has been filed.

In January 2023 the LPSC staff provided notice of an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2020 through 2022. Discovery is ongoing, and no audit report has been filed.

COVID-19 Orders

In April 2020 the LPSC issued an order authorizing utilities to record as a regulatory asset expenses incurred from the suspension of disconnections and collection of late fees imposed by LPSC orders associated with the COVID-19 pandemic. In addition, utilities may seek future recovery, subject to LPSC review and approval, of losses and expenses incurred due to compliance with the LPSC’s COVID-19 orders. The suspension of late fees and disconnects for non-pay was extended until the first billing cycle after July 16, 2020. In January 2021, Entergy Louisiana resumed disconnections for customers in all customer classes with past-due balances that had not made payment arrangements. Utilities seeking to recover the regulatory asset must formally petition the LPSC to do so, identifying the direct and indirect costs for which recovery is sought. Any such request is subject to LPSC review and approval. In April 2023, Entergy Louisiana filed an application proposing to utilize approximately $1.6 billion in certain low interest debt to generate earnings to apply toward the reduction of the COVID-19 regulatory asset, as well as to conduct additional outside right-of-way vegetation management activities and fund the minor storm reserve account. In that filing, Entergy Louisiana proposed to delay repayment of certain shorter-term first mortgage bonds that were issued to finance storm restoration costs until the costs could be securitized, and to invest the funds that otherwise would be used to repay those bonds in the money pool to take advantage of the spread between prevailing interest rates on investments in the money pool and the interest rates on the bonds. The LPSC

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approved Entergy Louisiana’s requested relief in June 2023. A subsequent filing will be required to permit the LPSC to review the COVID-19 regulatory asset. As of December 31, 2023, Entergy Louisiana had a regulatory asset of $47.8 million for costs associated with the COVID-19 pandemic and a regulatory liability of $36.8 million for the deferred earnings related to the approximately $1.6 billion in low interest debt.

Net Metering Rulemaking

In September 2019 the LPSC issued an order modifying its rules regarding net metering installations. Among other things, the rule provides for 2-channel billing for net metering with excess energy put to the grid being compensated at the utility’s avoided cost. However, the rule does provide that net meter installations in place as of December 31, 2019 will be subject to 1:1 net metering with excess energy put to the grid being compensated at the full retail rate for a period of 15 years (through December 31, 2034), after which those installations will be subject to 2-channel billing. The rule also eliminates the existing limit on the cumulative number of net meter installations.

Industrial and Commercial Customers

Entergy Louisiana’s large industrial and commercial customers continually explore ways to reduce their energy costs. In particular, cogeneration is an option available to a portion of Entergy Louisiana’s industrial customer base. Entergy Louisiana responds by working with industrial and commercial customers and negotiating electric service contracts to provide competitive rates that match specific customer needs and load profiles. Entergy Louisiana actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand, from both new and existing customers.

Federal Regulation

See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.

Nuclear Matters

Entergy Louisiana owns and, through an affiliate, operates the River Bend and Waterford 3 nuclear generating plants and is, therefore, subject to the risks related to such ownership and operation. These include risks related to: the use, storage, and handling and disposal of high-level and low-level radioactive materials; the substantial financial requirements, both for capital investments and operational needs, including the financial requirements to address emerging issues related to equipment reliability, to position Entergy Louisiana’s nuclear fleet to meet its operational goals; the performance and capacity factors of these nuclear plants; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license amendments, and decommissioning; the availability of interim or permanent sites for the disposal of spent nuclear fuel and nuclear waste, including the fees charged for such disposal; the sufficiency of nuclear decommissioning trust fund assets and earnings to complete decommissioning of each site when required; and limitations on the amounts of insurance recoveries for losses in connection with nuclear plant operations and catastrophic events such as a nuclear accident. In the event of an unanticipated early shutdown of River Bend or Waterford 3, Entergy Louisiana may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. Waterford 3’s operating license expires in 2044 and River Bend’s operating license expires in 2045.

NRC Reactor Oversight Process

The NRC’s Reactor Oversight Process is a program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response. The NRC evaluates plant performance by analyzing two distinct inputs: inspection findings resulting from the NRC’s

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inspection program and performance indicators reported by the licensee. The evaluations result in the placement of each plant in one of the NRC’s Reactor Oversight Process Action Matrix columns: “licensee response column,” or Column 1, “regulatory response column,” or Column 2, “degraded cornerstone column,” or Column 3, “multiple/repetitive degraded cornerstone column,” or Column 4, and “unacceptable performance,” or Column 5. Plants in Column 1 are subject to normal NRC inspection activities. Plants in Column 2, Column 3, or Column 4 are subject to progressively increasing levels of inspection by the NRC with, in general, progressively increasing levels of associated costs. Continued plant operation is not permitted for plants in Column 5. Waterford 3 is currently in Column 1, and River Bend is currently in Column 2.

In July 2023 the NRC placed River Bend in Column 2, effective April 2023, based on failure to inspect wiring associated with the high pressure core spray system. In August 2023 the NRC issued a finding and notice of violation related to a radiation monitor calibration issue at River Bend. In December 2023, River Bend successfully completed the inspection on the high pressure core spray system issue and in February 2024, River Bend successfully completed the supplemental inspection for the radiation monitor calibration issue involving radiation monitor calibrations. River Bend will remain in Column 2 pending receipt of the formal report on the inspection, which is expected in first quarter 2024.

Environmental Risks

Entergy Louisiana’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Louisiana is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Critical Accounting Estimates

The preparation of Entergy Louisiana’s financial statements in conformity with GAAP requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in these assumptions and measurements could produce estimates that would have a material effect on the presentation of Entergy Louisiana’s financial position, results of operations, or cash flows.

Nuclear Decommissioning Costs

See “Nuclear Decommissioning Costs” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.

Utility Regulatory Accounting

See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.

Taxation and Uncertain Tax Positions

See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.

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Qualified Pension and Other Postretirement Benefits

Entergy Louisiana’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are affected by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.

Cost Sensitivity

The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).

Actuarial AssumptionChange in AssumptionImpact on 2024 Qualified Pension CostImpact on 2023 Qualified Projected Benefit Obligation

Increase/(Decrease)

Discount rate(0.25%)$1,016$28,165

Rate of return on plan assets(0.25%)$2,739$—

Rate of increase in compensation0.25%$1,143$6,017

The following chart reflects the sensitivity of postretirement benefits cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).

Actuarial AssumptionChange in AssumptionImpact on 2024 Postretirement Benefits CostImpact on 2023 Accumulated Postretirement Benefit Obligation

Increase/(Decrease)

Discount rate(0.25%)$324$4,287

Health care cost trend0.25%$559$2,905

Each fluctuation above assumes that the other components of the calculation are held constant.

Costs and Employer Contributions

Total qualified pension cost for Entergy Louisiana in 2023 was $69.5 million, including $40.4 million in settlement costs. Entergy Louisiana anticipates 2024 qualified pension cost to be $10.7 million. Entergy Louisiana contributed $44.6 million to its qualified pension plans in 2023 and estimates pension contributions will be approximately $48.4 million in 2024, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024 valuations are completed, which is expected by April 1, 2024.

Total postretirement health care and life insurance benefit costs for Entergy Louisiana in 2023 were $1.4 million. Entergy Louisiana expects 2024 postretirement health care and life insurance benefit income of approximately $701 thousand. Entergy Louisiana contributed $20.5 million to its other postretirement plans in 2023 and estimates that 2024 contributions will be approximately $15 million.

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Other Contingencies

See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.

New Accounting Pronouncements

See the “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the member and Board of Directors of

Entergy Louisiana, LLC and Subsidiaries

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Entergy Louisiana, LLC and Subsidiaries (the “Company”) as of December 31, 2023 and 2022, the related consolidated statements of income, comprehensive income, cash flows, and changes in equity (pages 368 through 374 and applicable items in pages 47 through 238), for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Rate and Regulatory Matters — Entergy Louisiana, LLC and Subsidiaries — Refer to Note 2 to the financial statements

Critical Audit Matter Description

The Company is subject to rate regulation by the Louisiana Public Service Commission (the “LPSC”), which has jurisdiction with respect to the rates of electric companies in Louisiana, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.

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The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the LPSC and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the LPSC and the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.

We identified the impact of rate regulation as a critical audit matter due to the judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs, and refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the LPSC and the FERC, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities involved specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and auditor judgment to evaluate management estimates and the subjectivity of audit evidence.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertainty of future decisions by the LPSC and the FERC, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities included the following, among others:

•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

•We read relevant regulatory orders issued by the LPSC and the FERC for the Company to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the LPSC’s and the FERC’s treatment of similar costs under similar circumstances. We evaluated external information and compared to management’s recorded regulatory asset and liability balances for completeness.

•For regulatory matters in process, we inspected the Company’s filings with the LPSC and the FERC and orders issued, and considered the filings with the LPSC and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.

•We obtained an analysis from management and support from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order, to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.

•We obtained representation from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management’s assertion that amounts are probable of recovery, refund, or a future reduction in rates.

Securitization Financing — Storm Cost Recovery Filings with Retail Regulators — Entergy Louisiana, LLC and Subsidiaries — Refer to Note 2 to the financial statements

Critical Audit Matter Description

Hurricane Ida in 2021 caused significant damage to portions of the Company’s service area within the state of Louisiana. In January 2023, the LPSC issued a Financing Order authorizing financing of $1.491 billion of system restoration costs utilizing the securitization process authorized by Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021 (“Act 55, as supplemented by Act 293”). In March 2023, the securitization financing closed, resulting in the issuance of $1.491 billion principal amount bonds by

365

Louisiana Local Government Environmental Facilities and Community Development Authority (“LCDA”), a political subdivision of the State of Louisiana. The LCDA loaned the proceeds to the Louisiana Utilities Restoration Corporation (“LURC”), and the LURC contributed the net bond proceeds to a State legislatively authorized and LURC-sponsored trust, Restoration Law Trust II (the “storm trust II”). The Company and the LURC each hold beneficial interests in the storm trust II.

The Company does not report the bonds issued by the LCDA on its balance sheet because the bonds are the obligation of the LCDA. The bonds are secured by system restoration property, which is the right granted by law to the LURC to collect a system restoration charge from customers. The Company collects the system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee. The Company does not report the collection of system restoration charges as revenue because the Company is merely acting as a billing and collection agent for the LCDA and the LURC. In the remote possibility that the system restoration charge, as well as any funds in the excess subaccount and funds in the debt service reserve account, are insufficient to service the bonds resulting in a payment default, the storm trust II is required to liquidate Entergy Finance Company preferred interests in an amount equal to what would be required to cure the default. The estimated value of this indirect guarantee is immaterial. The Company consolidates the storm trust II as a variable interest entity and the LURC’s 1% beneficial interest is shown as a noncontrolling interest in the financial statements.

We identified management’s conclusion that the bonds issued by the LCDA are the obligation of the LCDA as a critical audit matter due to the judgments made by management to support its conclusion. Auditing management’s judgments involved especially subjective judgment and specialized knowledge of accounting for securitization financing transactions.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the Act 55, as supplemented by Act 293, securitization financing included the following, among others:

•We tested the effectiveness of management’s controls over the evaluation of the accounting impact of this securitization financing transaction, including the conclusion that the bonds issued by the LCDA are the obligation of the LCDA.

•We evaluated the Company’s disclosures related to the impacts of the Act 55, as supplemented by Act 293, securitization financing, including the balances recorded.

•We read relevant regulatory and financing orders issued by the LPSC for the Company, the LURC, and the LCDA, and evaluated the external information to compare to management’s conclusions.

•We obtained an analysis from management and support from the Company’s internal and external legal counsel regarding the legal status of the bonds issued by the LCDA and the system restoration property granted to the LURC to assess management’s assertion that the bonds issued by the LCDA are the obligation of the LCDA.

•With the assistance of professionals in our firm having expertise and experience in addressing the accounting for securitization financing transactions by regulated utilities, we evaluated the Company’s conclusion, including the conclusion that the bonds issued by the LCDA are the obligation of the LCDA.

Uncertain Tax Positions — Entergy Louisiana, LLC and Subsidiaries — Refer to Note 3 to the financial statements

Critical Audit Matter Description

The Company accounts for uncertain income tax positions under a two-step approach with a more likely-than-not recognition threshold and a measurement approach based on the largest amount of tax benefit that is greater than fifty percent likely of being realized upon settlement. The Company has uncertain tax positions which require management to make judgments and assumptions to determine whether available information supports the assertion that the recognition threshold is met, particularly related to the technical merits and facts and circumstances of each position, as well as the probability of different potential outcomes. These uncertain tax positions could be significantly affected by audits by taxing authorities of the tax positions and changes to relevant tax law. There is an uncertain tax position related to the March 2023 securitization financing that provided for a tax benefit in the first quarter of 2023 of approximately $129 million.

Given the judgments made by management, we identified management’s conclusion that the securitization uncertain tax position met the more-likely-than-not recognition threshold as a critical audit matter. Auditing management’s

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judgments regarding this uncertain tax position involved specialized knowledge of uncertain tax positions and auditor judgment to evaluate the subjectivity of audit evidence.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the securitization uncertain tax position included the following, among others:

•We tested the effectiveness of controls related to the securitization uncertain tax position, including those over the recognition and measurement of the income tax benefit.

•We evaluated the Company’s disclosures, and the balances recorded, related to the securitization uncertain tax position.

•We evaluated the methods and assumptions used by management to estimate the uncertain tax position by testing the underlying data that served as the basis for the uncertain tax position.

•With the assistance of our income tax specialists, we tested the technical merits of the securitization uncertain tax position and management’s key estimates and judgments made by:

•Assessing the technical merits of the uncertain tax position by comparing to similar cases filed with the Internal Revenue Service.

•Obtaining an opinion from the Company’s external legal counsel regarding certain federal income tax consequences related to the Act 55, as supplemented by Act 293, securitization financing and evaluating whether the analysis was consistent with our interpretation of the relevant laws and circumstances.

•Considering the impact of changes or settlements in the tax environment on management’s methods and assumptions used to estimate the uncertain tax position.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 23, 2024

We have served as the Company’s auditor since 2001.

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ENTERGY LOUISIANA, LLC AND SUBSIDIARIES

CONSOLIDATED INCOME STATEMENTS

For the Years Ended December 31,

202320222021

(In Thousands)

OPERATING REVENUES

Electric$5,073,239 $6,246,933 $4,994,459

Natural gas74,531 91,835 73,989

TOTAL5,147,770 6,338,768 5,068,448

OPERATING EXPENSES

Operation and Maintenance:

Fuel, fuel-related expenses, and gas purchased for resale1,080,485 2,002,456 1,302,291

Purchased power654,721 1,076,715 768,546

Nuclear refueling outage expenses63,429 59,698 49,373

Other operation and maintenance1,097,233 1,139,605 1,034,427

Decommissioning75,962 72,122 68,575

Taxes other than income taxes245,191 241,908 224,079

Depreciation and amortization726,389 695,204 656,132

Other regulatory charges (credits) - net41,209 148,871 38,245

TOTAL3,984,619 5,436,579 4,141,668

OPERATING INCOME1,163,151 902,189 926,780

OTHER INCOME

Allowance for equity funds used during construction32,160 26,252 28,648

Interest and investment income (loss)90,316 (69,144)154,606

Interest and investment income - affiliated303,233 185,826 127,594

Miscellaneous - net(160,972)9,824 (125,886)

TOTAL264,737 152,758 184,962

INTEREST EXPENSE

Interest expense375,295 373,480 350,227

Allowance for borrowed funds used during construction(14,996)(11,550)(12,878)

TOTAL360,299 361,930 337,349

INCOME BEFORE INCOME TAXES1,067,589 693,017 774,393

Income taxes(205,781)(162,853)120,409

NET INCOME1,273,370 855,870 653,984

Net income attributable to noncontrolling interests2,988 1,366 —

EARNINGS APPLICABLE TO MEMBER'S EQUITY$1,270,382 $854,504 $653,984

See Notes to Financial Statements.

368

ENTERGY LOUISIANA, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

For the Years Ended December 31,

202320222021

(In Thousands)

Net Income$1,273,370 $855,870 $653,984

Other comprehensive income (loss)

Pension and other postretirement liabilities

(net of tax expense (benefit) of ($211), $17,351, and $1,523)

(572)47,092 3,951

Other comprehensive income (loss)(572)47,092 3,951

Comprehensive Income1,272,798 902,962 657,935

Net income attributable to noncontrolling interests2,988 1,366 —

Comprehensive Income Applicable to Member's Equity$1,269,810 $901,596 $657,935

See Notes to Financial Statements.

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370

ENTERGY LOUISIANA, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31,

202320222021

(In Thousands)

OPERATING ACTIVITIES

Net income$1,273,370 $855,870 $653,984

Adjustments to reconcile net income to net cash flow provided by operating activities:

Depreciation, amortization, and decommissioning, including nuclear fuel amortization864,225 852,521 818,389

Deferred income taxes, investment tax credits, and non-current taxes accrued(99,812)(70,379)175,700

Changes in working capital:

Receivables55,140 (53,434)(58,466)

Fuel inventory(15,959)1,099 7,722

Accounts payable(100,321)(207,949)358,536

Taxes accrued30,459 (28,244)21,631

Interest accrued(9,680)8,284 803

Deferred fuel costs134,383 (113,809)(43,124)

Other working capital accounts(129,173)(103,571)(45,517)

Changes in provisions for estimated losses(52,445)291,824 (449)

Changes in other regulatory assets407,327 720,487 (1,050,600)

Changes in other regulatory liabilities225,645 (4,783)(16,478)

Effect of securitization on regulatory asset(491,150)(1,190,338)—

Changes in pension and other postretirement liabilities(117,886)(139,067)(164,263)

Other57,997 358,997 394,658

Net cash flow provided by operating activities2,032,120 1,177,508 1,052,526

INVESTING ACTIVITIES

Construction expenditures(1,624,181)(2,568,113)(3,621,775)

Allowance for equity funds used during construction32,160 26,252 28,648

Nuclear fuel purchases(162,079)(122,020)(85,419)

Proceeds from sale of nuclear fuel30,214 37,648 13,254

Payments to storm reserve escrow account(14,449)(1,293,633)—

Receipts from storm reserve escrow account64,036 1,000,228 —

Purchase of preferred membership interests of affiliate(1,457,676)(3,163,572)—

Redemption of preferred membership interests of affiliate125,002 1,390,587 —

Changes in securitization account— — 2,700

Proceeds from nuclear decommissioning trust fund sales575,596 633,100 944,703

Investment in nuclear decommissioning trust funds(633,029)(667,947)(1,004,888)

Changes in money pool receivable - net— 14,539 (1,113)

Proceeds from sale of assets— 5,000 15,000

Insurance proceeds received for property damages19,493 — —

Litigation proceeds from settlement agreement— 5,695 —

Litigation proceeds for reimbursement of spent nuclear fuel storage costs— — 8,691

Decrease (increase) in other investments5,457 (5,475)—

Net cash flow used in investing activities(3,039,456)(4,707,711)(3,700,199)

FINANCING ACTIVITIES

Proceeds from the issuance of long-term debt1,410,893 2,942,771 3,769,166

Retirement of long-term debt(2,699,235)(3,167,832)(1,895,091)

Proceeds received by storm trusts related to securitization1,457,676 3,163,572 —

Capital contributions from parent1,457,676 1,000,000 125,000

Changes in money pool payable - net(69,948)226,114 —

Common equity distributions paid(660,750)(624,000)(60,000)

Other57,183 27,618 (849)

Net cash flow provided by financing activities953,495 3,568,243 1,938,226

Net increase (decrease) in cash and cash equivalents(53,841)38,040 (709,447)

Cash and cash equivalents at beginning of period56,613 18,573 728,020

Cash and cash equivalents at end of period$2,772 $56,613 $18,573

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:

Cash paid (received) during the period for:

Interest - net of amount capitalized$376,353 $353,697 $337,926

Income taxes($141,143)($82,463)($18,453)

Non-cash investing activities:

Accrued construction expenditures$105,859 $156,654 $507,855

See Notes to Financial Statements.

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ENTERGY LOUISIANA, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31,

20232022

(In Thousands)

CURRENT ASSETS

Cash and cash equivalents:

Cash$2,255 $50,318

Temporary cash investments517 6,295

Total cash and cash equivalents2,772 56,613

Accounts receivable:

Customer264,776 339,291

Allowance for doubtful accounts(6,156)(7,595)

Associated companies82,292 88,896

Other74,685 53,241

Accrued unbilled revenues202,173 199,077

Total accounts receivable617,770 672,910

Deferred fuel costs24,800 159,183

Fuel inventory57,818 41,859

Materials and supplies - at average cost652,180 555,860

Deferred nuclear refueling outage costs96,047 53,833

Prepayments and other71,613 76,646

TOTAL1,523,000 1,616,904

OTHER PROPERTY AND INVESTMENTS

Investment in affiliate preferred membership interests4,496,245 3,163,572

Decommissioning trust funds2,107,384 1,779,090

Non-utility property - at cost (less accumulated depreciation)404,043 350,723

Storm reserve escrow account243,819 293,406

Other9,367 19,679

TOTAL7,260,858 5,606,470

UTILITY PLANT

Electric27,800,467 27,498,136

Natural gas315,658 301,719

Construction work in progress592,803 736,969

Nuclear fuel333,472 212,941

TOTAL UTILITY PLANT29,042,400 28,749,765

Less - accumulated depreciation and amortization10,570,707 10,087,942

UTILITY PLANT - NET18,471,693 18,661,823

DEFERRED DEBITS AND OTHER ASSETS

Regulatory assets:

Other regulatory assets1,648,852 2,056,179

Deferred fuel costs168,122 168,122

Other36,945 35,057

TOTAL1,853,919 2,259,358

TOTAL ASSETS$29,109,470 $28,144,555

See Notes to Financial Statements.

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ENTERGY LOUISIANA, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

December 31,

20232022

(In Thousands)

CURRENT LIABILITIES

Currently maturing long-term debt$1,400,000 $1,010,000

Accounts payable:

Associated companies283,016 356,688

Other467,414 589,355

Customer deposits167,905 161,666

Taxes accrued66,463 36,004

Interest accrued91,656 101,336

Other87,468 72,525

TOTAL2,563,922 2,327,574

NON-CURRENT LIABILITIES

Accumulated deferred income taxes and taxes accrued2,391,442 2,374,878

Accumulated deferred investment tax credits93,242 97,868

Regulatory liability for income taxes - net193,754 337,836

Other regulatory liabilities1,407,689 1,037,962

Decommissioning1,836,240 1,736,801

Accumulated provisions263,869 316,314

Pension and other postretirement liabilities271,928 389,631

Long-term debt8,020,689 9,688,922

Other493,176 343,321

TOTAL14,972,029 16,323,533

Commitments and Contingencies

EQUITY

Member’s equity

11,473,614 9,406,343

Accumulated other comprehensive income54,798 55,370

Noncontrolling interests45,107 31,735

TOTAL11,573,519 9,493,448

TOTAL LIABILITIES AND EQUITY$29,109,470 $28,144,555

See Notes to Financial Statements.

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ENTERGY LOUISIANA, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Years Ended December 31, 2023, 2022, and 2021

Noncontrolling InterestsMember’s Equity

Accumulated Other Comprehensive Income Total

(In Thousands)

Balance at December 31, 2020$— $7,453,361 $4,327 $7,457,688

Net income— 653,984 — 653,984

Other comprehensive income— — 3,951 3,951

Capital contribution from parent— 125,000 — 125,000

Common equity distributions— (60,000)— (60,000)

Other— (51)— (51)

Balance at December 31, 2021$— $8,172,294 $8,278 $8,180,572

Net income1,366 854,504 — 855,870

Other comprehensive income— — 47,092 47,092

Beneficial interest in storm trust31,636 — — 31,636

Non-cash contribution from parent— 3,597 — 3,597

Capital contribution from parent— 1,000,000 — 1,000,000

Common equity distributions— (624,000)— (624,000)

Distribution to LURC(1,267)— — (1,267)

Other— (52)— (52)

Balance at December 31, 2022$31,735 $9,406,343 $55,370 $9,493,448

Net income2,988 1,270,382 — 1,273,370

Other comprehensive loss— — (572)(572)

Beneficial interest in storm trust14,577 — — 14,577

Capital contribution from parent— 1,457,676 — 1,457,676

Common equity distributions— (660,750)— (660,750)

Distributions to LURC(4,193)— — (4,193)

Other— (37)— (37)

Balance at December 31, 2023$45,107 $11,473,614 $54,798 $11,573,519

See Notes to Financial Statements.

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ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

2023 Compared to 2022

Earnings Applicable to Member’s Equity

Earnings decreased $5.4 million primarily due to higher depreciation and amortization expenses, lower volume/weather, higher interest expense, lower other income, higher other operation and maintenance expenses, and higher taxes other than income taxes. The decrease was partially offset by higher retail electric price.

Operating Revenues

Following is an analysis of the change in operating revenues comparing 2023 to 2022.

Amount

(In Millions)

2022 operating revenues$1,624.2

Fuel, rider, and other revenues that do not significantly affect net income95.8

Retail electric price58.9

Retail one-time bill credit36.7

Volume/weather(13.1)

2023 operating revenues$1,802.5

Entergy Mississippi’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.

The retail electric price variance is primarily due to increases in formula rate plan rates effective August 2022, April 2023, and July 2023. See Note 2 to the financial statements for further discussion of the formula rate plan filings.

The retail one-time bill credit represents the disbursement of settlement proceeds in the form of a one-time bill credit provided to retail customers during the September 2022 billing cycle as a result of the System Energy settlement agreement with the MPSC. There is no effect on net income as the reduction in operating revenues was offset by a reduction in fuel and purchased power expenses. See Note 2 to the financial statements for discussion of the settlement agreement and the MPSC directive related to the disbursement of settlement proceeds.

The volume/weather variance is primarily due to the effect of less favorable weather on residential sales and a decrease in weather-adjusted residential and commercial usage, partially offset by the effect of more favorable weather on commercial sales.

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Entergy Mississippi, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Total electric energy sales for Entergy Mississippi for the years ended December 31, 2023 and 2022 are as follows:

20232022% Change

(GWh)

Residential5,460 5,679 (4)

Commercial4,640 4,586 1

Industrial2,347 2,359 (1)

Governmental407 414 (2)

Total retail 12,854 13,038 (1)

Sales for resale:

Non-associated companies4,598 2,914 58

Total17,452 15,952 9

See Note 19 to the financial statements for additional discussion of Entergy Mississippi’s operating revenues.

Other Income Statement Variances

Other operation and maintenance expenses increased primarily due to:

•an increase of $6.6 million in contract costs related to operational performance, customer service, and organizational health initiatives;

•an increase of $5.1 million in loss provisions;

•an increase of $4.4 million in bad debt expense;

•an increase of $3.1 million in power delivery expenses primarily due to higher vegetation maintenance costs, partially offset by a lower scope of work performed in 2023 as compared to 2022; and

•several individually insignificant items.

The increase was partially offset by:

•a decrease of $5.8 million in transmission costs allocated by MISO;

•a decrease of $5.3 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits service costs as a result of an increase in the discount rates used to value the benefits liabilities, lower health and welfare costs, including higher prescription drug rebates in second quarter 2023, and a revision to estimated incentive compensation expense in first quarter 2023. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs; and

•a decrease of $5.3 million in non-nuclear generation expenses primarily due to a lower scope of work, including during plant outages, performed in 2023 as compared to 2022.

Taxes other than income taxes increased primarily due to increases in ad valorem taxes resulting from higher assessments and increases in local franchise taxes.

Depreciation and amortization expenses increased primarily due to additions to plant in service, including the Sunflower Solar facility, which was placed in service in September 2022.

Other regulatory charges (credits) - net includes regulatory credits of $22.6 million, recorded in third quarter 2022, to reflect the effects of the joint stipulation reached in the 2022 formula rate plan filing proceeding and regulatory credits of $18.2 million, recorded in fourth quarter 2022, to reflect that the 2022 estimated earned

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Entergy Mississippi, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

return was below the formula bandwidth. See Note 2 to the financial statements for discussion of the formula rate plan filings.

Other income (deductions) decreased primarily due to lower interest income from carrying costs related to the deferred fuel balance and an increase in non-qualified pension settlement charges recorded in 2023 and other postretirement benefit non-service costs as a result of the amortization of 2022 trust asset losses. The decrease was partially offset by the timing of charitable donations and an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2023. See “Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs.

Interest expense increased primarily due to the issuance of $300 million of 5.0% Series mortgage bonds in May 2023 and the $150 million unsecured term loan drawn in June 2022, of which $50 million was repaid in May 2023 and $100 million was repaid in December 2023. The increase was partially offset by the repayment of $250 million of 3.10% Series mortgage bonds in June 2023.

Net loss attributable to noncontrolling interest reflects the earnings or losses attributable to the noncontrolling partner of the tax equity partnership for the Sunflower Solar facility under HLBV accounting. Entergy Mississippi recorded regulatory charges of $9.1 million in 2023 and $21.4 million in 2022 to defer the difference between the losses allocated to the tax equity partner under the HLBV method of accounting and the earnings/losses that would have been allocated to the tax equity partner under its respective ownership percentage in the partnership. See Note 1 to the financial statements for discussion of the HLBV method of accounting.

The effective income tax rates were 23.0% for 2023 and 23.7% for 2022. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates and for additional discussion regarding income taxes.

2022 Compared to 2021

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy Mississippi’s Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 24, 2023, for discussion of results of operations for 2022 compared to 2021.

Income Tax Legislation and Regulation

See the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of income tax legislation and regulation.

377

Entergy Mississippi, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2023, 2022, and 2021 were as follows:

202320222021

(In Thousands)

Cash and cash equivalents at beginning of period$16,979 $47,627 $18

Net cash provided by (used in):

Operating activities559,391 405,649 350,960

Investing activities(527,978)(620,740)(686,654)

Financing activities(41,762)184,443 383,303

Net increase (decrease) in cash and cash equivalents(10,349)(30,648)47,609

Cash and cash equivalents at end of period$6,630 $16,979 $47,627

2023 Compared to 2022

Operating Activities

Net cash flow provided by operating activities increased $153.7 million in 2023 primarily due to:

•lower fuel costs and the timing of recovery of fuel and purchased power costs. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery;

•higher collections from customers; and

•a decrease of $12.2 million in pension contributions in 2023. See “Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

The increase was partially offset by:

•the receipt of $235 million in settlement proceeds in 2022, of which $198.3 million was applied to the under-recovered deferred fuel balance. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery and the System Energy settlement agreement with the MPSC;

•income tax payments of $50.9 million in 2023 as compared to income tax refunds of $5.4 million in 2022. Entergy Mississippi made income tax payments in 2023 and received income tax refunds in 2022, each in accordance with an intercompany income tax allocation agreement;

•an increase of $13.9 million in storm spending in 2023; and

•an increase of $10.7 million in interest paid.

Investing Activities

Net cash flow used in investing activities decreased $92.8 million in 2023 primarily due to:

•the initial payment of approximately $105.1 million in May 2022 as compared to the substantial completion payment of approximately $30.4 million in April 2023 and the final payment of approximately $4.7 million in October 2023 for the purchase of the Sunflower Solar facility by a consolidated tax equity partnership. See Note 14 to the financial statements for discussion of the Sunflower Solar facility purchase;

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•the receipt of $34.5 million from the storm reserve escrow account in 2023. See Note 2 to the financial statements for discussion of the storm escrow disbursement;

•a decrease of $20.2 million in non-nuclear generation construction expenditures primarily due to a lower scope of work, including during plant outages, performed in 2023 as compared to 2022;

•a decrease of $17.8 million in information technology capital expenditures primarily due to decreased spending on various technology projects in 2023; and

•money pool activity.

The decrease was partially offset by an increase of $46.8 million in transmission construction expenditures primarily due to increased investment in the reliability and infrastructure of Entergy Mississippi’s transmission system in 2023 and an increase of $27.5 million in distribution construction expenditures primarily due to higher capital expenditures for storm restoration in 2023.

Decreases in Entergy Mississippi’s receivable from the money pool are a source of cash flow, and Entergy Mississippi’s receivable from the money pool decreased $26.9 million in 2023 compared to decreasing by $13.6 million in 2022. The money pool is an intercompany cash management program that makes possible intercompany borrowing and lending arrangements, including to reduce the Registrant Subsidiaries’ need for external short-term borrowings.

Financing Activities

Entergy Mississippi’s financing activities used $41.8 million of cash in 2023 compared to providing $184.4 million of cash in 2022 primarily due to the following activity:

•proceeds of $150 million received in June 2022 from an unsecured term loan due December 2023 as compared to repayments of $150 million on the unsecured term loan in 2023;

•the repayment, prior to maturity, of $250 million of 3.10% Series mortgage bonds in June 2023;

•$40 million in common equity distributions paid in 2023 in order to maintain Entergy Mississippi’s capital structure;

•money pool activity; and

•the issuance of $300 million of 5.0% Series mortgage bonds in May 2023.

Increases in Entergy Mississippi’s payable to the money pool are a source of cash flow, and Entergy Mississippi’s payable to the money pool increased $73.8 million in 2023.

See Note 5 to the financial statements for details on long-term debt.

2022 Compared to 2021

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Mississippi’s Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 24, 2023, for discussion of operating, investing, and financing cash flow activities for 2022 compared to 2021.

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Capital Structure

Entergy Mississippi’s debt to capital ratio is shown in the following table. The decrease in the debt to capital ratio for Entergy Mississippi is primarily due to the net retirement of long-term debt in 2023 and net income in 2023.

December 31,2023December 31,2022

Debt to capital50.5 %53.4 %

Effect of subtracting cash(0.1 %)(0.2 %)

Net debt to net capital (non-GAAP)50.4 %53.2 %

Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. Entergy Mississippi uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Mississippi’s financial condition. The net debt to net capital ratio is a non-GAAP measure. Entergy Mississippi uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Mississippi’s financial condition because net debt indicates Entergy Mississippi’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

Entergy Mississippi seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a distribution, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Mississippi may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reduced distributions, Entergy Mississippi may receive equity contributions to maintain its capital structure.

Uses of Capital

Entergy Mississippi requires capital resources for:

•construction and other capital investments;

•debt maturities or retirements;

•working capital purposes, including the financing of fuel and purchased power costs; and

•distributions and interest payments.

Following are the amounts of Entergy Mississippi’s planned construction and other capital investments.

202420252026

(In Millions)

Planned construction and capital investment:

Generation$130 $440 $750

Transmission185 200 180

Distribution335 325 295

Utility Support50 60 60

Total$700 $1,025 $1,285

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In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Mississippi includes investments in generation projects to modernize, decarbonize, and diversify Entergy Mississippi’s portfolio, as well as to support customer growth; distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to improve reliability and resilience while also supporting renewables expansion and customer growth; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, government actions, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.

Following are the amounts of Entergy Mississippi’s existing debt and lease obligations (includes estimated interest payments).

2024202520262027-2028 After 2028

(In Millions)

Long-term debt (a)$182 $81 $81 $675 $2,853

Operating leases (b)$8 $7 $5 $7 $2

Finance leases (b)$3 $3 $3 $4 $24

(a)Long-term debt is discussed in Note 5 to the financial statements.

(b)Lease obligations are discussed in Note 10 to the financial statements.

Other Obligations

Entergy Mississippi currently expects to contribute approximately $15 million to its qualified pension plans and approximately $178 thousand to other postretirement health care and life insurance plans in 2024, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024, valuations are completed, which is expected by April 1, 2024. See “Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

Entergy Mississippi has $1.9 million of unrecognized tax benefits net of unused tax attributes plus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

In addition, Entergy Mississippi enters into fuel and purchased power agreements that contain minimum purchase obligations. Entergy Mississippi has rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations. See Note 8 to the financial statements for discussion of Entergy Mississippi’s obligations under the Unit Power Sales Agreement.

As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Mississippi pays distributions from its earnings at a percentage determined monthly.

Sources of Capital

Entergy Mississippi’s sources to meet its capital requirements include:

•internally generated funds;

•cash on hand;

•the Entergy system money pool;

•storm reserve escrow accounts;

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•debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;

•capital contributions; and

•bank financing under new or existing facilities.

Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations, Entergy Mississippi expects to continue, when economically feasible, to retire higher-cost debt and replace it with lower-cost debt if market conditions permit.

All debt and preferred membership interest issuances by Entergy Mississippi require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in its bond indenture and other agreements. Entergy Mississippi has sufficient capacity under these tests to meet its foreseeable capital needs for the next twelve months and beyond.

Entergy Mississippi’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.

2023202220212020

(In Thousands)

($73,769)$26,879$40,456($16,516)

See Note 4 to the financial statements for a description of the money pool.

Entergy Mississippi has a credit facility in the amount of $150 million scheduled to expire in July 2025. As of December 31, 2023, there were no cash borrowings outstanding under the credit facility. In addition, Entergy Mississippi is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO and for other purposes. As of December 31, 2023, $20.0 million in MISO letters of credit and $1.0 million in a non-MISO letter of credit were outstanding under this facility. See Note 4 to the financial statements for additional discussion of the credit facilities.

Entergy Mississippi obtained authorization from the FERC through April 2025 for short-term borrowings, not to exceed an aggregate amount of $200 million at any time outstanding, and long-term borrowings and security issuances. See Note 4 to the financial statements for further discussion of Entergy Mississippi’s short-term borrowing limits.

State and Local Rate Regulation and Fuel-Cost Recovery

The rates that Entergy Mississippi charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Mississippi is regulated, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the MPSC, is primarily responsible for approval of the rates charged to customers.

Filings with the MPSC

Retail Rates

2021 Formula Rate Plan Filing

In March 2021, Entergy Mississippi submitted its formula rate plan 2021 test year filing and 2020 look-back filing showing Entergy Mississippi’s earned return for the historical 2020 calendar year to be below the

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formula rate plan bandwidth and projected earned return for the 2021 calendar year to be below the formula rate plan bandwidth. The 2021 test year filing showed a $95.4 million rate increase was necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.69% return on rate base, within the formula rate plan bandwidth. The change in formula rate plan revenues, however, was capped at 4% of retail revenues, which equated to a revenue change of $44.3 million. The 2021 evaluation report also included $3.9 million in demand side management costs for which the MPSC approved realignment of recovery from the energy efficiency rider to the formula rate plan. These costs were not subject to the 4% cap and resulted in a total change in formula rate plan revenues of $48.2 million. The 2020 look-back filing compared actual 2020 results to the approved benchmark return on rate base and reflected the need for a $16.8 million interim increase in formula rate plan revenues. In addition, the 2020 look-back filing included an interim capacity adjustment true-up for the Choctaw Generating Station, which increased the look-back interim rate adjustment by $1.7 million. These interim rate adjustments totaled $18.5 million. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $22.1 million interim rate increase, reflecting a cap equal to 2% of 2020 retail revenues, effective with the April 2021 billing cycle, subject to refund, pending a final MPSC order. The $3.9 million of demand side management costs and the Choctaw Generating Station true-up of $1.7 million, which were not subject to the 2% cap of 2020 retail revenues, were included in the April 2021 rate adjustments.

In June 2021, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed the 2021 test year filing that resulted in a total rate increase of $48.2 million. Pursuant to the joint stipulation, Entergy Mississippi’s 2020 look-back filing reflected an earned return on rate base of 6.12% in calendar year 2020, which was below the look-back bandwidth, resulting in a $17.5 million increase in formula rate plan revenues on an interim basis through June 2022. This included $1.7 million related to the Choctaw Generating Station and $3.7 million of COVID-19 non-bad debt expenses. The joint stipulation also included Entergy Mississippi’s quantification and methodology for calculating incremental COVID-19 bad debt expenses and provided for Entergy Mississippi to continue to defer these incremental COVID-19 bad debt expenses through December 2021. In June 2021 the MPSC approved the joint stipulation with rates effective for the first billing cycle of July 2021. In June 2021, Entergy Mississippi recorded regulatory credits of $19.9 million to reflect the effects of the joint stipulation.

2022 Formula Rate Plan Filing

In March 2022, Entergy Mississippi submitted its formula rate plan 2022 test year filing and 2021 look-back filing showing Entergy Mississippi’s earned return for the historical 2021 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2022 calendar year to be below the formula rate plan bandwidth. The 2022 test year filing showed a $69 million rate increase was necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.70% return on rate base, within the formula rate plan bandwidth. The change in formula rate plan revenues, however, was capped at 4% of retail revenues, which equated to a revenue change of $48.6 million. The 2021 look-back filing compared actual 2021 results to the approved benchmark return on rate base and reflected the need for a $34.5 million interim increase in formula rate plan revenues. In fourth quarter 2021, Entergy Mississippi recorded a regulatory asset of $19 million to reflect the then-current estimate in connection with the look-back feature of the formula rate plan. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $24.3 million interim rate increase, reflecting a cap equal to 2% of 2021 retail revenues, effective in April 2022. With the implementation of the interim formula rate plan rates, Entergy Mississippi began recovery of the bad debt expense deferral resulting from the COVID-19 pandemic over a three-year period.

In June 2022, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed the 2022 test year filing that resulted in a total rate increase of $48.6 million. Pursuant to the joint stipulation, Entergy Mississippi’s 2021 look-back filing reflected an earned return on rate base of 5.99% in calendar year 2021, which was below the look-back bandwidth, resulting in a $34.3 million increase in the formula rate plan revenues on an interim basis through June 2023. In July 2022 the MPSC approved the joint stipulation with rates effective in August 2022. In July 2022, Entergy Mississippi recorded regulatory credits of $22.6 million to reflect

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the effects of the joint stipulation. In August 2022 an intervenor filed a statutorily-authorized direct appeal to the Mississippi Supreme Court seeking review of the MPSC’s July 2022 order approving the joint stipulation confirming Entergy Mississippi’s 2022 formula rate plan filing. Formula rate plan rates are not stayed or otherwise impacted while the appeal is pending.

In July 2022 the MPSC directed Entergy Mississippi to flow $14.1 million of the power management rider over-recovery balance to customers beginning in August 2022 through December 2022 to mitigate the bill impact of the increase in formula rate plan revenues.

2023 Formula Rate Plan Filing

In March 2023, Entergy Mississippi submitted its formula rate plan 2023 test year filing and 2022 look-back filing showing Entergy Mississippi’s earned return on rate base for the historical 2022 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2023 calendar year to be below the formula rate plan bandwidth. The 2023 test year filing showed a $39.8 million rate increase was necessary to reset Entergy Mississippi’s earned return on rate base to the specified point of adjustment of 6.67%, within the formula rate plan bandwidth. The 2022 look-back filing compared actual 2022 results to the approved benchmark return on rate base and reflected the need for a $19.8 million temporary increase in formula rate plan revenues, including the refund of a $1.3 million over-recovery resulting from the demand-side management costs true-up for 2022. In fourth quarter 2022, Entergy Mississippi recorded a regulatory asset of $18.2 million in connection with the look-back feature of the formula rate plan to reflect that the 2022 estimated earned return was below the formula rate plan bandwidth. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $27.9 million interim rate increase, reflecting a cap equal to 2% of 2022 retail revenues, effective in April 2023.

In May 2023, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed a 2023 test year filing resulting in a total revenue increase of $26.5 million for 2023. Pursuant to the joint stipulation, Entergy Mississippi’s 2022 look-back filing reflected an earned return on rate base of 6.10% in calendar year 2022, which was below the look-back bandwidth, resulting in a $19.0 million increase in the formula rate plan revenues on an interim basis through June 2024. Entergy Mississippi recorded a regulatory credit of $0.8 million in June 2023 to reflect the increase in the look-back regulatory asset. In addition, certain long-term service agreement and conductor handling costs were authorized for realignment from the formula rate plan to the annual power management and grid modernization riders effective January 2023, resulting in regulatory credits recorded in June 2023 of $4.1 million and $4.3 million, respectively. Also, the amortization of Entergy Mississippi’s COVID-19 bad debt expense deferral was suspended for calendar year 2023 and will resume in 2024. In June 2023 the MPSC approved the joint stipulation with rates effective in July 2023.

Fuel and purchased power cost recovery

Entergy Mississippi’s rate schedules include an energy cost recovery rider and a power management rider, both of which are adjusted annually to reflect accumulated over- or under-recoveries. Entergy Mississippi recovers fuel and purchased energy costs through its energy cost recovery rider and recovers costs associated with natural gas hedging and capacity payments through its power management rider. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.

In November 2020, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an over-recovery of approximately $24.4 million as of September 30, 2020. In January 2021 the MPSC approved the proposed energy cost factor effective for February 2021 bills.

In November 2021, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an under-recovery of approximately $80.6 million as of September 30, 2021. In December 2021, at the request of the MPSC, Entergy

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Mississippi submitted a proposal to mitigate the impact of rising fuel costs on customer bills during 2022. Entergy Mississippi proposed that the deferred fuel balance as of December 31, 2021, which was $121.9 million, be amortized over three years and that the MPSC authorize Entergy Mississippi to apply its weighted-average cost of capital as the carrying cost for the unamortized fuel balance. In January 2022 the MPSC approved the amortization of $100 million of the deferred fuel balance over two years and authorized Entergy Mississippi to apply its weighted-average cost of capital as the carrying cost for the unamortized fuel balance. The MPSC approved the proposed energy cost factor effective for February 2022 bills.

See “Complaints Against System Energy - System Energy Settlement with the MPSC” in Note 2 to the financial statements for discussion of the settlement agreement filed with the FERC in June 2022. The settlement, which was approved by the FERC in November 2022, provided for a refund of $235 million from System Energy to Entergy Mississippi. In July 2022 the MPSC directed the disbursement of settlement proceeds, ordering Entergy Mississippi to provide a one-time $80 bill credit to each of its approximately 460,000 retail customers to be effective during the September 2022 billing cycle and to apply the remaining proceeds to Entergy Mississippi’s under-recovered deferred fuel balance. In accordance with the MPSC’s directive, Entergy Mississippi provided approximately $36.7 million in customer bill credits as a result of the settlement. In November 2022, Entergy Mississippi applied the remaining settlement proceeds in the amount of approximately $198.3 million to Entergy Mississippi’s under-recovered deferred fuel balance.

Entergy Mississippi had a deferred fuel balance of approximately $291.7 million under the energy cost recovery rider as of July 31, 2022, along with an over-recovery balance of $51.1 million under the power management rider. Without further action, Entergy Mississippi anticipated a year-end deferred fuel balance of approximately $200 million after application of a portion of the System Energy settlement proceeds, as discussed above. In September 2022, Entergy Mississippi filed for interim adjustments under both the energy cost recovery rider and the power management rider. Entergy Mississippi proposed five monthly incremental adjustments to the net energy cost factor designed to collect the under-recovered fuel balance as of July 31, 2022 and to reflect the recovery of a higher natural gas price. Entergy Mississippi also proposed five monthly incremental adjustments to the power management adjustment factor designed to flow through to customers the over-recovered power management rider balance as of July 31, 2022. In October 2022 the MPSC approved modified interim adjustments to Entergy Mississippi’s energy cost recovery rider and power management rider. The MPSC approved dividing the energy cost recovery rider interim adjustment into two components that would allow Entergy Mississippi to (1) recover a natural gas fuel rate that is better aligned with current prices; and (2) recover the estimated under-recovered deferred fuel balance as of September 30, 2022 over a period of 20 months. The MPSC approved six monthly incremental adjustments to the net energy cost factor designed to reflect the recovery of a higher natural gas price. The MPSC also approved six monthly incremental adjustments to the power management adjustment factor designed to flow through to customers the over-recovered power management rider balance. In accordance with the order of the MPSC, Entergy Mississippi did not file an annual redetermination of the energy cost recovery rider or the power management rider in November 2022.

In June 2023 the MPSC approved the joint stipulation agreement between Entergy Mississippi and the Mississippi Public Utilities Staff for Entergy Mississippi’s 2023 formula rate plan filing. The stipulation directed Entergy Mississippi to make a compliance filing to revise its power management cost adjustment factor, to revise its grid modernization cost adjustment factor, and to include a revision to reduce the net energy cost factor to a level necessary to reflect an average natural gas price of $4.50 per MMBtu. The MPSC approved the compliance filing in June 2023, effective for July 2023 bills. See “Retail Rate Proceedings - Filings with the MPSC (Entergy Mississippi) - Retail Rates - 2023 Formula Rate Plan Filing” in Note 2 to the financial statements for further discussion of the 2023 formula rate plan filing and the joint stipulation agreement.

In November 2023 Entergy Mississippi filed its annual redeterminations of the energy cost factor and the power management cost adjustment factor. The calculation of the annual factor for the energy cost recovery rider included a projected over-recovery balance of approximately $142 million at the end of January 2024. The calculation of the annual factor for the power management rider included a projected under-recovery of $47 million

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at the end of January 2024. In January 2024 the MPSC approved the proposed energy cost factor and the proposed power management cost factor effective for February 2024 bills.

RenewABLE Community Option

In January 2022, Entergy Mississippi filed its RenewABLE Community Option (Schedule RCO), an offering for qualifying non-residential customers to subscribe to renewable resource capacity to satisfy their environmental, sustainability, and governance goals. The MPSC approved Schedule RCO in December 2022. Registration for the Schedule RCO launched in May 2023 and subscriptions as of December 31, 2023 totaled 17.9 MW of the 40 MW available.

Storm Cost Recovery Filings with Retail Regulators

Entergy Mississippi has approval from the MPSC to collect a storm damage provision of $1.75 million per month. If Entergy Mississippi’s accumulated storm damage provision balance exceeds $15 million, the collection of the storm damage provision ceases until such time that the accumulated storm damage provision becomes less than $10 million. Entergy Mississippi’s storm damage provision balance has been less than $10 million since May 2019, and Entergy Mississippi has been billing the monthly storm damage provision since July 2019.

In December 2023 Entergy Mississippi filed a Notice of Storm Escrow Disbursement and Request for Interim Relief notifying the MPSC that Entergy Mississippi had requested disbursement of approximately $34.5 million of storm escrow funds from its restricted storm escrow account. The filing also requested authorization from the MPSC, on a temporary basis, that the $34.5 million of storm escrow funds be credited to Entergy Mississippi’s storm damage provision, pending the MPSC’s review of Entergy Mississippi’s storm-related costs, and that Entergy Mississippi continue to bill its monthly storm damage provision without suspension in the event the storm damage provision balance exceeds $15 million, in anticipation of a subsequent filing by Entergy Mississippi in this proceeding. The storm damage reserve exceeded $15 million upon receipt of the storm escrow funds. Because the MPSC had not entered an order on Entergy Mississippi’s filing on the requested relief to continue billing this provision, Entergy Mississippi suspended billing the monthly storm damage provision effective with February 2024 bills.

Federal Regulation

See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.

Nuclear Matters

See the “Nuclear Matters” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of nuclear matters.

Environmental Risks

Entergy Mississippi’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Mississippi is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

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Critical Accounting Estimates

The preparation of Entergy Mississippi’s financial statements in conformity with GAAP requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in these assumptions and measurements could produce estimates that would have a material effect on the presentation of Entergy Mississippi’s financial position, results of operations, or cash flows.

Utility Regulatory Accounting

See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.

Taxation and Uncertain Tax Positions

See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.

Qualified Pension and Other Postretirement Benefits

Entergy Mississippi’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are affected by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.

Cost Sensitivity

The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).

Actuarial AssumptionChange in AssumptionImpact on 2024 Qualified Pension CostImpact on 2023 Qualified Projected Benefit Obligation

Increase/(Decrease)

Discount rate(0.25%)$256$6,670

Rate of return on plan assets(0.25%)$723$—

Rate of increase in compensation0.25%$264$1,383

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The following chart reflects the sensitivity of postretirement benefits cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).

Actuarial AssumptionChange in AssumptionImpact on 2024 Postretirement Benefits CostImpact on 2023 Accumulated Postretirement Benefit Obligation

Increase/(Decrease)

Discount rate(0.25%)$20$1,031

Health care cost trend0.25%$60$701

Each fluctuation above assumes that the other components of the calculation are held constant.

Costs and Employer Contributions

Total qualified pension cost for Entergy Mississippi in 2023 was $19.7 million, including $12.2 million in settlement costs. Entergy Mississippi anticipates 2024 qualified pension cost to be $3.3 million. Entergy Mississippi contributed $21.1 million to its qualified pension plans in 2023 and estimates 2024 pension contributions will be approximately $15 million, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024 valuations are completed, which is expected by April 1, 2024.

Total postretirement health care and life insurance benefit income for Entergy Mississippi in 2023 was $2.5 million. Entergy Mississippi expects 2024 postretirement health care and life insurance benefit income of approximately $3.7 million. Entergy Mississippi contributed $646 thousand to its other postretirement plan in 2023 and estimates 2024 contributions will be approximately $178 thousand.

Other Contingencies

See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.

New Accounting Pronouncements

See the “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.

388

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the member and Board of Directors of

Entergy Mississippi, LLC and Subsidiaries

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Entergy Mississippi, LLC and Subsidiaries (the “Company”) as of December 31, 2023 and 2022, the related consolidated statements of income, cash flows and changes in equity (pages 391 through 396 and applicable items in pages 47 through 238), for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Rate and Regulatory Matters — Entergy Mississippi, LLC and Subsidiaries — Refer to Note 2 to the financial statements

Critical Audit Matter Description

The Company is subject to rate regulation by the Mississippi Public Service Commission (the “MPSC”), which has jurisdiction with respect to the rates of electric companies in Mississippi, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.

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The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the MPSC and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the MPSC and the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.

We identified the impact of rate regulation as a critical audit matter due to the judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs and refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the MPSC and the FERC, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities involved specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and auditor judgment to evaluate management estimates and the subjectivity of audit evidence.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertainty of future decisions by the MPSC and the FERC, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities included the following, among others:

•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

•We read relevant regulatory orders issued by the MPSC and the FERC for the Company to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the MPSC’s and FERC’s treatment of similar costs under similar circumstances. We evaluated external information and compared to management’s recorded regulatory asset and liability balances for completeness.

•For regulatory matters in process, we inspected the Company’s filings with the MPSC and the FERC and orders issued, and considered the filings with the MPSC and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.

•We obtained an analysis from management and support from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.

•We obtained representation from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management’s assertion that amounts are probable of recovery, refund, or a future reduction in rates.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 23, 2024

We have served as the Company’s auditor since 2001.

390

ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES

CONSOLIDATED INCOME STATEMENTS

For the Years Ended December 31,

202320222021

(In Thousands)

OPERATING REVENUES

Electric$1,802,533 $1,624,234 $1,406,346

OPERATING EXPENSES

Operation and Maintenance:

Fuel, fuel-related expenses, and gas purchased for resale563,296 252,760 181,511

Purchased power281,761 322,674 298,034

Other operation and maintenance320,192 314,902 298,129

Taxes other than income taxes150,921 137,541 111,712

Depreciation and amortization262,624 246,063 226,545

Other regulatory charges (credits) - net(111,376)38,017 5,913

TOTAL1,467,418 1,311,957 1,121,844

OPERATING INCOME335,115 312,277 284,502

OTHER INCOME (DEDUCTIONS)

Allowance for equity funds used during construction8,552 6,125 8,101

Interest and investment income2,275 508 53

Miscellaneous - net(13,231)(3,619)(8,791)

TOTAL(2,404)3,014 (637)

INTEREST EXPENSE

Interest expense99,857 86,960 75,124

Allowance for borrowed funds used during construction(3,479)(2,800)(3,416)

TOTAL96,378 84,160 71,708

INCOME BEFORE INCOME TAXES236,333 231,131 212,157

Income taxes54,364 54,864 45,323

NET INCOME181,969 176,267 166,834

Net loss attributable to noncontrolling interest(10,302)(21,355)—

EARNINGS APPLICABLE TO MEMBER'S EQUITY$192,271 $197,622 $166,834

See Notes to Financial Statements.

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ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31,

202320222021

(In Thousands)

OPERATING ACTIVITIES

Net income$181,969 $176,267 $166,834

Adjustments to reconcile net income to net cash flow provided by operating activities:

Depreciation and amortization262,624 246,063 226,545

Deferred income taxes, investment tax credits, and non-current taxes accrued28,990 54,850 64,868

Changes in assets and liabilities:

Receivables3,627 (65,843)10,260

Fuel inventory(648)(5,237)6,806

Accounts payable(41,101)49,101 27,068

Taxes accrued(9,771)18,632 (1,811)

Interest accrued3,329 925 (3,606)

Deferred fuel costs273,856 (21,333)(136,569)

Other working capital accounts(23,813)2,632 (9,522)

Provisions for estimated losses1,972 (519)(8,476)

Other regulatory assets(59,616)(57,028)4,909

Other regulatory liabilities(59,513)20,165 21,930

Pension and other postretirement liabilities(49,223)(35,299)(51,828)

Other assets and liabilities46,709 22,273 33,552

Net cash flow provided by operating activities559,391 405,649 350,960

INVESTING ACTIVITIES

Construction expenditures(562,118)(534,020)(654,352)

Allowance for equity funds used during construction8,552 6,125 8,101

Payment for purchase of assets(35,094)(105,149)—

Changes in money pool receivable - net26,879 13,577 (40,456)

Receipt from storm reserve escrow account34,493 — —

Decrease (increase) in other investments(690)(1,273)53

Net cash flow used in investing activities(527,978)(620,740)(686,654)

FINANCING ACTIVITIES

Proceeds from the issuance of long-term debt396,833 249,266 398,284

Retirement of long-term debt(500,000)(100,000)—

Capital contributions from noncontrolling interest25,708 24,702 —

Changes in money pool payable - net73,769 — (16,516)

Common equity distributions paid(40,000)— —

Other1,928 10,475 1,535

Net cash flow provided by (used in) financing activities(41,762)184,443 383,303

Net increase (decrease) in cash and cash equivalents(10,349)(30,648)47,609

Cash and cash equivalents at beginning of period16,979 47,627 18

Cash and cash equivalents at end of period$6,630 $16,979 $47,627

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:

Cash paid (received) during the period for:

Interest - net of amount capitalized$93,961 $83,291 $76,245

Income taxes$50,869 ($5,396)($19,672)

Noncash investing activities:

Accrued construction expenditures$16,342 $59,474 $26,498

See Notes to Financial Statements.

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ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31,

20232022

(In Thousands)

CURRENT ASSETS

Cash and cash equivalents:

Cash$30 $26

Temporary cash investments6,600 16,953

Total cash and cash equivalents6,630 16,979

Accounts receivable:

Customer121,389 99,504

Allowance for doubtful accounts(3,312)(2,472)

Associated companies4,997 37,673

Other17,697 34,564

Accrued unbilled revenues71,465 73,473

Total accounts receivable212,236 242,742

Deferred fuel costs— 143,211

Fuel inventory - at average cost16,196 15,548

Materials and supplies - at average cost95,526 84,346

Prepayments and other12,740 9,603

TOTAL343,328 512,429

OTHER PROPERTY AND INVESTMENTS

Non-utility property - at cost (less accumulated depreciation)4,497 4,512

Storm reserve escrow account656 33,549

Other— 910

TOTAL5,153 38,971

UTILITY PLANT

Electric7,455,145 7,079,849

Construction work in progress139,635 170,191

TOTAL UTILITY PLANT7,594,780 7,250,040

Less - accumulated depreciation and amortization2,346,327 2,264,786

UTILITY PLANT - NET5,248,453 4,985,254

DEFERRED DEBITS AND OTHER ASSETS

Regulatory assets:

Other regulatory assets579,076 519,460

Other51,996 22,650

TOTAL631,072 542,110

TOTAL ASSETS$6,228,006 $6,078,764

See Notes to Financial Statements.

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ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

December 31,

20232022

(In Thousands)

CURRENT LIABILITIES

Currently maturing long-term debt$100,000 $400,000

Accounts payable:

Associated companies133,571 60,532

Other92,659 176,162

Customer deposits92,637 89,668

Taxes accrued115,134 124,905

Interest accrued21,537 18,208

Deferred fuel costs130,645 —

Other26,463 38,908

TOTAL712,646 908,383

NON-CURRENT LIABILITIES

Accumulated deferred income taxes and taxes accrued821,744 780,030

Accumulated deferred investment tax credits13,811 14,591

Regulatory liability for income taxes - net188,714 202,058

Other regulatory liabilities33,696 79,865

Asset retirement cost liabilities8,229 7,797

Accumulated provisions39,481 37,509

Pension and other postretirement liabilities— 23,742

Long-term debt2,129,510 1,931,096

Other71,961 53,156

TOTAL3,307,146 3,129,844

Commitments and Contingencies

EQUITY

Member's equity2,189,461 2,037,190

Noncontrolling interest18,753 3,347

TOTAL2,208,214 2,040,537

TOTAL LIABILITIES AND EQUITY$6,228,006 $6,078,764

See Notes to Financial Statements.

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ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Years Ended December 31, 2023, 2022, and 2021

Noncontrolling InterestMember's EquityTotal

(In Thousands)

Balance at December 31, 2020$— $1,672,734 $1,672,734

Net income— 166,834 166,834

Balance at December 31, 2021$— $1,839,568 $1,839,568

Net income (loss)(21,355)197,622 176,267

Capital contributions from noncontrolling interest24,702 — 24,702

Balance at December 31, 2022$3,347 $2,037,190 $2,040,537

Net income (loss)(10,302)192,271 181,969

Common equity distributions— (40,000)(40,000)

Capital contributions from noncontrolling interest25,708 — 25,708

Balance at December 31, 2023$18,753 $2,189,461 $2,208,214

See Notes to Financial Statements.

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ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

2023 Compared to 2022

Net Income

Net income increased $164.8 million primarily due to a $198.4 million reduction in income tax expense in 2023 as a result of the resolution of the 2016-2018 IRS audit, partially offset by a $60 million regulatory charge ($43.8 million net-of-tax) to reflect credits expected to be provided to customers, and higher retail electric price. The increase was partially offset by higher other operation and maintenance expenses. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit.

Operating Revenues

Following is an analysis of the change in operating revenues comparing 2023 to 2022:

Amount

(In Millions)

2022 operating revenues$997.3

Fuel, rider, and other revenues that do not significantly affect net income(174.6)

Volume/weather0.5

Storm restoration carrying costs5.2

Retail electric price15.5

2023 operating revenues$843.9

Entergy New Orleans’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.

The volume/weather variance is insignificant and primarily due to the effect of more favorable weather on commercial sales and an increase in weather-adjusted residential usage, partially offset by the effect of less favorable weather on residential sales.

Storm restoration carrying costs represent the equity component of storm restoration carrying costs, recorded in fourth quarter 2023, recognized as part of the City Council’s approval of the Hurricane Ida storm cost certification report in December 2023. See Note 2 to the financial statements for further discussion of the storm cost certification.

The retail electric price variance is primarily due to an increase in formula rate plan rates effective September 2022 in accordance with the terms of the 2022 formula rate plan filing. See Note 2 to the financial statements for further discussion of the formula rate plan filing.

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Entergy New Orleans, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Total electric energy sales for Entergy New Orleans for the years ended December 31, 2023 and 2022 are as follows:

20232022% Change

(GWh)

Residential2,364 2,410 (2)

Commercial2,126 2,096 1

Industrial423 411 3

Governmental783 789 (1)

Total retail 5,696 5,706 —

Sales for resale:

Non-associated companies2,818 2,298 23

Total8,514 8,004 6

See Note 19 to the financial statements for additional discussion of Entergy New Orleans’s operating revenues.

Other Income Statement Variances

Other operation and maintenance expenses increased primarily due to:

•an increase of $4.6 million in non-nuclear generation expenses primarily due to a higher scope of work performed in 2023 as compared to 2022;

•an increase of $4.5 million resulting from a gain on the sale of NOx allowances in 2022;

•an increase of $3.9 million in power delivery expenses primarily due to higher reliability costs and higher vegetation maintenance costs in 2023 as compared to 2022; and

•an increase of $3 million in contract costs related to operational performance, customer service, and organizational health initiatives.

The increase was partially offset by a decrease of $3 million in energy efficiency expenses primarily due to the timing of recovery from customers and lower energy efficiency costs.

Depreciation and amortization expenses increased primarily due to additions to plant in service.

Other regulatory charges (credits) - net includes a regulatory charge of $60 million, recorded in fourth quarter 2023, to reflect credits expected to be provided to customers as a result of the resolution of the 2016-2018 IRS audit. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit.

Other income increased primarily due to higher interest earned on money pool investments. The increase was partially offset by a decrease of $2.3 million due to the recognition of storm restoration carrying costs in 2022 related to Hurricane Ida and an increase in other postretirement benefit non-service costs as a result of the amortization of 2022 trust asset losses and non-qualified pension settlement charges. See Note 2 to the financial statements for further discussion of storm restoration costs. See “Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs.

Interest expense increased primarily due to a higher fixed interest rate on Entergy New Orleans’s unsecured term loan and interest on the $34 million regulatory liability recorded when Entergy New Orleans received a refund from System Energy in January 2023 related to the sale-leaseback renewal costs and depreciation litigation. The

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Entergy New Orleans, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

increase was partially offset by the repayment of $100 million of 3.9% Series mortgage bonds in July 2023. See Note 2 to the financial statements for further discussion of the refund and the related proceedings.

The effective income tax rates were (487.5%) for 2023 and 27.5% for 2022. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates and for additional discussion regarding income taxes.

2022 Compared to 2021

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy New Orleans’s Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 24, 2023, for discussion of results of operations for 2022 compared to 2021.

Income Tax Legislation and Regulation

See the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of income tax legislation and regulation.

Planned Sale of Gas Distribution Business

See the “Planned Sale of Gas Distribution Businesses” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the purchase and sale agreement for the sale of Entergy New Orleans’s gas distribution business.

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2023, 2022, and 2021 were as follows:

202320222021

(In Thousands)

Cash and cash equivalents at beginning of period$4,464 $42,862 $26

Net cash provided by (used in):

Operating activities202,956 363,763 78,808

Investing activities(18,802)(403,790)(169,920)

Financing activities(188,592)1,629 133,948

Net increase (decrease) in cash and cash equivalents(4,438)(38,398)42,836

Cash and cash equivalents at end of period$26 $4,464 $42,862

2023 Compared to 2022

Operating Activities

Net cash flow provided by operating activities decreased $160.8 million in 2023 primarily due to:

•net proceeds of $201.8 million received from the LURC in December 2022 from securitization. See Note 2 to the financial statements for further discussion of the storm securitization;

•lower receipts from associated companies in 2022;

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Entergy New Orleans, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

•an increase of $13.6 million in income taxes paid in 2023. Entergy New Orleans made net income tax payments in 2023 primarily related to the resolution of the 2016-2018 IRS audit and estimated federal and state income taxes. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit; and

•lower collections from customers.

The decrease was partially offset by:

•lower fuel costs and the timing of recovery of fuel and purchased power costs. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery;

•the refund of $34 million received from System Energy in January 2023 related to the sale-leaseback renewal costs and depreciation litigation as calculated in System Energy’s January 2023 compliance report filed with the FERC. See Note 2 to the financial statements for further discussion of the refund and the related proceedings; and

•a decrease of $18.7 million in storm spending primarily due to Hurricane Ida restoration efforts in 2022.

Investing Activities

Net cash flow used in investing activities decreased $385 million in 2023 primarily due to:

•money pool activity;

•a decrease of $71.3 million in net payments to the storm reserve escrow account in 2023; and

•a decrease of $42.9 million in distribution construction expenditures primarily due to higher capital expenditures for Hurricane Ida storm restoration efforts in 2022, partially offset by increased investment in the reliability and infrastructure of Entergy New Orleans’s distribution system in 2023.

Decreases in Entergy New Orleans’s receivable from the money pool are a source of cash flow, and Entergy New Orleans’s receivable from the money pool decreased $147.3 million in 2023 compared to increasing by $110.8 million in 2022. The money pool is an intercompany cash management program that makes possible intercompany borrowing and lending arrangements, and the money pool and other borrowing arrangements are designed to reduce the Registrant Subsidiaries’ dependence on external short-term borrowings.

Financing Activities

Entergy New Orleans’s financing activities used $188.6 million of cash in 2023 compared to providing $1.6 million of cash in 2022 primarily due to the following activity:

•$125 million in common equity distributions paid in 2023 in order to maintain Entergy New Orleans’s capital structure;

•the repayment, at maturity, of $100 million of 3.90% Series mortgage bonds in July 2023;

•additional borrowings of $15 million in May 2023 on an unsecured term loan due June 2024; and

•money pool activity.

Increases in Entergy New Orleans’s payable to the money pool are a source of cash flow, and Entergy New Orleans’s payable to the money pool increased $21.7 million in 2023.

See Note 5 to the financial statements for details on long-term debt.

2022 Compared to 2021

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy New Orleans’s Annual Report on Form 10-K for the year ended

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Entergy New Orleans, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

December 31, 2022, filed with the SEC on February 24, 2023, for discussion of operating, investing, and financing cash flow activities for 2022 compared to 2021.

Capital Structure

Entergy New Orleans’s debt to capital ratio is shown in the following table. The decrease in the debt to capital ratio for Entergy New Orleans is primarily due to net income in 2023 and the net retirement of long-term debt in 2023, partially offset by common equity distributions of $125 million in 2023.

December 31,2023December 31,2022

Debt to capital45.8 %52.6 %

Effect of excluding securitization bonds (0.2 %)(0.6 %)

Debt to capital, excluding securitization bonds (non-GAAP) (a)45.6 %52.0 %

Effect of subtracting cash— %(0.1 %)

Net debt to net capital, excluding securitization bonds (non-GAAP) (a)45.6 %51.9 %

(a)Calculation excludes the securitization bonds, which are non-recourse to Entergy New Orleans.

Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, long-term debt, including the currently maturing portion, and the long-term payable due to an associated company. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. The debt to capital ratio excluding securitization bonds and net debt to net capital ratio excluding securitization bonds are non-GAAP measures. Entergy New Orleans uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy New Orleans’s financial condition because the securitization bonds are non-recourse to Entergy New Orleans, as more fully described in Note 5 to the financial statements. Entergy New Orleans also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy New Orleans’s financial condition because net debt indicates Entergy New Orleans’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

Entergy New Orleans seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a distribution, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy New Orleans may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reduced distributions, Entergy New Orleans may receive equity contributions to maintain its capital structure.

Uses of Capital

Entergy New Orleans requires capital resources for:

•construction and other capital investments;

•working capital purposes, including the financing of fuel and purchased power costs;

•debt maturities or retirements; and

•distribution and interest payments.

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Entergy New Orleans, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Following are the amounts of Entergy New Orleans’s planned construction and other capital investments.

202420252026

(In Millions)

Planned construction and capital investment:

Generation$5 $15 $10

Transmission30 20 30

Distribution110 110 95

Utility Support20 15 30

Total$165 $160 $165

In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy New Orleans includes distribution and Utility support spending to deliver reliability, resilience, and customer experience; transmission spending to improve reliability and resilience; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, government actions, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.

Following are the amounts of Entergy New Orleans’s existing debt and lease obligations (includes estimated interest payments).

2024202520262027-2028 After 2028

(In Millions)

Long-term debt (a)$119 $101 $106 $39 $748

Operating leases (b)$2 $2 $1 $1 $1

Finance leases (b)$1 $1 $1 $1 $1

(a)Long-term debt is discussed in Note 5 to the financial statements.

(b)Lease obligations are discussed in Note 10 to the financial statements.

Other Obligations

Entergy New Orleans currently expects to contribute approximately $4.9 million to its qualified pension plan and approximately $205 thousand to other postretirement health care and life insurance plans in 2024, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024, valuations are completed, which is expected by April 1, 2024. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

Entergy New Orleans has $7.6 million of unrecognized tax benefits net of unused tax attributes plus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

In addition, Entergy New Orleans enters into fuel and purchased power agreements that contain minimum purchase obligations. Entergy New Orleans has rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations. See Note 8 to the financial statements for discussion of Entergy New Orleans’s obligations under the Unit Power Sales Agreement.

As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy New Orleans pays distributions from its earnings at a percentage determined monthly.

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Entergy New Orleans, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

System Resilience and Storm Hardening

In October 2021 the City Council passed a resolution and order establishing a docket and procedural schedule with respect to system resiliency and storm hardening. The docket will identify a plan for storm hardening and resiliency projects with other stakeholders. In July 2022, Entergy New Orleans filed with the City Council a response identifying a preliminary plan for storm hardening and resiliency projects, including microgrids, to be implemented over ten years at an approximate cost of $1.5 billion. In February 2023 the City Council approved a revised procedural schedule requiring Entergy New Orleans to make a filing in April 2023 containing a narrowed list of proposed hardening projects, with final comments on that filing due July 2023. In April 2023, Entergy New Orleans filed the required application and supporting testimony seeking City Council approval of the first phase (five years and $559 million) of a ten-year infrastructure hardening plan totaling approximately $1 billion. Entergy New Orleans also sought, among other relief, City Council approval of a rider to recover from customers the costs of the infrastructure hardening plan. In July 2023, Entergy New Orleans filed comments in support of its application. In February 2024 the City Council approved a resolution authorizing Entergy New Orleans to implement a resilience project to be partially funded by $55 million of matching funding through the Department of Energy’s Grid Resilience and Innovation Partnerships program. The resolution also requires Entergy New Orleans to submit, no later than July 2024, a revised resilience plan consisting of projects in three-year intervals. Entergy New Orleans continues to seek approval of its application.

Sources of Capital

Entergy New Orleans’s sources to meet its capital requirements include:

•internally generated funds;

•cash on hand;

•the Entergy system money pool;

•storm reserve escrow accounts;

•debt and preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;

•capital contributions; and

•bank financing under new or existing facilities.

Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations, Entergy New Orleans expects to continue, when economically feasible, to retire higher-cost debt and replace it with lower-cost debt if market conditions permit.

All debt and common and preferred membership interest issuances by Entergy New Orleans require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in its bond indenture and other agreements. Entergy New Orleans has sufficient capacity under these tests to meet its foreseeable capital needs for the next twelve months and beyond.

Entergy New Orleans’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.

2023202220212020

(In Thousands)

($21,651)$147,254$36,410($10,190)

See Note 4 to the financial statements for a description of the money pool.

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Entergy New Orleans, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Entergy New Orleans has a credit facility in the amount of $25 million scheduled to expire in June 2024. The credit facility includes fronting commitments for the issuance of letters of credit against $10 million of the borrowing capacity of the facility. As of December 31, 2023, there were no cash borrowings and no letters of credit outstanding under the credit facility. In addition, Entergy New Orleans is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2023, a $0.5 million letter of credit was outstanding under Entergy New Orleans’s uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.

Entergy New Orleans obtained authorization from the FERC through April 2025 for short-term borrowings not to exceed an aggregate amount of $150 million at any time outstanding and long-term borrowings and securities issuances. See Note 4 to the financial statements for further discussion of Entergy New Orleans’s short-term borrowing limits. The long-term securities issuances of Entergy New Orleans are limited to amounts authorized not only by the FERC, but also by the City Council, and the current City Council authorization extends through December 2025.

State and Local Rate Regulation

The rates that Entergy New Orleans charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy New Orleans is regulated, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the City Council, is primarily responsible for approval of the rates charged to customers.

Retail Rates

2021 Formula Rate Plan Filing

In July 2021, Entergy New Orleans submitted to the City Council its formula rate plan 2020 test year filing. The 2020 test year evaluation report produced an earned return on equity of 6.26% compared to the authorized return on equity of 9.35%. Entergy New Orleans sought approval of a $64 million rate increase based on the formula set by the City Council in the 2018 rate case. The formula resulted in an increase in authorized electric revenues of $40 million and an increase in authorized gas revenues of $18.8 million. Entergy New Orleans also sought to commence collecting $5.2 million in electric revenues and $0.3 million in gas revenues that were previously approved by the City Council for collection through the formula rate plan. The filing was subject to review by the City Council and other parties over a 75-day review period, followed by a 25-day period to resolve any disputes among the parties. In October 2021 the City Council’s advisors filed a 75-day report recommending a reduction of $10 million for electric revenues and a reduction of $4.5 million for gas revenues, along with one-time credits funded by certain electric regulatory liabilities currently held by Entergy New Orleans for customers. On October 26, 2021, Entergy New Orleans provided notice to the City Council that it intends to implement rates effective with the first billing cycle of November 2021, with such rates reflecting an amount agreed-upon by Entergy New Orleans including adjustments filed in the City Council’s 75-day report, per the approved process for formula rate plan implementation. The total formula rate plan increase implemented was $49.5 million, with an increase of $34.9 million in electric revenues and $14.6 million in gas revenues. Also, credits of $17.4 million funded by certain regulatory liabilities currently held by Entergy New Orleans for customers will be issued over a five-month period from November 2021 through March 2022. Resulting rates went into effect with the first billing cycle of November 2021 pursuant to the formula rate plan tariff.

2022 Formula Rate Plan Filing

In April 2022, Entergy New Orleans submitted to the City Council its formula rate plan 2021 test year filing. The 2021 test year evaluation report, subsequently updated in a July 2022 filing, produced an earned return on equity of 6.88% compared to the authorized return on equity of 9.35%. Entergy New Orleans sought approval of

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Management’s Financial Discussion and Analysis

a $42.1 million rate increase based on the formula set by the City Council in the 2018 rate case. The formula resulted in an increase in authorized electric revenues of $34.1 million and an increase in authorized gas revenues of $3.3 million. Entergy New Orleans also sought to commence collecting $4.7 million in electric revenues that were previously approved by the City Council for collection through the formula rate plan. In July 2022 the City Council’s advisors issued a report seeking a reduction to Entergy New Orleans’s proposed increase of approximately $17.1 million in total for electric and gas revenues. Effective with the first billing cycle of September 2022, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council including adjustments filed in the City Council’s advisors’ report, per the approved process for formula rate plan implementation. The total formula rate plan increase implemented was $24.7 million, which includes an increase of $18.2 million in electric revenues, $4.7 million in previously approved electric revenues, and an increase of $1.8 million in gas revenues. Additionally, credits of $13.9 million funded by certain regulatory liabilities currently held by Entergy New Orleans for customers were issued over an eight-month period beginning September 2022.

2023 Formula Rate Plan Filing

In April 2023, Entergy New Orleans submitted to the City Council its formula rate plan 2022 test year filing. The 2022 test year evaluation report produced an electric earned return on equity of 7.34% and a gas earned return on equity of 3.52% compared to the authorized return on equity for each of 9.35%. Entergy New Orleans sought approval of a $25.6 million rate increase based on the formula set by the City Council in the 2018 rate case. The formula would result in an increase in authorized electric revenues of $17.4 million and an increase in authorized gas revenues of $8.2 million. Entergy New Orleans also sought to commence collecting $3.4 million in electric revenues that were previously approved by the City Council for collection through the formula rate plan. In July 2023, Entergy New Orleans filed a report to decrease its requested formula rate plan revenues by approximately $0.5 million to account for minor errors discovered after the filing. The City Council advisors issued a report seeking a reduction in the requested formula rate plan revenues of approximately $8.3 million, combined for electric and gas, due to alleged errors. The City Council advisors proposed additional rate mitigation in the amount of $12 million through offsets to the formula rate plan rate increase by certain regulatory liabilities. In September 2023 the City Council approved an agreement to settle the 2023 formula rate plan filing. Effective with the first billing cycle of September 2023, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council, per the approved process for formula rate plan implementation. The agreement provides for a total increase in electric revenues of $10.5 million and a total increase in gas revenues of $6.9 million. The agreement also provides for a minor storm accrual of $0.5 million per year and the distribution of $8.9 million of currently held customer credits to implement the City Council advisors’ mitigation recommendations.

Request for Extension and Modification of Formula Rate Plan

In September 2023, Entergy New Orleans filed a motion seeking City Council approval of a three-year extension of Entergy New Orleans’s electric and gas formula rate plans. In October 2023 the City Council granted Entergy New Orleans’s request for an extension, subject to minor modifications which included a 55% fixed capital structure for rate setting purposes.

Fuel and purchased power cost recovery

Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.

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Entergy New Orleans, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.

Reliability Investigation

In August 2017 the City Council established a docket to investigate the reliability of the Entergy New Orleans distribution system and to consider implementing certain reliability standards and possible financial penalties for not meeting any such standards. In April 2018 the City Council adopted a resolution directing Entergy New Orleans to demonstrate that it has been prudent in the management and maintenance of the reliability of its distribution system. The resolution also called for Entergy New Orleans to file a revised reliability plan addressing the current state of its distribution system and proposing remedial measures for increasing reliability. In June 2018, Entergy New Orleans filed its response to the City Council’s resolution regarding the prudence of its management and maintenance of the reliability of its distribution system. In July 2018, Entergy New Orleans filed its revised reliability plan discussing the various reliability programs that it uses to improve distribution system reliability and discussing generally the positive effect that advanced meter deployment and grid modernization can have on future reliability. Entergy New Orleans retained a national consulting firm with expertise in distribution system reliability to conduct a review of Entergy New Orleans’s distribution system reliability-related practices and procedures and to provide recommendations for improving distribution system reliability. The report was filed with the City Council in October 2018. The City Council also approved a resolution that opened a prudence investigation into whether Entergy New Orleans was imprudent for not acting sooner to address outages in New Orleans and whether fines should be imposed. In January 2019, Entergy New Orleans filed testimony in response to the prudence investigation asserting that it had been prudent in managing system reliability. In April 2019 the City Council advisors filed comments and testimony asserting that Entergy New Orleans did not act prudently in maintaining and improving its distribution system reliability in recent years and recommending that a financial penalty in the range of $1.5 million to $2 million should be assessed. Entergy New Orleans disagreed with the recommendation and submitted rebuttal testimony and rebuttal comments in June 2019. In November 2019 the City Council passed a resolution that penalized Entergy New Orleans $1 million for alleged imprudence in the maintenance of its distribution system. In December 2019, Entergy New Orleans filed suit in Louisiana state court seeking judicial review of the City Council’s resolution. In June 2022 the Orleans Civil District Court issued a written judgment that the penalty be set aside, reversed, and vacated. In August 2022 the Orleans Civil District Court issued written reasons for its judgment and also granted a post-judgment motion to remand for the City Council to take actions consistent with its judgment.

Also in August 2022 the City Council approved a resolution establishing a 30-day comment period on proposed minimum reliability standards and an associated penalty mechanism. In September 2022, Entergy New Orleans filed comments to the proposed plan including a request for an additional round of comments. In February 2023 the City Council approved a resolution adopting the proposed reliability standards, including a minimum annual performance level for Entergy New Orleans’s distribution system, as well as associated penalty mechanisms. In April 2023, Entergy New Orleans filed the compliance filings required by the resolution for calendar year 2023. The first year for which the City Council may assess a penalty for distribution system reliability performance is calendar year 2024.

In April 2023 the City Council approved a resolution that established a procedural schedule to allow for the submission of additional evidence regarding the penalty imposed in 2019. In May 2023, Entergy New Orleans filed with the Orleans Civil District Court a petition for judicial review and (or alternatively) declaratory judgment of, together with a request for injunctive relief from, the City Council’s April 2023 resolution. In June 2023 the City Council filed exceptions requesting the Orleans Civil District Court dismiss the suit as premature, and a hearing date was set on the exceptions. In September 2023, Entergy New Orleans filed an unopposed motion to continue the hearing on the City Council’s exceptions without date, which was granted. Entergy New Orleans expects to file its opposition to the City Council’s exceptions by the applicable deadlines. In January 2024 the City Council approved

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Entergy New Orleans, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

a modified procedural schedule in which the hearing officer shall certify the record of the proceeding for City Council consideration no later than July 2024.

Renewable Portfolio Standard Rulemaking

In March 2019 the City Council initiated a rulemaking proceeding to consider whether to establish a renewable portfolio standard. The four components of the Renewable and Clean Portfolio Standard that the City Council expressed a desire to implement were: (1) a mandatory requirement that Entergy New Orleans achieve 100% net zero carbon emissions by 2040; (2) reliance on renewable energy credits purchased without the associated energy for compliance with the standard being phased out over the ten-year period from 2040 to 2050; (3) no carbon-emitting resources in the portfolio of resources Entergy New Orleans uses to serve New Orleans by 2050; and (4) a mechanism to limit costs in any one plan year to no more than one percent of plan year total utility retail sales revenues. The City Council adopted the Utility Committee resolution in April 2020. The City Council approved the rule in May 2021, establishing the Renewable and Clean Portfolio Standard.

In March 2022 the City Council approved Entergy New Orleans’s initial compliance plan and established an alternative compliance payment value of $8.45 per MWh, which Entergy New Orleans will pay if it is unable to comply with the Renewable and Clean Portfolio Standard for the 2022 compliance year. Such compliance payments are paid into a clean energy fund established by the City Council. The City Council also approved the electric vehicle credit calculation methodology for use in the compliance demonstration report for 2022, to be filed prior to May 1, 2023. Entergy New Orleans’s proposal to create a 5% contingency reserve was considered reasonable for the initial compliance plan.

In August 2022, Entergy New Orleans submitted its compliance plan covering compliance years 2023-2025. After receiving comments from intervenors and Entergy New Orleans, in December 2022 the City Council adopted a resolution that (a) approved Entergy New Orleans's proposal to purchase unbundled renewable energy credits, as needed; (b) denied Entergy New Orleans’s request to treat the Sewerage and Water Board’s 230 kV Sullivan substation electrification as a “qualified measure;” (c) approved the alternative compliance payment for years 2023-2025 at $8.45 per MWh; and (d) approved the Tier 3 credit calculations for electric vehicle charging infrastructure but denied the request to approve a Tier 3 credit for the Sewerage and Water Board substation electrification project at this time while the substation is not yet in service.

In May 2023, Entergy New Orleans submitted its compliance demonstration report to the City Council for the 2022 compliance year, which describes and demonstrates Entergy New Orleans’s compliance with the Renewable and Clean Portfolio Standard in 2022 and satisfies certain informational requirements. Entergy New Orleans requested, among other things, that the City Council determine that Entergy New Orleans achieved the target under the portfolio standard for 2022 and remains within the customer protection cost cap, and that the City Council approve a proposal to recover costs associated with 2022 compliance. In July 2023 intervenors filed comments on the compliance demonstration report, and Entergy New Orleans responded to those comments in August 2023.

Federal Regulation

See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.

Nuclear Matters

See the “Nuclear Matters” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of nuclear matters.

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Management’s Financial Discussion and Analysis

Environmental Risks

Entergy New Orleans’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy New Orleans is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Critical Accounting Estimates

The preparation of Entergy New Orleans’s financial statements in conformity with GAAP requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in these assumptions and measurements could produce estimates that would have a material effect on the presentation of Entergy New Orleans’s financial position, results of operations, or cash flows.

Utility Regulatory Accounting

See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.

Taxation and Uncertain Tax Positions

See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.

Qualified Pension and Other Postretirement Benefits

Entergy New Orleans’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are affected by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.

Cost Sensitivity

The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).

Actuarial AssumptionChange in AssumptionImpact on 2024 Qualified Pension CostImpact on 2023 Qualified Projected Benefit Obligation

Increase/(Decrease)

Discount rate(0.25%)$93$3,124

Rate of return on plan assets(0.25%)$305$—

Rate of increase in compensation0.25%$132$538

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Entergy New Orleans, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

The following chart reflects the sensitivity of postretirement benefits cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).

Actuarial AssumptionChange in AssumptionImpact on 2024 Postretirement Benefits CostImpact on 2023 Accumulated Postretirement Benefit Obligation

Increase/(Decrease)

Discount rate(0.25%)$32$494

Health care cost trend0.25%$49$282

Each fluctuation above assumes that the other components of the calculation are held constant.

Costs and Employer Contributions

Total qualified pension cost for Entergy New Orleans in 2023 was $3.7 million, including $2.1 million in settlement costs. Entergy New Orleans anticipates 2024 qualified pension cost to be $1.1 million. Entergy New Orleans contributed $1.4 million to its qualified pension plans in 2023 and estimates 2024 pension contributions will be approximately $4.9 million, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024 valuations are completed, which is expected by April 1, 2024.

Total postretirement health care and life insurance benefit income for Entergy New Orleans in 2023 was $4.3 million. Entergy New Orleans expects 2024 postretirement health care and life insurance benefit income of approximately $5.5 million. Entergy New Orleans contributed $213 thousand to its other postretirement plans in 2023 and estimates 2024 contributions will be approximately $205 thousand.

Other Contingencies

See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.

New Accounting Pronouncements

See the “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the member and Board of Directors of

Entergy New Orleans, LLC and Subsidiaries

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Entergy New Orleans, LLC and Subsidiaries (the “Company”) as of December 31, 2023 and 2022, the related consolidated statements of income, cash flows, and changes in member’s equity (pages 412 through 416 and applicable items in pages 47 through 238), for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Rate and Regulatory Matters — Entergy New Orleans, LLC and Subsidiaries — Refer to Note 2 to the financial statements

Critical Audit Matter Description

The Company is subject to rate regulation by the Council of the City of New Orleans, Louisiana (the “City Council”), which has jurisdiction with respect to the rates of electric companies in the City of New Orleans, Louisiana, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based

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rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.

The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the City Council and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the City Council and the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.

We identified the impact of rate regulation as a critical audit matter due to the judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs and refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the City Council and the FERC, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities involved specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and auditor judgment to evaluate management estimates and the subjectivity of audit evidence.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertainty of future decisions by the City Council and the FERC, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities included the following, among others:

•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

•We read relevant regulatory orders issued by the City Council and the FERC for the Company to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the City Council’s and the FERC’s treatment of similar costs under similar circumstances. We evaluated external information and compared to management’s recorded regulatory asset and liability balances for completeness.

•For regulatory matters in process, we inspected the Company’s filings with the City Council and the FERC and orders issued, and considered the filings with the City Council and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.

•We obtained an analysis from management and support from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.

•We obtained representation from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management’s assertion that amounts are probable of recovery, refund, or a future reduction in rates.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 23, 2024

We have served as the Company’s auditor since 2001.

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ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES

CONSOLIDATED INCOME STATEMENTS

For the Years Ended December 31,

202320222021

(In Thousands)

OPERATING REVENUES

Electric$737,974 $855,248 $672,231

Natural gas105,959 142,085 96,621

TOTAL843,933 997,333 768,852

OPERATING EXPENSES

Operation and Maintenance:

Fuel, fuel-related expenses, and gas purchased for resale122,400 244,994 150,018

Purchased power268,478 314,283 268,568

Other operation and maintenance167,719 156,653 145,377

Taxes other than income taxes62,979 63,743 53,569

Depreciation and amortization81,282 76,938 73,480

Other regulatory charges (credits) - net69,211 19,596 13,177

TOTAL772,069 876,207 704,189

OPERATING INCOME71,864 121,126 64,663

OTHER INCOME

Allowance for equity funds used during construction1,470 829 2,371

Interest and investment income7,154 742 48

Miscellaneous - net(4,119)(21)(1,240)

TOTAL4,505 1,550 1,179

INTEREST EXPENSE

Interest expense38,118 34,829 29,164

Allowance for borrowed funds used during construction(714)(531)(1,056)

TOTAL37,404 34,298 28,108

INCOME BEFORE INCOME TAXES38,965 88,378 37,734

Income taxes(189,973)24,277 5,936

NET INCOME$228,938 $64,101 $31,798

See Notes to Financial Statements.

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ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31,

202320222021

(In Thousands)

OPERATING ACTIVITIES

Net income$228,938 $64,101 $31,798

Adjustments to reconcile net income to net cash flow provided by operating activities:

Depreciation and amortization81,282 76,938 73,480

Deferred income taxes, investment tax credits, and non-current taxes accrued(191,326)18,685 12,573

Changes in assets and liabilities:

Receivables29,944 6,128 (42,612)

Fuel inventory2,574 (2,927)(967)

Accounts payable(11,924)21 22,457

Prepaid taxes and taxes accrued(11,882)5,923 (315)

Interest accrued454 89 (104)

Deferred fuel costs4,005 (17,760)9,737

Other working capital accounts(9,184)(790)(3,233)

Provisions for estimated losses1,076 80,719 (83,569)

Other regulatory assets19,745 46,505 18,173

Other regulatory liabilities 66,022 (8,639)4,985

Effect of securitization on regulatory asset— 95,920 —

Pension and other postretirement liabilities(16,371)9,769 (32,144)

Other assets and liabilities9,603 (10,919)68,549

Net cash flow provided by operating activities202,956 363,763 78,808

INVESTING ACTIVITIES

Construction expenditures(164,279)(217,864)(220,284)

Allowance for equity funds used during construction1,470 829 2,371

Changes in money pool receivable - net147,254 (110,844)(36,410)

Payments to storm reserve escrow account(3,731)(200,000)(7)

Receipts from storm reserve escrow account— 125,000 83,045

Changes in securitization account(191)(236)1,365

Decrease (increase) in other investments675 (675)—

Net cash flow used in investing activities(18,802)(403,790)(169,920)

FINANCING ACTIVITIES

Proceeds from the issuance of long-term debt14,610 — 183,403

Retirement of long-term debt(112,525)(12,207)(36,873)

Repayment of long-term payable due to associated company(1,306)(1,326)(1,618)

Contributions from customer for construction15,000 15,000 —

Changes in money pool payable - net21,651 — (10,190)

Common equity distributions paid(125,000)— —

Other(1,022)162 (774)

Net cash flow provided by (used in) financing activities(188,592)1,629 133,948

Net increase (decrease) in cash and cash equivalents(4,438)(38,398)42,836

Cash and cash equivalents at beginning of period4,464 42,862 26

Cash and cash equivalents at end of period$26 $4,464 $42,862

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:

Cash paid (received) during the period for:

Interest - net of amount capitalized$36,263 $33,343 $28,009

Income taxes$14,120 $499 ($3,839)

Noncash investing activities:

Accrued construction expenditures$7,068 $11,152 $—

See Notes to Financial Statements.

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ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31,

20232022

(In Thousands)

CURRENT ASSETS

Cash and cash equivalents:

Cash$26 $27

Temporary cash investments— 4,437

Total cash and cash equivalents26 4,464

Securitization recovery trust account2,426 2,235

Accounts receivable:

Customer67,258 93,288

Allowance for doubtful accounts(7,770)(11,909)

Associated companies1,657 149,927

Other5,270 6,110

Accrued unbilled revenues31,087 37,284

Total accounts receivable97,502 274,700

Deferred fuel costs6,148 10,153

Fuel inventory - at average cost3,298 5,872

Materials and supplies - at average cost30,019 22,498

Prepaid taxes1,574 —

Prepayments and other11,482 6,312

TOTAL152,475 326,234

OTHER PROPERTY AND INVESTMENTS

Non-utility property - at cost (less accumulated depreciation)832 1,050

Storm reserve escrow account78,731 75,000

Other— 675

TOTAL79,563 76,725

UTILITY PLANT

Electric2,046,928 1,934,837

Natural gas401,846 390,252

Construction work in progress25,424 39,607

TOTAL UTILITY PLANT2,474,198 2,364,696

Less - accumulated depreciation and amortization858,672 808,224

UTILITY PLANT - NET1,615,526 1,556,472

DEFERRED DEBITS AND OTHER ASSETS

Regulatory assets:

Other regulatory assets (includes securitization property of $506 as of December 31, 2023 and $13,363 as of December 31, 2022)

182,367 202,112

Deferred fuel costs4,080 4,080

Other63,964 46,778

TOTAL250,411 252,970

TOTAL ASSETS$2,097,975 $2,212,401

See Notes to Financial Statements.

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ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

December 31,

20232022

(In Thousands)

CURRENT LIABILITIES

Currently maturing long-term debt$85,000 $170,000

Payable due to associated company1,275 1,306

Accounts payable:

Associated companies76,736 53,258

Other39,813 57,291

Customer deposits32,420 31,826

Taxes accrued— 10,308

Interest accrued8,534 8,080

Other8,953 6,560

TOTAL252,731 338,629

NON-CURRENT LIABILITIES

Accumulated deferred income taxes and taxes accrued195,615 385,259

Accumulated deferred investment tax credits16,457 16,481

Regulatory liability for income taxes - net36,061 39,738

Other regulatory liabilities90,434 20,735

Accumulated provisions88,124 87,048

Long-term debt (includes securitization bonds of $5,415 as of December 31, 2023 and $17,697 as of December 31, 2022)

584,171 596,047

Long-term payable due to associated company7,004 8,279

Other20,624 17,369

TOTAL1,038,490 1,170,956

Commitments and Contingencies

EQUITY

Member's equity806,754 702,816

TOTAL806,754 702,816

TOTAL LIABILITIES AND EQUITY$2,097,975 $2,212,401

See Notes to Financial Statements.

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CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY

For the Years Ended December 31, 2023, 2022, and 2021

Member’s Equity

(In Thousands)

Balance at December 31, 2020$606,917

Net income31,798

Balance at December 31, 2021$638,715

Net income64,101

Balance at December 31, 2022$702,816

Net income228,938

Common equity distributions(125,000)

Balance at December 31, 2023$806,754

See Notes to Financial Statements.

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MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

2023 Compared to 2022

Net Income

Net income decreased $12.1 million primarily due to higher depreciation and amortization expenses, the recognition of the equity component of carrying costs as part of the securitization of the Hurricane Laura, Hurricane Delta, and Winter Storm Uri system restoration costs in April 2022, and higher taxes other than income taxes. The decrease was partially offset by higher retail electric price and higher other income.

Operating Revenues

Following is an analysis of the change in operating revenues comparing 2023 to 2022.

Amount

(In Millions)

2022 operating revenues$2,288.9

Fuel, rider, and other revenues that do not significantly affect net income(331.8)

System restoration carrying costs(21.7)

Volume/weather8.4

Return of unprotected excess accumulated deferred income taxes to customers26.6

Retail electric price58.2

2023 operating revenues$2,028.6

Entergy Texas’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.

System restoration carrying costs represent the equity component of system restoration carrying costs recognized as part of the securitization of the Hurricane Laura, Hurricane Delta, and Winter Storm Uri system restoration costs in April 2022. See Note 2 to the financial statements for a discussion of the securitization.

The volume/weather variance is primarily due to an increase in weather-adjusted residential usage and an increase in commercial usage, partially offset by the effect of less favorable weather on residential sales and a decrease in demand from cogeneration customers. The increase in weather-adjusted residential usage was primarily due to an increase in customers.

The return of unprotected excess accumulated deferred income taxes to customers resulted from the return of unprotected excess accumulated deferred income taxes through a rider effective October 2018 in response to the enactment of the Tax Cuts and Jobs Act. There was no return of unprotected excess accumulated deferred income taxes to customers in 2023. In 2022, $26.6 million was returned to customers through reductions in operating revenues. There was no effect on net income as the reductions in operating revenues were offset by reductions in

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income tax expense. See Note 2 to the financial statements for discussion of regulatory activity regarding the Tax Cuts and Jobs Act.

The retail electric price variance is primarily due to an increase in base rates, including the realignment of the costs previously being collected through the distribution and transmission cost recovery factor riders and the generation cost recovery rider to base rates, effective June 2023 on an interim basis and approved by the PUCT in August 2023. See Note 2 to the financial statements for discussion of the 2022 base rate case.

Total electric energy sales for Entergy Texas for the years ended December 31, 2023 and 2022 are as follows:

20232022% Change

(GWh)

Residential6,731 6,779 (1)

Commercial4,797 4,758 1

Industrial9,343 9,572 (2)

Governmental275 271 1

Total retail 21,146 21,380 (1)

Sales for resale:

Associated companies— 279 (100)

Non-associated companies462 813 (43)

Total21,608 22,472 (4)

See Note 19 to the financial statements for additional discussion of Entergy Texas’s operating revenues.

Other Income Statement Variances

Other operation and maintenance expenses increased primarily due to:

•an increase of $12.2 million in power delivery expenses primarily due to higher vegetation maintenance costs;

•an increase of $7 million in contract costs related to operational performance, customer service, and organizational health initiatives;

•an increase of $2.4 million in loss provisions; and

•several individually insignificant items.

The increase was partially offset by a decrease of $9.5 million in transmission costs allocated by MISO and a gain of $6.9 million on the partial sale of a service center in April 2023 as part of an eminent domain proceeding.

Taxes other than income taxes increased primarily due to increases in ad valorem taxes resulting from higher assessments.

Depreciation and amortization expenses increased primarily due to an increase in depreciation rates effective with an interim increase in base rates in June 2023, which was approved by the PUCT in August 2023, and additions to plant in service. See Note 2 to the financial statements for discussion of the 2022 base rate case.

Other regulatory charges (credits) - net includes the reversal in third quarter 2023 of $21.9 million of regulatory liabilities to reflect the recognition of certain receipts by Entergy Texas under affiliated PPAs that have been resolved. See Note 2 to the financial statements for discussion of the 2022 base rate case.

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Other income increased primarily due to an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2023, including the Orange County Advanced Power Station project, and higher interest earned on money pool investments.

Interest expense increased primarily due to the issuance of $325 million of 5.00% Series mortgage bonds in August 2022 and the issuance of $350 million of 5.80% Series mortgage bonds in August 2023, partially offset by an increase in the allowance for borrowed funds used during construction due to higher construction work in progress in 2023, including the Orange County Advanced Power Station project.

The effective income tax rates were 17.8% for 2023 and 14.3% for 2022. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates and for additional discussion regarding income taxes.

2022 Compared to 2021

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy Texas’s Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 24, 2023, for discussion of results of operations for 2022 compared to 2021.

Income Tax Legislation and Regulation

See the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of income tax legislation and regulation.

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2023, 2022, and 2021 were as follows:

202320222021

(In Thousands)

Cash and cash equivalents at beginning of period$3,497 $28 $248,596

Net cash provided by (used in):

Operating activities641,691 409,427 356,933

Investing activities(1,125,948)(764,069)(647,271)

Financing activities502,746 358,111 41,770

Net increase (decrease) in cash and cash equivalents18,489 3,469 (248,568)

Cash and cash equivalents at end of period$21,986 $3,497 $28

2023 Compared to 2022

Operating Activities

Net cash flow provided by operating activities increased $232.3 million in 2023 primarily due to lower fuel costs and the timing of recovery of fuel and purchased power costs. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery. The increase was partially offset by:

•lower collections from customers;

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•the timing of payments to vendors;

•an increase of $27.1 million in income taxes paid in 2023 as a result of higher estimated income tax payments in comparison to 2022; and

•an increase of $17.1 million in interest paid.

Investing Activities

Net cash flow used in investing activities increased $361.9 million in 2023 primarily due to:

•an increase of $162.3 million in non-nuclear generation construction expenditures primarily due to higher spending on the Orange County Advanced Power Station project;

•money pool activity;

•an increase of $73.5 million in transmission construction expenditures primarily due to increased investment in the reliability and infrastructure of Entergy Texas’s transmission system; and

•an increase of $27.6 million in distribution construction expenditures primarily due to higher capital expenditures for storm restoration in 2023.

The increase was partially offset by the partial sale of a service center in April 2023 for $11 million as part of an eminent domain proceeding.

Increases in Entergy Texas’s receivable from the money pool are a use of cash flow, and Entergy Texas’s receivable from the money pool increased $218.4 million in 2023 compared to increasing by $99.5 million in 2022. The money pool is an intercompany cash management program that makes possible intercompany borrowing and lending arrangements, and the money pool and other borrowing arrangements are designed to reduce the Registrant Subsidiaries’ dependence on external short-term borrowings.

Financing Activities

Net cash flow provided by financing activities increased $144.6 million in 2023 primarily due to:

•the issuance of $350 million of 5.80% Series mortgage bonds in August 2023;

•a capital contribution of $150 million received from Entergy Corporation in 2023 in order to maintain Entergy Texas’s capital structure and in anticipation of various capital expenditures;

•the payment of $105 million of common stock dividends in 2022. No common stock dividends were paid in 2023 in order to maintain Entergy Texas’s capital structure;

•money pool activity;

•principal payments of $17.8 million on securitization bonds in 2023 as compared to principal payments of $66.5 million on securitization bonds in 2022; and

•an increase of $22.8 million in prepaid deposits related to contributions-in-aid-of-construction primarily for customer and generator interconnection agreements.

The increase was partially offset by the issuance of $325 million of 5.00% Series mortgage bonds in August 2022 and the issuance of $290.85 million of senior secured system restoration bonds in April 2022.

Decreases in Entergy Texas’s payable to the money pool are a use of cash flow, and Entergy Texas’s payable to the money pool decreased $79.6 million in 2022.

See Note 5 to the financial statements for further details of long-term debt.

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2022 Compared to 2021

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Texas’s Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 24, 2023, for discussion of operating, investing, and financing cash flow activities for 2022 compared to 2021.

Capital Structure

Entergy Texas’s debt to capital ratio is shown in the following table. The decrease in the debt to capital ratio is primarily due to net income in 2023 and the capital contribution of $150 million received from Entergy Corporation in 2023, partially offset by the issuance of long-term debt in 2023.

December 31,2023December 31,2022

Debt to capital50.9 %52.0 %

Effect of excluding securitization bonds(2.1 %)(2.5 %)

Debt to capital, excluding securitization bonds (non-GAAP) (a)48.8 %49.5 %

Effect of subtracting cash(0.2 %)— %

Net debt to net capital, excluding securitization bonds (non-GAAP) (a)48.6 %49.5 %

(a)Calculation excludes the securitization bonds, which are non-recourse to Entergy Texas.

Net debt consists of debt less cash and cash equivalents. Debt consists of finance lease obligations and long-term debt, including the currently maturing portion. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. The debt to capital ratio excluding securitization bonds and net debt to net capital ratio excluding securitization bonds are non-GAAP measures. Entergy Texas uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy Texas’s financial condition because the securitization bonds are non-recourse to Entergy Texas, as more fully described in Note 5 to the financial statements. Entergy Texas also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Texas’s financial condition because net debt indicates Entergy Texas’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

Entergy Texas seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Texas may issue incremental debt or reduce dividends, or both, to maintain its capital structure. In addition, Entergy Texas may receive equity contributions to maintain its capital structure for certain circumstances such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reduced dividends.

Uses of Capital

Entergy Texas requires capital resources for:

•construction and other capital investments;

•debt maturities or retirements;

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•working capital purposes, including the financing of fuel and purchased power costs; and

•dividend and interest payments.

Following are the amounts of Entergy Texas’s planned construction and other capital investments.

202420252026

(In Millions)

Planned construction and capital investment:

Generation$445 $935 $1,205

Transmission320 305 370

Distribution475 365 315

Utility Support50 25 90

Total$1,290 $1,630 $1,980

In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Texas includes investments in generation projects to modernize, decarbonize, and diversify Entergy Texas’s portfolio, including Orange County Advanced Power Station; distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to improve reliability and resilience while also supporting renewables expansion and customer growth; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, government actions, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.

Following are the amounts of Entergy Texas’s existing debt and lease obligations (includes estimated interest payments).

2024202520262027-2028 After 2028

(In Millions)

Long-term debt (a)$141 $141 $270 $422 $4,537

Operating leases (b)$7 $6 $5 $4 $2

Finance leases (b)$2 $2 $2 $3 $1

(a)Long-term debt is discussed in Note 5 to the financial statements.

(b)Lease obligations are discussed in Note 10 to the financial statements.

Other Obligations

Entergy Texas expects to contribute approximately $8.3 million to its qualified pension plans and approximately $156 thousand to other postretirement health care and life insurance plans in 2024, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024, valuations are completed, which is expected by April 1, 2024. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

Entergy Texas has $33.6 million of unrecognized tax benefits net of unused tax attributes plus interest and payments for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

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In addition, Entergy Texas enters into fuel and purchased power agreements that contain minimum purchase obligations. Entergy Texas has rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations.

As a subsidiary, Entergy Texas dividends its earnings to Entergy Corporation at a percentage determined monthly.

Orange County Advanced Power Station

In September 2021, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the Orange County Advanced Power Station, a new 1,215 MW combined-cycle combustion turbine facility to be located in Bridge City, Texas at an initially-estimated expected total cost of $1.2 billion inclusive of the estimated costs of the generation facilities, transmission upgrades, contingency, an allowance for funds used during construction, and necessary regulatory expenses, among others. The project includes combustion turbine technology with dual fuel capability, able to co-fire up to 30% hydrogen by volume upon commercial operation and upgradable to support 100% hydrogen operations in the future. In December 2021 the PUCT referred the proceeding to the State Office of Administrative Hearings. In March 2022 certain intervenors filed testimony opposing the hydrogen co-firing component of the proposed project and others filed testimony opposing the project outright. Also in March 2022 the PUCT staff filed testimony opposing the hydrogen co-firing component of the proposed project, but otherwise taking no specific position on the merits of the project. The PUCT staff also proposed that the PUCT establish a maximum amount that Entergy Texas may recover in rates attributable to the project. In April 2022, Entergy Texas filed rebuttal testimony addressing and rebutting these various arguments. The hearing on the merits was held in June 2022, and post-hearing briefs were submitted in July 2022. In September 2022 the ALJs with the State Office of Administrative Hearings issued a proposal for decision recommending the PUCT approve Entergy Texas’s application for certification of Orange County Advanced Power Station subject to certain conditions, including a cap on cost recovery at $1.37 billion, the exclusion of investment associated with co-firing hydrogen, weatherization requirements, and customer receipt of any contractual benefits associated with the facility’s guaranteed heat rate. In October 2022 the parties in the proceeding filed exceptions and replies to exceptions to the proposal for decision. Also in October 2022, Entergy Texas filed with the PUCT information regarding a new fixed pricing option for an estimated project cost of approximately $1.55 billion associated with Entergy Texas’s issuance of limited notice to proceed by mid-November 2022. In November 2022 the PUCT issued a final order approving the requested amendment to Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the Orange County Advanced Power Station without the investment associated with hydrogen co-firing capability, without a cap on cost recovery, and subject to certain conditions, including weatherization requirements and customer receipt of any contractual benefits associated with the facility’s guaranteed heat rate.

In December 2022, Texas Industrial Energy Consumers and Sierra Club filed motions for rehearing of the PUCT’s final order alleging the PUCT erred in granting the certification of the Orange County Advanced Power Station, in not imposing a cost cap, in including certain findings related to the reasonableness of Entergy Texas’s request for proposals from which the Orange County Advanced Power Station was selected, and in other regards. Also in December 2022, Entergy Texas filed a response to the motions for rehearing refuting the points raised therein. In January 2023 the PUCT issued letters noting that it voted to consider Texas Industrial Energy Consumers’ motion for rehearing at its upcoming January 2023 open meeting and voted not to consider Sierra Club’s motion for rehearing at an open meeting. At the January 2023 open meeting, the PUCT voted to grant Texas Industrial Energy Consumers’ motion for rehearing for the limited purpose of issuing an order on rehearing that excludes three findings related to Entergy Texas’s request for proposals. The order on rehearing does not change the PUCT’s certification of the Orange County Advanced Power Station or the conditions placed thereon in the PUCT’s November 2022 final order. Construction is in progress, and subject to receipt of required permits, the facility is expected to be in service by mid-2026.

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Sources of Capital

Entergy Texas’s sources to meet its capital requirements include:

•internally generated funds;

•cash on hand;

•the Entergy system money pool;

•debt or preferred stock issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;

•capital contributions; and

•bank financing under new or existing facilities.

Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations, Entergy Texas expects to continue, when economically feasible, to retire higher-cost debt and replace it with lower-cost debt if market conditions permit.

All debt and common and preferred stock issuances by Entergy Texas require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in its bond indenture and other agreements. Entergy Texas has sufficient capacity under these tests to meet its foreseeable capital needs for the next twelve months and beyond.

Entergy Texas’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.

2023202220212020

(In Thousands)

$317,882$99,468($79,594)$4,601

See Note 4 to the financial statements for a description of the money pool.

Entergy Texas has a credit facility in the amount of $150 million scheduled to expire in June 2028. The credit facility includes fronting commitments for the issuance of letters of credit against $30 million of the borrowing capacity of the facility. As of December 31, 2023, there were no cash borrowings and $1.1 million in letters of credit outstanding under the credit facility. In addition, Entergy Texas is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2023, $76.5 million in letters of credit were outstanding under Entergy Texas’s uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.

Entergy Texas obtained authorizations from the FERC through April 2025 for short-term borrowings, not to exceed an aggregate amount of $200 million at any time outstanding, and long-term borrowings and security issuances. See Note 4 to the financial statements for further discussion of Entergy Texas’s short-term borrowing limits.

State and Local Rate Regulation and Fuel-Cost Recovery

The rates that Entergy Texas charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Texas is regulated, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the PUCT, is primarily responsible for approval of the rates charged to customers.

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Filings with the PUCT and Texas Cities

Retail Rates

2022 Base Rate Case

In July 2022, Entergy Texas filed a base rate case with the PUCT seeking a net increase in base rates of approximately $131.4 million. The base rate case was based on a 12-month test year ending December 31, 2021. Key drivers of the requested increase were changes in depreciation rates as the result of a depreciation study and an increase in the return on equity. In addition, Entergy Texas included capital additions placed into service for the period of January 1, 2018 through December 31, 2021, including those additions reflected in the then-effective distribution and transmission cost recovery factor riders and the generation cost recovery rider, all of which have been reset to zero as a result of this proceeding. In July 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In October 2022 intervenors filed direct testimony challenging and supporting various aspects of Entergy Texas’s rate case application. The key issues addressed included the appropriate return on equity, generation plant deactivations, depreciation rates, and proposed tariffs related to electric vehicles. In November 2022 the PUCT staff filed direct testimony addressing a similar set of issues and recommending a reduction of $50.7 million to Entergy Texas’s overall cost of service associated with the requested net increase in base rates of approximately $131.4 million. Entergy Texas filed rebuttal testimony in November 2022. In December 2022 the ALJs with the State Office of Administrative Hearings issued two orders, one adopting the parties’ joint proposal that issues related to electric vehicle charging infrastructure be decided exclusively on written evidence and briefing, and one adopting a joint proposed briefing outline and schedule with deadlines in January 2023 for the parties to submit briefing on issues related to electric vehicle charging infrastructure and admitting evidence related to electric vehicle charging infrastructure issues. In January 2023 the parties filed initial and reply briefs addressing issues related to electric vehicle charging infrastructure.

In May 2023, Entergy Texas filed on behalf of the parties an unopposed settlement resolving all issues in the proceeding, except for issues related to electric vehicle charging infrastructure, and Entergy Texas filed an agreed motion for interim rates, subject to refund or surcharge to the extent that the interim rates differ from the final approved rates. The unopposed settlement reflected a net base rate increase to be effective and relate back to December 2022 of $54 million, exclusive of, and incremental to, the costs being realigned from the distribution and transmission cost recovery factor riders and the generation cost recovery rider and $4.8 million of rate case expenses to be recovered through a rider over a period of 36 months. The net base rate increase of $54 million includes updated depreciation rates and a total annual revenue requirement of $14.5 million for the accrual of a self-insured storm reserve and the recovery of the regulatory assets for the pension and postretirement benefits expense deferral, costs associated with the COVID-19 pandemic, and retired non-advanced metering system electric meters. In May 2023 the ALJ with the State Office of Administrative Hearings granted the motion for interim rates, which became effective in June 2023. Additionally, the ALJ remanded the proceeding, except for the issues related to electric vehicle charging infrastructure, to the PUCT to consider the settlement. In June 2023 the ALJ issued a proposal for decision related to the electric vehicle charging infrastructure issues and which noted recent legislation enacted which permits electric utilities to own and operate such infrastructure. The ALJ’s proposal for decision deferred to the PUCT regarding whether it is appropriate for any vertically integrated electric utility, or Entergy Texas specifically, to own electric vehicle charging infrastructure, and in the event that the PUCT decided ownership is permissible, the ALJ recommended approval of the proposed tariff to charge host customers for utility-owned and operated electric vehicle charging infrastructure sited on customer premises and denial of the proposed tariff to temporarily adjust billing demand charges for separately metered electric vehicle charging infrastructure, citing cost-shifting concerns. In July 2023 the parties filed exceptions and replies to exceptions to the proposal for decision. In August 2023 the PUCT issued an order approving the unopposed settlement and also issued an order severing the issues related to electric vehicle charging infrastructure addressed in the ALJ’s proposal for decision to a separate proceeding. Concurrently, Entergy Texas recorded the reversal of $21.9 million of regulatory liabilities to reflect the recognition of certain receipts by Entergy Texas under affiliated PPAs that have been resolved.

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Following the PUCT’s approval of the unopposed settlement in August 2023, Entergy Texas recorded a regulatory liability of $10.3 million, which reflects the net effects of higher depreciation and amortizations for the relate back period, partially offset by the relate back of base rate revenues that would have been collected had the approved rates been in effect for the period from December 2022 through June 2023, the date the new base rates were implemented on an interim basis. In October 2023, Entergy Texas filed a relate back surcharge rider to collect over six months beginning in January 2024 an additional approximately $24.6 million, which is the revenue requirement associated with the relate back of rates from December 2022 through June 2023, including carrying costs, as authorized by the PUCT’s August 2023 order. In November 2023, Entergy Texas filed an amended relate back surcharge rider to collect approximately $24.1 million based on a revised carrying cost rate. The amended relate back surcharge rider was approved by the PUCT in December 2023. The higher depreciation and amortizations for the relate back period will also be recognized over the six months beginning in January 2024, resulting in no effect on net income from the collection of the relate back surcharge rider.

In December 2023 the PUCT referred the separate proceeding to resolve issues related to electric vehicle charging infrastructure to the State Office of Administrative Hearings. In January 2024, the ALJ with the State Office of Administrative Hearings adopted a procedural schedule setting a hearing on the merits for April 2024.

Distribution Cost Recovery Factor (DCRF) Rider

In October 2020, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $26.3 million annually, or $6.8 million in incremental annual revenues beyond Entergy Texas’s then-effective DCRF rider based on its capital invested in distribution between January 1, 2020 and August 31, 2020. In February 2021 the ALJ with the State Office of Administrative Hearings approved Entergy Texas's agreed motion for interim rates, which went into effect in March 2021. In March 2021 the parties filed an unopposed settlement recommending that Entergy Texas be allowed to collect its full requested DCRF revenue requirement and resolving all issues in the proceeding. In May 2021 the PUCT issued an order approving the settlement.

In August 2021, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $40.2 million annually, or $13.9 million in incremental annual revenues beyond Entergy Texas’s then-effective DCRF rider based on its capital invested in distribution between September 1, 2020 and June 30, 2021. In September 2021 the PUCT referred the proceeding to the State Office of Administrative Hearings. A procedural schedule was established with a hearing scheduled in December 2021. In December 2021 the parties filed an unopposed settlement recommending that Entergy Texas be allowed to collect its full requested DCRF revenue requirement and resolving all issues in the proceeding, including a motion for interim rates to take effect for usage on and after January 24, 2022. Also, in December 2021, the ALJ with the State Office of Administrative Hearings issued an order granting the motion for interim rates, which went into effect in January 2022, admitting evidence, and remanding the proceeding to the PUCT to consider the settlement. In March 2022 the PUCT issued an order approving the settlement.

Transmission Cost Recovery Factor (TCRF) Rider

In December 2018, Entergy Texas filed with the PUCT a request to set a new TCRF rider. The new TCRF rider was designed to collect approximately $2.7 million annually from Entergy Texas’s retail customers based on its capital invested in transmission between January 1, 2018 and September 30, 2018. In April 2019 parties filed testimony proposing a load growth adjustment, which would fully offset Entergy Texas’s proposed TCRF revenue requirement. In July 2019 the PUCT granted Entergy Texas’s application as filed to begin recovery of the requested $2.7 million annual revenue requirement, rejecting opposing parties’ proposed adjustment; however, the PUCT found that the question of prudence of the actual investment costs should be determined in Entergy Texas’s next rate case similar to the procedure used for the costs recovered through the DCRF rider. In October 2019 the PUCT issued an order on a motion for rehearing, clarifying and affirming its prior order granting Entergy Texas’s application as filed. Also in October 2019 a second motion for rehearing was filed, and Entergy Texas filed a

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response in opposition to the motion. The second motion for rehearing was overruled by operation of law. In December 2019, Texas Industrial Energy Consumers filed an appeal to the PUCT order in district court alleging that the PUCT erred in declining to apply a load growth adjustment.

In October 2020, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $51 million annually, or $31.6 million in incremental annual revenues beyond Entergy Texas’s then-effective TCRF rider based on its capital invested in transmission between July 1, 2019 and August 31, 2020. In March 2021 the parties filed an unopposed settlement recommending that Entergy Texas be allowed to collect its full requested TCRF revenue requirement with interim rates effective March 2021 and resolving all issues in the proceeding. In March 2021 the ALJ granted the motion for interim rates, admitted evidence, and remanded the case to the PUCT for consideration of a final order at a future open meeting. In June 2021 the PUCT issued an order approving the settlement.

In October 2021, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $66.1 million annually, or $15.1 million in incremental annual revenues beyond Energy Texas’s then-effective TCRF rider based on its capital invested in transmission between September 1, 2020 and July 31, 2021 and changes in approved transmission charges. In January 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In February 2022 the parties filed an unopposed settlement recommending that Entergy Texas be allowed to collect its full requested TCRF revenue requirement with interim rates effective March 2022. In February 2022 the ALJ granted the motion for interim rates, admitted evidence, and remanded the case to the PUCT for consideration of a final order at a future open meeting. In June 2022 the PUCT issued an order approving the settlement.

Generation Cost Recovery Rider

In October 2020, Entergy Texas filed an application to establish a generation cost recovery rider with an initial annual revenue requirement of approximately $91 million to begin recovering a return of and on its generation capital investment in the Montgomery County Power Station through August 31, 2020. In December 2020, Entergy Texas filed an unopposed settlement supporting a generation cost recovery rider with an annual revenue requirement of approximately $86 million. The settlement revenue requirement was based on a depreciation rate intended to fully depreciate Montgomery County Power Station over 38 years and the removal of certain costs from Entergy Texas’s request. Under the settlement, Entergy Texas retained the right to propose a different depreciation rate and seek recovery of a majority of the costs removed from its request in its next base rate proceeding, and such depreciation rate was revised to fully depreciate Montgomery County Power Station over 40 years and all requested capital additions were approved as prudent in the 2022 base rate case proceeding discussed above. On January 14, 2021, the PUCT approved the generation cost recovery rider settlement rates on an interim basis and abated the proceeding. In March 2021, Entergy Texas filed to update its generation cost recovery rider to include its generation capital investment in Montgomery County Power Station after August 31, 2020. In April 2021 the ALJ issued an order unabating the proceeding and in May 2021 the ALJ issued an order finding Entergy Texas’s application and notice of the application to be sufficient. In May 2021, Entergy Texas filed an amendment to the application to reflect the PUCT’s approval of the sale of a 7.56% partial interest in the Montgomery County Power Station to East Texas Electric Cooperative, Inc., which closed in June 2021. In June 2021 the PUCT referred the proceeding to the State Office of Administrative Hearings. In July 2021 the ALJ with the State Office of Administrative Hearings adopted a procedural schedule setting a hearing on the merits for September 2021. In July 2021 the parties filed a motion to abate the procedural schedule noting they had reached an agreement in principle and to allow the parties time to finalize a settlement agreement, which motion was granted by the ALJ. In October 2021, Entergy Texas filed on behalf of the parties an unopposed settlement agreement that would adjust its generation cost recovery rider to recover an annual revenue requirement of approximately $88.3 million related to Entergy Texas’s investment in the Montgomery County Power Station through January 1, 2021, with Entergy Texas able to seek recovery of the remainder of its investment in its next base rate case, and all requested capital additions were approved as prudent in the 2022 base rate case proceeding discussed above. Also in October 2021 the ALJ granted a motion to admit evidence and remand the proceeding to the PUCT. In January 2022 the PUCT issued an

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Entergy Texas, Inc. and Subsidiaries

Management’s Financial Discussion and Analysis

order approving the unopposed settlement. In February 2022, Entergy Texas filed a relate-back rider to collect over five months an additional approximately $5 million, which is the difference between the interim revenue requirement approved in January 2021 and the revenue requirement approved in January 2022 that reflects Entergy Texas’s full generation capital investment and ownership in Montgomery County Power Station on January 1, 2021, plus carrying costs from January 2021 through January 2022 when the updated revenue requirement took effect. In April 2022, Entergy Texas and the PUCT staff filed a joint proposed order supporting approval of Entergy Texas’s as-filed request. The PUCT approved the relate-back rider consistent with Entergy Texas’s as-filed request, and rates became effective over a five-month period, in August 2022.

In December 2020, Entergy Texas also filed an application to amend its generation cost recovery rider to reflect its acquisition of the Hardin County Peaking Facility, which closed in June 2021. Because Hardin was to be acquired in the future, the initial generation cost recovery rider rates proposed in the application represented no change from the generation cost recovery rider rates established in Entergy Texas’s previous generation cost recovery rider proceeding. In July 2021 the PUCT issued an order approving the application. In August 2021, Entergy Texas filed an update application to recover its actual investment in the acquisition of the Hardin County Peaking Facility. In September 2021 the PUCT referred the proceeding to the State Office of Administrative Hearings. A procedural schedule was established with a hearing scheduled in April 2022. In January 2022, Entergy Texas filed an update to its application to align the requested revenue requirement with the terms of the generation cost recovery rider settlement approved by the PUCT in January 2022. In March 2022, Entergy Texas filed on behalf of the parties an unopposed motion, which motion was granted by the ALJ with the State Office of Administrative Hearings, to abate the procedural schedule indicating that the parties had reached an agreement in principle. In April 2022, Entergy Texas filed on behalf of the parties a unanimous settlement agreement that would adjust its generation cost recovery rider to recover an annual revenue requirement of approximately $92.8 million, which is $4.5 million in incremental annual revenue above the $88.3 million approved in January 2022, related to Entergy Texas’s actual investment in the acquisition of the Hardin County Peaking Facility. Concurrently with filing of the unanimous settlement agreement, Entergy Texas submitted an agreed motion to admit evidence and remand the case to the PUCT for review and consideration of the settlement agreement, which motion was granted by the ALJ with the State Office of Administrative Hearings. The PUCT approved the settlement agreement and rates became effective in August 2022. In September 2022, Entergy Texas filed a relate-back rider designed to collect over three months an additional approximately $5.7 million, which is the revenue requirement, plus carrying costs, associated with Entergy Texas’s acquisition of Hardin County Peaking Facility from June 2021 through August 2022 when the updated revenue requirement took effect. In April 2023 the PUCT approved Entergy Texas’s as-filed request with rates effective over three months beginning in May 2023. See Note 14 to the financial statements for discussion of the Hardin County Peaking Facility purchase.

Fuel and purchased power cost recovery

Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, not recovered in base rates. Historically, semi-annual revisions of the fixed fuel factor have been made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. In 2023 the Texas legislature modified the Texas Utilities Code to provide that material over- and under-recovered fuel balances are to be refunded or surcharged through interim fuel adjustments and that fuel reconciliations must be filed at least once every two years. Entergy Texas expects the PUCT to undertake a rulemaking to effectuate the new legislation by the end of 2024.

In May 2022, Entergy Texas filed an application with the PUCT to implement an interim fuel surcharge to collect the cumulative under-recovery of approximately $51.7 million, including interest, of fuel and purchased power costs incurred from May 1, 2020 through December 31, 2021. The under-recovery balance is primarily attributable to the impacts of Winter Storm Uri, including historically high natural gas prices, partially offset by settlements received by Entergy Texas from MISO related to Hurricane Laura. Entergy Texas proposed that the interim fuel surcharge be assessed over a period of six months beginning with the first billing cycle after the PUCT

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Entergy Texas, Inc. and Subsidiaries

Management’s Financial Discussion and Analysis

issues a final order, but no later than the first billing cycle of September 2022. Also in May 2022, the PUCT referred the proceeding to the State Office of Administrative Hearings. In July 2022, Entergy Texas filed on behalf of the parties an unopposed settlement resolving all issues in the proceeding. In addition, Entergy Texas filed on behalf of the parties a motion to admit evidence, to approve interim rates as requested in the initial application, and to remand the proceeding to the PUCT to consider the unopposed settlement. In August 2022 the ALJ with the State Office of Administrative Hearings issued an order granting Entergy Texas’s motion, approving interim rates effective with the first billing cycle of September 2022, and remanding the case to the PUCT for final approval. The interim fuel surcharge was approved by the PUCT in January 2023.

In September 2022, Entergy Texas filed an application with the PUCT to reconcile its fuel and purchased power costs for the period from April 2019 through March 2022. During the reconciliation period, Entergy Texas incurred approximately $1.7 billion in eligible fuel and purchased power expenses, net of certain revenues credited to such expenses and other adjustments. As of the end of the reconciliation period, Entergy Texas’s cumulative under-recovery balance was approximately $103.1 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning April 2022, pending future surcharges or refunds as approved by the PUCT. In November 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In May 2023, Entergy Texas filed, and the ALJ with the State Office of Administrative Hearings granted, a joint motion to abate the proceeding to give parties additional time to finalize a settlement. In July 2023, Entergy Texas filed an unopposed settlement, supporting testimony, and an agreed motion to admit evidence and remand the proceeding to the PUCT. Pursuant to the unopposed settlement, Entergy Texas would receive no disallowance of fuel costs incurred over the three-year reconciliation period and retain $9.3 million in margins from off-system sales made during the reconciliation period, resulting in a cumulative under-recovery balance of approximately $99.7 million, including interest, as of the end of the reconciliation period. In July 2023 the ALJ with the State Office of Administrative Hearings granted the motion to admit evidence and remanded the proceeding to the PUCT for consideration of the unopposed settlement. The PUCT approved the settlement in September 2023.

Federal Regulation

See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.

Nuclear Matters

See the “Nuclear Matters” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of nuclear matters.

Industrial and Commercial Customers

Entergy Texas’s large industrial and commercial customers continually explore ways to reduce their energy costs. In particular, cogeneration is an option available to a portion of Entergy Texas’s industrial customer base. Entergy Texas responds by working with industrial and commercial customers and negotiating electric service contracts to provide, under existing rate schedules, competitive rates that match specific customer needs and load profiles. Entergy Texas actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand, from both new and existing customers.

Environmental Risks

Entergy Texas’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Texas is in substantial compliance with

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Entergy Texas, Inc. and Subsidiaries

Management’s Financial Discussion and Analysis

environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Critical Accounting Estimates

The preparation of Entergy Texas’s financial statements in conformity with GAAP requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in these assumptions and measurements could produce estimates that would have a material effect on the presentation of Entergy Texas’s financial position, results of operations, or cash flows.

Utility Regulatory Accounting

See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.

Taxation and Uncertain Tax Positions

See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.

Qualified Pension and Other Postretirement Benefits

Entergy Texas’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are affected by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.

Cost Sensitivity

The following chart reflects the sensitivity of qualified pension and qualified projected benefit obligation cost to changes in certain actuarial assumptions (dollars in thousands).

Actuarial AssumptionChange in AssumptionImpact on 2024 Qualified Pension CostImpact on 2023 Qualified Projected Benefit Obligation

Increase/(Decrease)

Discount rate(0.25%)$182$5,266

Rate of return on plan assets(0.25%)$577$—

Rate of increase in compensation0.25%$196$953

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Entergy Texas, Inc. and Subsidiaries

Management’s Financial Discussion and Analysis

The following chart reflects the sensitivity of postretirement benefits cost and accumulated postretirement benefit obligation changes in certain actuarial assumptions (dollars in thousands).

Actuarial AssumptionChange in AssumptionImpact on 2024 Postretirement Benefits CostImpact on 2023 Accumulated Postretirement Benefit Obligation

Increase/(Decrease)

Discount rate(0.25%)$7$1,188

Health care cost trend0.25%$59$755

Each fluctuation above assumes that the other components of the calculation are held constant.

Costs and Employer Contributions

Total qualified pension cost for Entergy Texas in 2023 was $15.7 million, including $11.2 million in settlement costs. Entergy Texas anticipates 2024 qualified pension cost to be $436 thousand. Entergy Texas contributed $5.3 million to its qualified pension plans in 2023 and estimates 2024 pension contributions will be approximately $8.3 million, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024 valuations are completed, which is expected by April 1, 2024.

Total postretirement health care and life insurance benefit income for Entergy Texas in 2023 was $8.8 million. Entergy Texas expects 2024 postretirement health care and life insurance benefit income to approximate $10.9 million. Entergy Texas contributed $235 thousand to its other postretirement plans in 2023 and estimates 2024 contributions will be approximately $156 thousand.

Other Contingencies

See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.

New Accounting Pronouncements

See the “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.

431

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and Board of Directors of

Entergy Texas, Inc. and Subsidiaries

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Entergy Texas, Inc. and Subsidiaries (the “Company”) as of December 31, 2023 and 2022, the related consolidated statements of income, cash flows, and changes in equity (pages 434 through 438 and applicable items in pages 47 through 238), for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Rate and Regulatory Matters — Entergy Texas, Inc. and Subsidiaries — Refer to Note 2 to the financial statements

Critical Audit Matter Description

The Company is subject to rate regulation by the Public Utility Commission of Texas (the “PUCT”), which has jurisdiction with respect to the rates of electric companies in Texas, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.

432

The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the PUCT and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the PUCT and the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.

We identified the impact of rate regulation as a critical audit matter due to the judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs and refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the PUCT and the FERC, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities involved specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and auditor judgment to evaluate management estimates and the subjectivity of audit evidence.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertainty of future decisions by the PUCT and the FERC, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities included the following, among others:

•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

•We read relevant regulatory orders issued by the PUCT and the FERC for the Company to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the PUCT’s and the FERC’s treatment of similar costs under similar circumstances. We evaluated external information and compared to management’s recorded regulatory asset and liability balances for completeness.

•For regulatory matters in process, we inspected the Company’s filings with the PUCT and the FERC and orders issued, and considered the filings with the PUCT and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.

•We obtained an analysis from management and support from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.

•We obtained representation from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management’s assertion that amounts are probable of recovery, refund, or a future reduction in rates.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 23, 2024

We have served as the Company’s auditor since 2001.

433

ENTERGY TEXAS, INC. AND SUBSIDIARIES

CONSOLIDATED INCOME STATEMENTS

For the Years Ended December 31,

202320222021

(In Thousands)

OPERATING REVENUES

Electric$2,028,586 $2,288,905 $1,902,511

OPERATING EXPENSES

Operation and Maintenance:

Fuel, fuel-related expenses, and gas purchased for resale403,111 443,765 335,742

Purchased power468,511 717,501 588,941

Other operation and maintenance323,797 312,340 281,713

Taxes other than income taxes117,852 101,673 94,989

Depreciation and amortization278,311 230,692 214,838

Other regulatory charges (credits) - net7,324 49,175 59,581

TOTAL1,598,906 1,855,146 1,575,804

OPERATING INCOME429,680 433,759 326,707

OTHER INCOME

Allowance for equity funds used during construction28,193 13,527 9,892

Interest and investment income11,116 4,141 837

Miscellaneous - net(10,411)(6,572)721

TOTAL28,898 11,096 11,450

INTEREST EXPENSE

Interest expense114,978 95,454 87,787

Allowance for borrowed funds used during construction(10,545)(4,547)(3,980)

TOTAL104,433 90,907 83,807

INCOME BEFORE INCOME TAXES354,145 353,948 254,350

Income taxes62,872 50,621 25,526

NET INCOME291,273 303,327 228,824

Preferred dividend requirements2,072 2,072 1,909

EARNINGS APPLICABLE TO COMMON STOCK$289,201 $301,255 $226,915

See Notes to Financial Statements.

434

ENTERGY TEXAS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31,

202320222021

(In Thousands)

OPERATING ACTIVITIES

Net income$291,273 $303,327 $228,824

Adjustments to reconcile net income to net cash flow provided by operating activities:

Depreciation and amortization278,311 230,692 214,838

Deferred income taxes, investment tax credits, and non-current taxes accrued53,507 41,648 48,813

Changes in assets and liabilities:

Receivables24,249 (35,131)(16,455)

Fuel inventory(24,097)15,962 10,819

Accounts payable(22,046)48,199 (5,718)

Taxes accrued(14,146)44,015 (3,420)

Interest accrued7,357 4,926 (1,854)

Deferred fuel costs119,096 (209,835)(133,636)

Other working capital accounts(36,097)(19,574)(12,105)

Provisions for estimated losses1,887 (649)(140)

Other regulatory assets(17,924)(157,349)103,380

Other regulatory liabilities(20,122)(30,499)(28,747)

Effect of securitization on regulatory asset— 153,383 —

Pension and other postretirement liabilities(36,131)20,656 (42,502)

Other assets and liabilities36,574 (344)(5,164)

Net cash flow provided by operating activities641,691 409,427 356,933

INVESTING ACTIVITIES

Construction expenditures(946,543)(696,879)(702,754)

Allowance for equity funds used during construction28,193 13,527 9,892

Proceeds from sale of assets11,000 — 67,920

Payment for purchase of assets— — (36,534)

Litigation proceeds from settlement agreement— 4,134 —

Changes in money pool receivable - net(218,414)(99,468)4,601

Changes in securitization account5,684 15,750 9,604

Increase in other investments(5,868)(1,133)—

Net cash flow used in investing activities(1,125,948)(764,069)(647,271)

FINANCING ACTIVITIES

Proceeds from the issuance of long-term debt344,895 606,168 127,931

Retirement of long-term debt(17,835)(66,514)(269,435)

Capital contributions from parent150,000 — 95,000

Proceeds from the issuance of preferred stock— — 3,713

Changes in money pool payable - net— (79,594)79,594

Dividends paid:

Common stock— (105,000)—

Preferred stock(2,072)(2,060)(1,881)

Other27,758 5,111 6,848

Net cash flow provided by financing activities502,746 358,111 41,770

Net increase (decrease) in cash and cash equivalents18,489 3,469 (248,568)

Cash and cash equivalents at beginning of period3,497 28 248,596

Cash and cash equivalents at end of period$21,986 $3,497 $28

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:

Cash paid during the period for:

Interest - net of amount capitalized$104,766 $87,682 $87,094

Income taxes$28,969 $1,864 $17,594

Noncash investing activities:

Accrued construction expenditures$257,467 $68,893 $73,105

See Notes to Financial Statements.

435

ENTERGY TEXAS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31,

20232022

(In Thousands)

CURRENT ASSETS

Cash and cash equivalents:

Cash$1,497 $500

Temporary cash investments20,489 2,997

Total cash and cash equivalents21,986 3,497

Securitization recovery trust account5,195 10,879

Accounts receivable:

Customer88,468 115,955

Allowance for doubtful accounts(1,484)(2,352)

Associated companies329,941 115,549

Other24,416 21,587

Accrued unbilled revenues72,771 69,208

Total accounts receivable514,112 319,947

Deferred fuel costs139,019 258,115

Fuel inventory - at average cost50,847 26,750

Materials and supplies - at average cost123,020 93,031

Prepayments and other35,232 20,568

TOTAL889,411 732,787

OTHER PROPERTY AND INVESTMENTS

Investments in affiliates - at equity214 250

Non-utility property - at cost (less accumulated depreciation)376 376

Other15,068 18,975

TOTAL15,658 19,601

UTILITY PLANT

Electric7,931,340 7,409,461

Construction work in progress857,707 339,139

TOTAL UTILITY PLANT8,789,047 7,748,600

Less - accumulated depreciation and amortization2,363,919 2,135,400

UTILITY PLANT - NET6,425,128 5,613,200

DEFERRED DEBITS AND OTHER ASSETS

Regulatory assets:

Other regulatory assets (includes securitization property of $250,324 as of December 31, 2023 and $269,523 as of December 31, 2022)

596,606 578,682

Other129,769 99,694

TOTAL726,375 678,376

TOTAL ASSETS$8,056,572 $7,043,964

See Notes to Financial Statements.

436

ENTERGY TEXAS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

December 31,

20232022

(In Thousands)

CURRENT LIABILITIES

Accounts payable:

Associated companies$74,423 $70,321

Other195,703 201,982

Customer deposits39,999 38,764

Taxes accrued78,887 93,033

Interest accrued31,285 23,928

Other16,237 16,963

TOTAL436,534 444,991

NON-CURRENT LIABILITIES

Accumulated deferred income taxes and taxes accrued814,905 744,227

Accumulated deferred investment tax credits7,963 8,711

Regulatory liability for income taxes - net114,759 132,647

Other regulatory liabilities43,013 45,247

Asset retirement cost liabilities11,743 11,121

Accumulated provisions9,480 7,593

Long-term debt (includes securitization bonds of $257,592 as of December 31, 2023 and $275,064 as of December 31, 2022)

3,225,092 2,895,913

Other274,421 74,053

TOTAL4,501,376 3,919,512

Commitments and Contingencies

EQUITY

Common stock, no par value, authorized 200,000,000 shares; issued and outstanding 46,525,000 shares in 2023 and 2022

49,452 49,452

Paid-in capital1,200,125 1,050,125

Retained earnings1,830,335 1,541,134

Total common shareholder's equity3,079,912 2,640,711

Preferred stock without sinking fund38,750 38,750

TOTAL3,118,662 2,679,461

TOTAL LIABILITIES AND EQUITY$8,056,572 $7,043,964

See Notes to Financial Statements.

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ENTERGY TEXAS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Years Ended December 31, 2023, 2022, and 2021

Common Equity

Preferred StockCommon StockPaid-in CapitalRetained EarningsTotal

(In Thousands)

Balance at December 31, 2020$35,000 $49,452 $955,162 $1,117,964 $2,157,578

Net income— — — 228,824 228,824

Capital contributions from parent— — 95,000 — 95,000

Preferred stock issuance3,750 — (37)— 3,713

Preferred stock dividends— — — (1,909)(1,909)

Balance at December 31, 2021$38,750 $49,452 $1,050,125 $1,344,879 $2,483,206

Net income— — — 303,327 303,327

Common stock dividends— — — (105,000)(105,000)

Preferred stock dividends— — — (2,072)(2,072)

Balance at December 31, 2022$38,750 $49,452 $1,050,125 $1,541,134 $2,679,461

Net income— — — 291,273 291,273

Capital contributions from parent— — 150,000 — 150,000

Preferred stock dividends— — — (2,072)(2,072)

Balance at December 31, 2023$38,750 $49,452 $1,200,125 $1,830,335 $3,118,662

See Notes to Financial Statements.

438

SYSTEM ENERGY RESOURCES, INC.

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

System Energy’s principal asset consists of an ownership interest and a leasehold interest in Grand Gulf. The capacity and energy from its 90% interest is sold under the Unit Power Sales Agreement to its only four customers, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% interest in Grand Gulf pursuant to the Unit Power Sales Agreement. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenues. As discussed in “Complaints Against System Energy” below, System Energy and the Unit Power Sales Agreement are currently the subject of several litigation proceedings at the FERC (or on appeal from the FERC to the United States Court of Appeals for the Fifth Circuit).

Results of Operations

2023 Compared to 2022

Net Income

System Energy had net income of $108.8 million in 2023 compared to a net loss of $276.6 million in 2022 primarily due to a regulatory charge of $551 million ($413 million net-of-tax) recorded in second quarter 2022 to reflect the effects of the partial settlement agreement and offer of settlement related to pending proceedings before the FERC. The increase was partially offset by the disallowance of the recovery of sale-leaseback lease renewal costs from Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans per the December 2022 FERC order related to the Grand Gulf sale-leaseback renewal complaint and the lower authorized rate of return on equity and capital structure limitations on monthly bills issued to Entergy Mississippi per the June 2022 settlement agreement with the MPSC. See Note 2 to the financial statements for discussion of the partial settlement agreement with the MPSC and discussion of the Grand Gulf sale-leaseback renewal complaint.

Income Taxes

The effective income tax rates were 22.7% for 2023 and 25.1% for 2022. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates and for additional discussion regarding income taxes.

2022 Compared to 2021

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of System Energy’s Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 24, 2023, for discussion of results of operations for 2022 compared to 2021.

Income Tax Legislation and Regulation

See the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of income tax legislation and regulation.

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System Energy Resources, Inc.

Management’s Financial Discussion and Analysis

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2023, 2022, and 2021 were as follows:

202320222021

(In Thousands)

Cash and cash equivalents at beginning of period$2,940 $89,201 $242,469

Net cash provided by (used in):

Operating activities273,572 7,280 201,211

Investing activities(75,806)(264,184)(193,392)

Financing activities(200,646)170,643 (161,087)

Net decrease in cash and cash equivalents(2,880)(86,261)(153,268)

Cash and cash equivalents at end of period$60 $2,940 $89,201

2023 Compared to 2022

Operating Activities

Net cash flow provided by operating activities increased $266.3 million in 2023 primarily due to:

•the refund of $235 million to Entergy Mississippi in 2022 as a result of the settlement with the MPSC. See Note 2 to the financial statements for discussion of the settlement agreement with the MPSC;

•$40.5 million in recoupment payments received from Entergy Louisiana and Entergy New Orleans in October 2023 related to the sale-leaseback renewal costs and depreciation litigation as calculated in System Energy’s October 2023 compliance filing with the FERC. See Note 2 to the financial statements for further discussion of the Grand Gulf sale-leaseback renewal complaint;

•income tax refunds of $19.8 million in 2023 as compared to income tax payments of $18.4 million in 2022. System Energy received income tax refunds in 2023 and made income tax payments in 2022, each in accordance with an intercompany income tax allocation agreement;

•a decrease in spending of $36.4 million on nuclear refueling outage costs in 2023 as compared to 2022; and

•a decrease of $13.1 million in pension contributions in 2023. See “Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

The increase was partially offset by:

•aggregate refunds of $103.5 million made in January 2023 related to the sale-leaseback renewal costs and depreciation litigation as calculated in System Energy’s January 2023 compliance report filed with the FERC. See Note 2 to the financial statements for further discussion of the refunds and the related proceedings;

•refunds of $41.8 million included in September 2023 service month bills under the Unit Power Sales Agreement to reflect the revenue requirement effects of Grand Gulf’s updated depreciation rates as approved by the FERC in August 2023. See Note 2 to the financial statements for discussion of the Unit Power Sales Agreement depreciation amendment proceeding; and

•refunds of $19.3 million included in May 2023 service month bills under the Unit Power Sales Agreement to reflect the effects of the partial settlement agreement approved by the FERC in April 2023. See Note 2 to the financial statements for discussion of the Unit Power Sales Agreement complaint.

440

System Energy Resources, Inc.

Management’s Financial Discussion and Analysis

Investing Activities

Net cash flow used in investing activities decreased by $188.4 million in 2023 primarily due to:

•money pool activity;

•a decrease of $43.4 million as a result of fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle; and

•a decrease of $41.8 million in nuclear construction expenditures primarily due to higher spending in 2022 on Grand Gulf outage projects and upgrades.

Decreases in System Energy’s receivable from the money pool are a source of cash flow, and System Energy’s receivable from the money pool decreased $95 million in 2023 compared to increasing by $19.2 million in 2022. The money pool is an intercompany cash management program that makes possible intercompany borrowing and lending arrangements, and the money pool and other borrowing arrangements are designed to reduce the Registrant Subsidiaries’ dependence on external short-term borrowings.

Financing Activities

System Energy’s financing activities used $200.6 million of cash in 2023 compared to providing $170.6 million of cash in 2022 primarily due to the following activity:

•the repayment, at maturity, of $250 million of 4.10% Series mortgage bonds in April 2023;

•$170 million in common stock dividends and distributions paid in 2023. No common stock dividends or distributions were made in 2022 in order to maintain System Energy’s capital structure and in anticipation of the settlement with the MPSC. See Note 2 to the financial statements for discussion of the settlement with the MPSC;

•a $135 million capital contribution from Entergy Corporation in 2022 primarily to fund the settlement payment to Entergy Mississippi;

•the issuance of a $50 million term loan in May 2022, which was repaid, prior to maturity, in March 2023;

•net repayments of $51.1 million in 2023 as compared to net long-term borrowings of $36.5 million in 2022 on the nuclear fuel company variable interest entity’s credit facilities;

•the repayment, at maturity, of $50.3 million of 2.5% Series governmental bonds in April 2022; and

•the issuance of $325 million of 6.00% Series mortgage bonds in March 2023.

See Note 5 to the financial statements for additional details of long-term debt.

2022 Compared to 2021

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of System Energy’s Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 24, 2023, for discussion of operating, investing, and financing cash flow activities for 2022 compared to 2021.

441

System Energy Resources, Inc.

Management’s Financial Discussion and Analysis

Capital Structure

System Energy’s debt to capital ratio is shown in the following table.

December 31,2023December 31,2022

Debt to capital45.4 %45.0 %

Effect of subtracting cash— %(0.1 %)

Net debt to net capital (non-GAAP)45.4 %44.9 %

Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings and long-term debt, including the currently maturing portion. Capital consists of debt and common equity. Net capital consists of capital less cash and cash equivalents. System Energy uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating System Energy’s financial condition. The net debt to net capital ratio is a non-GAAP measure. System Energy uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating System Energy’s financial condition because net debt indicates System Energy’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

System Energy seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend or a capital distribution, to the extent funds are legally available to do so, or a combination of the three, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments and other uses of cash such as the payment of expenses in the ordinary course, System Energy may issue incremental debt or reduce dividends, or both, to maintain its capital structure. In addition, System Energy may receive equity contributions to maintain its capital structure for certain circumstances that would materially alter the capital structure if financed entirely with debt and reduced dividends.

Uses of Capital

System Energy requires capital resources for:

•construction and other capital investments;

•debt maturities or retirements;

•working capital purposes, including the financing of fuel costs and tax payments; and

•dividend, distribution, and interest payments.

Following are the amounts of System Energy’s planned construction and other capital investments.

202420252026

(In Millions)

Planned construction and capital investment:

Generation$165 $125 $150

Utility Support10 5 5

Total$175 $130 $155

In addition to routine spending to maintain operations, the planned capital investment estimate includes amounts associated with Grand Gulf investments and initiatives.

442

System Energy Resources, Inc.

Management’s Financial Discussion and Analysis

Following are the amounts of System Energy’s existing debt obligations (includes estimated interest payments).

2024202520262027-2028 After 2028

(In Millions)

Long-term debt (a)$46 $266 $41 $479 $252

(a)Long-term debt is discussed in Note 5 to the financial statements.

Other Obligations

System Energy expects to contribute approximately $16.7 million to its qualified pension plans and approximately $34 thousand to other postretirement health care and life insurance plans in 2024, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024, valuations are completed, which is expected by April 1, 2024. See “Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

System Energy has no unrecognized tax benefits and interest net of unused tax attributes and payments for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

In addition, System Energy enters into nuclear fuel purchase agreements that contain minimum purchase obligations. As discussed in Note 8 to the financial statements, System Energy recovers these costs through charges under the Unit Power Sales Agreement.

As a wholly-owned subsidiary, System Energy dividends its earnings to Entergy Corporation at a percentage determined monthly.

Sources of Capital

System Energy’s sources to meet its capital requirements include:

•internally generated funds;

•cash on hand;

•the Entergy system money pool;

•debt issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;

•equity contributions; and

•bank financing under new or existing facilities.

Circumstances such fuel and purchased power price fluctuations and unanticipated expenses, including unscheduled plant outages, could affect the timing and level of internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations, System Energy expects to continue, when economically feasible, to retire higher-cost debt and replace it with lower-cost debt if market conditions permit.

All debt issuances by System Energy require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in its bond indenture and other agreements. System Energy has sufficient capacity under these tests to meet its foreseeable capital needs for the next twelve months and beyond.

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System Energy Resources, Inc.

Management’s Financial Discussion and Analysis

System Energy’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.

2023202220212020

(In Thousands)

($12,246)$94,981$75,745$4,004

See Note 4 to the financial statements for a description of the money pool.

The System Energy nuclear fuel company variable interest entity has a credit facility in the amount of $120 million scheduled to expire in June 2025. As of December 31, 2023, $21.5 million in loans were outstanding under the System Energy nuclear fuel company variable interest entity credit facility. See Note 4 to the financial statements for additional discussion of the variable interest entity credit facility.

System Energy obtained authorizations from the FERC through March 2025 for the following:

•short-term borrowings not to exceed an aggregate amount of $200 million at any time outstanding;

•long-term borrowings and security issuances not to exceed an aggregate amount of $1.3 billion at any time outstanding; and

•borrowings by its nuclear fuel company variable interest entity.

See Note 4 to the financial statements for further discussion of System Energy’s short-term borrowing limits.

Federal Regulation

See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.

Complaints Against System Energy

System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf. System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. System Energy and the Unit Power Sales Agreement are currently the subject of several litigation proceedings at the FERC (or on appeal from the FERC to the United States Court of Appeals for the Fifth Circuit), including challenges with respect to System Energy’s authorized return on equity and capital structure, renewal of its sale-leaseback arrangement, treatment of uncertain tax positions, a broader investigation of rates under the Unit Power Sales Agreement, and two prudence complaints, one challenging the extended power uprate completed at Grand Gulf in 2012 and the operation and management of Grand Gulf, particularly in the 2016-2020 time period, and the second challenging the operation and management of Grand Gulf in the 2021-2022 time period. The settlement with the MPSC described in “System Energy Settlement with the MPSC” below, and the settlement in principle with the APSC described in “System Energy Settlement with the APSC” below, if approved by the FERC, substantially reduce the aggregate amount of exposure resulting from these claims. The claims in these proceedings include claims for refunds and claims for rate adjustments; the aggregate amount of refunds claimed in these proceedings, after reduction for settlements reached with the MPSC and the APSC (subject in the latter case to approval by the FERC), exceeds the current net book value of System Energy. In the event of an adverse decision in one or more of these proceedings requiring the payment of additional refunds, System Energy may be required to seek financing to pay such refunds, the cost and availability of which are unknown. Following are discussions of these proceedings.

444

System Energy Resources, Inc.

Management’s Financial Discussion and Analysis

Return on Equity and Capital Structure Complaints

In January 2017 the APSC and MPSC filed a complaint with the FERC against System Energy. The complaint seeks a reduction in the return on equity component of the Unit Power Sales Agreement pursuant to which System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. Entergy Arkansas also sells some of its Grand Gulf capacity and energy to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under separate agreements. The current return on equity under the Unit Power Sales Agreement is 10.94%, which was established in a rate proceeding that became final in July 2001. As discussed below in “System Energy Settlement with the MPSC,” beginning with the July 2022 service month, bills issued to Entergy Mississippi under the Unit Power Sales Agreement reflect a return on equity of 9.65%.

The APSC and MPSC complaint alleges that the return on equity is unjust and unreasonable because capital market and other considerations indicate that it is excessive. The complaint requests proceedings to investigate the return on equity and establish a lower return on equity, and also requests that the FERC establish January 23, 2017 as a refund effective date. The complaint includes return on equity analysis that purports to establish that the range of reasonable return on equity for System Energy is between 8.37% and 8.67%. System Energy answered the complaint in February 2017 and disputes that a return on equity of 8.37% to 8.67% is just and reasonable. The LPSC and the City Council intervened in the proceeding expressing support for the complaint. In September 2017 the FERC established a refund effective date of January 23, 2017 and directed the parties to engage in settlement proceedings before an ALJ. The parties were unable to settle the return on equity issue and a FERC hearing judge was assigned in July 2018. The 15-month refund period in connection with the APSC/MPSC complaint expired on April 23, 2018.

In April 2018 the LPSC filed a complaint with the FERC against System Energy seeking an additional 15-month refund period. The LPSC complaint requests similar relief from the FERC with respect to System Energy’s return on equity and also requests the FERC to investigate System Energy’s capital structure. The APSC, MPSC, and City Council intervened in the proceeding, filed an answer expressing support for the complaint, and asked the FERC to consolidate this proceeding with the proceeding initiated by the complaint of the APSC and MPSC in January 2017. System Energy answered the LPSC complaint in May 2018 and also filed a motion to dismiss the complaint. In August 2018 the FERC issued an order dismissing the LPSC’s request to investigate System Energy’s capital structure and setting for hearing the return on equity complaint, with a refund effective date of April 27, 2018. The 15-month refund period in connection with the LPSC return on equity complaint expired on July 26, 2019.

The portion of the LPSC’s complaint dealing with return on equity was subsequently consolidated with the APSC and MPSC complaint for hearing. The parties addressed an order (issued in a separate FERC proceeding involving New England transmission owners) that proposed modifying the FERC’s standard methodology for determining return on equity. In September 2018, System Energy filed a request for rehearing and the LPSC filed a request for rehearing or reconsideration of the FERC’s August 2018 order. The LPSC’s request referenced an amended complaint that it filed on the same day raising the same capital structure claim the FERC had earlier dismissed. The FERC initiated a new proceeding for the amended capital structure complaint, and System Energy submitted a response in October 2018. In January 2019 the FERC set the amended complaint for settlement and hearing proceedings. Settlement proceedings in the capital structure proceeding commenced in February 2019. As noted below, in June 2019 settlement discussions were terminated and the amended capital structure complaint was consolidated with the ongoing return on equity proceeding. The 15-month refund period in connection with the capital structure complaint was from September 24, 2018 to December 23, 2019.

In January 2019 the LPSC, the APSC, and the MPSC filed direct testimony in the return on equity proceeding. For the refund period January 23, 2017 through April 23, 2018, the LPSC argues for an authorized return on equity for System Energy of 7.81% and the APSC and the MPSC argue for an authorized return on equity for System Energy of 8.24%. For the refund period April 27, 2018 through July 27, 2019, and for application on a

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System Energy Resources, Inc.

Management’s Financial Discussion and Analysis

prospective basis, the LPSC argues for an authorized return on equity for System Energy of 7.97% and the APSC and the MPSC argue for an authorized return on equity for System Energy of 8.41%. In March 2019, System Energy submitted answering testimony. For the first refund period, System Energy’s testimony argues for a return on equity of 10.10% (median) or 10.70% (midpoint). For the second refund period, System Energy’s testimony shows that the calculated returns on equity for the first period fall within the range of presumptively just and reasonable returns on equity, and thus the second complaint should be dismissed (and the first period return on equity used going forward). If the FERC nonetheless were to set a new return on equity for the second period (and going forward), System Energy argues the return on equity should be either 10.32% (median) or 10.69% (midpoint).

In May 2019 the FERC trial staff filed its direct and answering testimony in the return on equity proceeding. For the first refund period, the FERC trial staff calculates an authorized return on equity for System Energy of 9.89% based on the application of FERC’s proposed methodology. The FERC trial staff’s direct and answering testimony noted that an authorized return on equity of 9.89% for the first refund period was within the range of presumptively just and reasonable returns on equity for the second refund period, as calculated using a study period ending January 31, 2019 for the second refund period.

In June 2019, System Energy filed testimony responding to the testimony filed by the FERC trial staff. Among other things, System Energy’s testimony rebutted arguments raised by the FERC trial staff and provided updated calculations for the second refund period based on the study period ending May 31, 2019. For that refund period, System Energy’s testimony shows that strict application of the return on equity methodology proposed by the FERC staff indicates that the second complaint would not be dismissed, and the new return on equity would be set at 9.65% (median) or 9.74% (midpoint). System Energy’s testimony argues that these results are insufficient in light of benchmarks such as state returns on equity and treasury bond yields, and instead proposes that the calculated returns on equity for the second period should be either 9.91% (median) or 10.3% (midpoint). System Energy’s testimony also argues that, under application of its proposed modified methodology, the 10.10% return on equity calculated for the first refund period would fall within the range of presumptively just and reasonable returns on equity for the second refund period.

Also in June 2019, the FERC’s Chief ALJ issued an order terminating settlement discussions in the amended complaint addressing System Energy’s capital structure. The ALJ consolidated the amended capital structure complaint with the ongoing return on equity proceeding and set new procedural deadlines for the consolidated hearing.

In August 2019 the LPSC, the APSC, and the MPSC filed rebuttal testimony in the return on equity proceeding and direct and answering testimony relating to System Energy’s capital structure. The LPSC re-argues for an authorized return on equity for System Energy of 7.81% for the first refund period and 7.97% for the second refund period. The APSC and MPSC argue for an authorized return on equity for System Energy of 8.26% for the first refund period and 8.32% for the second refund period. With respect to capital structure, the LPSC proposes that the FERC establish a hypothetical capital structure for System Energy for ratemaking purposes. Specifically, the LPSC proposes that System Energy’s common equity ratio be set to Entergy Corporation’s equity ratio of 37% equity and 63% debt. In the alternative, the LPSC argues that the equity ratio should be no higher than 49%, the composite equity ratio of System Energy and the other Entergy operating companies who purchase under the Unit Power Sales Agreement. The APSC and the MPSC recommend that 35.98% be set as the common equity ratio for System Energy. As an alternative, the APSC and the MPSC propose that System Energy’s common equity be set at 46.75% based on the median equity ratio of the proxy group for setting the return on equity.

In September 2019 the FERC trial staff filed its rebuttal testimony in the return on equity proceeding. For the first refund period, the FERC trial staff calculates an authorized return on equity for System Energy of 9.40% based on the application of the FERC’s proposed methodology and an updated proxy group. For the second refund period, based on the study period ending May 31, 2019, the FERC trial staff rebuttal testimony argues for a return on equity of 9.63%. In September 2019 the FERC trial staff also filed direct and answering testimony relating to System Energy’s capital structure. The FERC trial staff argues that the average capital structure of the proxy group

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System Energy Resources, Inc.

Management’s Financial Discussion and Analysis

used to develop System Energy’s return on equity should be used to establish the capital structure. Using this approach, the FERC trial staff calculates the average capital structure for its proposed proxy group of 46.74% common equity, and 53.26% debt.

In October 2019, System Energy filed answering testimony disputing the FERC trial staff’s, the LPSC’s, and the APSC’s and MPSC’s arguments for the use of a hypothetical capital structure and arguing that the use of System Energy’s actual capital structure is just and reasonable.

In November 2019, in a proceeding that did not involve System Energy, the FERC issued an order addressing the methodology for determining the return on equity applicable to transmission owners in MISO. Thereafter, the procedural schedule in the System Energy proceeding was amended to allow the participants to file supplemental testimony addressing the order in the MISO transmission owner proceeding (Opinion No. 569).

In February 2020 the LPSC, the MPSC and APSC, and the FERC trial staff filed supplemental testimony addressing Opinion No. 569 and how it would affect the return on equity evaluation for the two complaint periods concerning System Energy. For the first refund period, based on their respective interpretations and applications of the Opinion No. 569 methodology, the LPSC argues for an authorized return on equity for System Energy of 8.44%; the MPSC and APSC argue for an authorized return on equity of 8.41%; and the FERC trial staff argues for an authorized return on equity of 9.22%. For the second refund period and on a prospective basis, based on their respective interpretations and applications of the Opinion No. 569 methodology, the LPSC argues for an authorized return on equity for System Energy of 7.89%; the MPSC and APSC argue that an authorized return on equity of 8.01% may be appropriate; and the FERC trial staff argues for an authorized return on equity of 8.66%.

In April 2020, System Energy filed supplemental answering testimony addressing Opinion No. 569. System Energy argues that the Opinion No. 569 methodology is conceptually and analytically defective for purposes of establishing just and reasonable authorized return on equity determinations and proposes an alternative approach. As its primary recommendation, System Energy continues to support the return on equity determinations in its March 2019 testimony for the first refund period and its June 2019 testimony for the second refund period. Under the Opinion No. 569 methodology, System Energy calculates a “presumptively just and reasonable range” for the authorized return on equity for the first refund period of 8.57% to 9.52%, and for the second refund period of 8.28% to 9.11%. System Energy argues that these ranges are not just and reasonable results. Under its proposed alternative methodology, System Energy calculates an authorized return on equity of 10.26% for the first refund period, which also falls within the presumptively just and reasonable range calculated for the second refund period and prospectively.

In May 2020 the FERC issued an order on rehearing of Opinion No. 569 (Opinion No. 569-A). In June 2020 the procedural schedule in the System Energy proceeding was further revised in order to allow parties to address the Opinion No. 569-A methodology. Pursuant to the revised schedule, in June 2020, the LPSC, MPSC and APSC, and the FERC trial staff filed supplemental testimony addressing Opinion No. 569-A and how it would affect the return on equity evaluation for the two complaint periods concerning System Energy. For the first refund period, based on their respective interpretations and applications of the Opinion No. 569-A methodology, the LPSC argues for an authorized return on equity for System Energy of 7.97%; the MPSC and APSC argue for an authorized return on equity of 9.24%; and the FERC trial staff argues for an authorized return on equity of 9.49%. For the second refund period and on a prospective basis, based on their respective interpretations and applications of the Opinion No. 569-A methodology, the LPSC argues for an authorized return on equity for System Energy of 7.78%; the MPSC and APSC argue that an authorized return on equity of 9.15% may be appropriate if the second complaint is not dismissed; and the FERC trial staff argues for an authorized return on equity of 9.09% if the second complaint is not dismissed.

Pursuant to the revised procedural schedule, in July 2020, System Energy filed supplemental testimony addressing Opinion No. 569-A. System Energy argues that strict application of the Opinion No. 569-A methodology produces results inconsistent with investor requirements and does not provide a sound basis on which

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System Energy Resources, Inc.

Management’s Financial Discussion and Analysis

to evaluate System Energy’s authorized return on equity. As its primary recommendation, System Energy argues for the use of a methodology that incorporates four separate financial models, including the constant growth form of the discounted cash flow model and the empirical capital asset pricing model. Based on application of its recommended methodology, System Energy argues for an authorized return on equity of 10.12% for the first refund period, which also falls within the presumptively just and reasonable range calculated for the second refund period and prospectively. Under the Opinion No. 569-A methodology, System Energy calculates an authorized return on equity of 9.44% for the first refund period, which also falls within the presumptively just and reasonable range calculated for the second refund period and prospectively.

The parties and FERC trial staff filed final rounds of testimony in August 2020. The hearing before a FERC ALJ occurred in late-September through early-October 2020, post-hearing briefing took place in November and December 2020.

In March 2021 the FERC ALJ issued an initial decision. With regard to System Energy’s authorized return on equity, the ALJ determined that the existing return on equity of 10.94% is no longer just and reasonable, and that the replacement authorized return on equity, based on application of the Opinion No. 569-A methodology, should be 9.32%. The ALJ further determined that System Energy should pay refunds for a fifteen-month refund period (January 2017-April 2018) based on the difference between the current return on equity and the replacement authorized return on equity. The ALJ determined that the April 2018 complaint concerning the authorized return on equity should be dismissed, and that no refunds for a second fifteen-month refund period should be due. With regard to System Energy’s capital structure, the ALJ determined that System Energy’s actual equity ratio is excessive and that the just and reasonable equity ratio is 48.15% equity, based on the average equity ratio of the proxy group used to evaluate the return on equity for the second complaint. The ALJ further determined that System Energy should pay refunds for a fifteen-month refund period (September 2018-December 2019) based on the difference between the actual equity ratio and the 48.15% equity ratio. If the ALJ’s initial decision is upheld, the estimated refund for this proceeding is approximately $41 million, which includes interest through December 31, 2023, and the estimated resulting annual rate reduction would be approximately $25 million. As a result of the 2022 settlement agreement with the MPSC, both the estimated refund and rate reduction exclude Entergy Mississippi's portion. See “System Energy Settlement with the MPSC” below for discussion of the settlement. The estimated refund will continue to accrue interest until a final FERC decision is issued.

The ALJ initial decision is an interim step in the FERC litigation process, and an ALJ’s determinations made in an initial decision are not controlling on the FERC. In April 2021, System Energy filed its brief on exceptions, in which it challenged the initial decision’s findings on both the return on equity and capital structure issues. Also in April 2021 the LPSC, the APSC, the MPSC, the City Council, and the FERC trial staff filed briefs on exceptions. Reply briefs opposing exceptions were filed in May 2021 by System Energy, the FERC trial staff, the LPSC, the APSC, the MPSC, and the City Council. Refunds, if any, that might be required will only become due after the FERC issues its order reviewing the initial decision.

As discussed in “System Energy Settlement with the MPSC” below, beginning with the July 2022 service month, bills issued to Entergy Mississippi under the Unit Power Sales Agreement were adjusted to reflect a capital structure not to exceed 52% equity.

In August 2022 the D.C. Circuit Court of Appeals issued an order addressing appeals of FERC’s Opinion No. 569 and 569-A, which established the methodology applied in the ALJ’s initial decision in the proceeding against System Energy discussed above. The appellate order addressed the methodology for determining the return on equity applicable to transmission owners in MISO. The D.C. Circuit found the FERC’s use of the Risk Premium model as part of the methodology to be arbitrary and capricious, and remanded the case back to the FERC. The remanded case is pending FERC action.

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System Energy Resources, Inc.

Management’s Financial Discussion and Analysis

Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue

In May 2018 the LPSC filed a complaint against System Energy and Entergy Services related to System Energy’s renewal of a sale-leaseback transaction originally entered into in December 1988 for an 11.5% undivided interest in Grand Gulf Unit 1. The complaint alleges that System Energy violated the filed rate and the FERC’s ratemaking and accounting requirements when it included in Unit Power Sales Agreement billings the cost of capital additions associated with the sale-leaseback interest, and that System Energy is double-recovering costs by including both the lease payments and the capital additions in Unit Power Sales Agreement billings. The complaint also claims that System Energy was imprudent in entering into the sale-leaseback renewal because the Utility operating companies that purchase Grand Gulf’s output from System Energy could have obtained cheaper capacity and energy in the MISO markets. The complaint further alleges that System Energy violated various other reporting and accounting requirements and should have sought prior FERC approval of the lease renewal. The complaint seeks various forms of relief from the FERC. The complaint seeks refunds for capital addition costs for all years in which they were recorded in allegedly non-formula accounts or, alternatively, the disallowance of the return on equity for the capital additions in those years plus interest. The complaint also asks that the FERC disallow and refund the lease costs of the sale-leaseback renewal on grounds of imprudence, investigate System Energy’s treatment of a DOE litigation payment, and impose certain forward-looking procedural protections, including audit rights for retail regulators of the Unit Power Sales Agreement formula rates. The APSC, the MPSC, and the City Council intervened in the proceeding.

In June 2018, System Energy and Entergy Services filed a motion to dismiss and an answer to the LPSC complaint denying that System Energy’s treatment of the sale-leaseback renewal and capital additions violated the terms of the filed rate or any other FERC ratemaking, accounting, or legal requirements or otherwise constituted double recovery. The response also argued that the complaint is inconsistent with a FERC-approved settlement to which the LPSC is a party and that explicitly authorizes System Energy to recover its lease payments. Finally, the response argued that both the capital additions and the sale-leaseback renewal were prudent investments and the LPSC complaint fails to justify any disallowance or refunds. The response also offered to submit formula rate protocols for the Unit Power Sales Agreement similar to the procedures used for reviewing transmission rates under the MISO tariff. In September 2018 the FERC issued an order setting the complaint for hearing and settlement proceedings. The FERC established a refund effective date of May 18, 2018.

In February 2019 the presiding ALJ ruled that the hearing ordered by the FERC includes the issue of whether specific subcategories of accumulated deferred income tax should be included in, or excluded from, System Energy’s formula rate. In March 2019 the LPSC, the MPSC, the APSC and the City Council filed direct testimony. The LPSC testimony sought refunds that include the renewal lease payments (approximately $17.2 million per year since July 2015), rate base reductions for accumulated deferred income tax associated with uncertain tax positions, and the cost of capital additions associated with the sale-leaseback interest, as well as interest on those amounts.

In June 2019 System Energy filed answering testimony arguing that the FERC should reject all claims for refunds. Among other things, System Energy argued that claims for refunds of the costs of lease renewal payments and capital additions should be rejected because those costs were recovered consistent with the Unit Power Sales Agreement formula rate, System Energy was not over or double recovering any costs, and ratepayers will save costs over the initial and renewal terms of the leases. System Energy argued that claims for refunds associated with liabilities arising from uncertain tax positions should be rejected because the liabilities do not provide cost-free capital, the repayment timing of the liabilities is uncertain, and the outcome of the underlying tax positions is uncertain. System Energy’s testimony also challenged the refund calculations supplied by the other parties.

In August 2019 the FERC trial staff filed direct and answering testimony seeking refunds for rate base reductions for liabilities associated with uncertain tax positions. The FERC trial staff also argued that System Energy recovered $32 million more than it should have in depreciation expense for capital additions. In September 2019, System Energy filed cross-answering testimony disputing the FERC trial staff’s arguments for refunds, stating that the FERC trial staff’s position regarding depreciation rates for capital additions is not unreasonable, but

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explaining that any change in depreciation expense is only one element of a Unit Power Sales Agreement re-billing calculation. Adjustments to depreciation expense in any re-billing under the Unit Power Sales Agreement formula rate will also involve changes to accumulated depreciation, accumulated deferred income taxes, and other formula elements as needed. In October 2019 the LPSC filed rebuttal testimony increasing the amount of refunds sought for liabilities associated with uncertain tax positions. The LPSC seeks approximately $512 million plus interest, which is approximately $310 million through December 31, 2023. The FERC trial staff also filed rebuttal testimony in which it seeks refunds of a similar amount as the LPSC for the liabilities associated with uncertain tax positions. The LPSC testimony also argued that adjustments to depreciation rates should affect rate base on a prospective basis only.

A hearing was held before a FERC ALJ in November 2019. In April 2020 the ALJ issued the initial decision. Among other things, the ALJ determined that refunds were due on three main issues. First, with regard to the lease renewal payments, the ALJ determined that System Energy is recovering an unjust acquisition premium through the lease renewal payments, and that System Energy’s recovery from customers through rates should be limited to the cost of service based on the remaining net book value of the leased assets, which is approximately $70 million. The ALJ found that the remedy for this issue should be the refund of lease payments (approximately $17.2 million per year since July 2015) with interest determined at the FERC quarterly interest rate, which would be offset by the addition of the net book value of the leased assets in the cost of service. The ALJ did not calculate a value for the refund expected as a result of this remedy. In addition, System Energy would no longer recover the lease payments in rates prospectively. Second, with regard to the liabilities associated with uncertain tax positions, the ALJ determined that the liabilities are accumulated deferred income taxes and that System Energy’s rate base should have been reduced for those liabilities. The ALJ also found that System Energy should include liabilities associated with uncertain tax positions as a rate base reduction going forward. Third, with regard to the depreciation expense adjustments, the ALJ found that System Energy should correct for the error in re-billings retroactively and prospectively, but that System Energy should not be permitted to recover interest on any retroactive return on enhanced rate base resulting from such corrections.

In June 2020, System Energy, the LPSC, and the FERC trial staff filed briefs on exceptions, challenging several of the initial decision’s findings. System Energy’s brief on exceptions challenged the initial decision’s limitations on recovery of the lease renewal payments, its proposed rate base refund for the liabilities associated with uncertain tax positions, and its proposal to asymmetrically treat interest on bill corrections for depreciation expense adjustments. The LPSC’s and the FERC trial staff’s briefs on exceptions each challenged the initial decision’s allowance for recovery of the cost of service associated with the lease renewal based on the remaining net book value of the leased assets, its calculation of the remaining net book value of the leased assets, and the amount of the initial decision’s proposed rate base refund for the liabilities associated with uncertain tax positions. The LPSC’s brief on exceptions also challenged the initial decision’s proposal that depreciation expense adjustments include retroactive adjustments to rate base and its finding that section 203 of the Federal Power Act did not apply to the lease renewal. The FERC trial staff’s brief on exceptions also challenged the initial decision’s finding that the FERC need not institute a formal investigation into System Energy’s tariff. In October 2020, System Energy, the LPSC, the MPSC, the APSC, and the City Council filed briefs opposing exceptions. System Energy opposed the exceptions filed by the LPSC and the FERC trial staff. The LPSC, the MPSC, the APSC, the City Council, and the FERC trial staff opposed the exceptions filed by System Energy. Also in October 2020 the MPSC, the APSC, and the City Council filed briefs adopting the exceptions of the LPSC and the FERC trial staff.

In addition, in September 2020, the IRS issued a Notice of Proposed Adjustment (NOPA) and Entergy executed it. The NOPA memorializes the IRS’s decision to adjust the 2015 consolidated federal income tax return of Entergy Corporation and certain of its subsidiaries, including System Energy, with regard to the uncertain decommissioning tax position. Pursuant to the audit resolution documented in the NOPA, the IRS allowed System Energy’s inclusion of $102 million of future nuclear decommissioning costs in System Energy’s cost of goods sold for the 2015 tax year, roughly 10% of the requested deduction, but disallowed the balance of the position. In September 2020, System Energy filed a motion to lodge the NOPA into the record in the FERC proceeding. In October 2020 the LPSC, the APSC, the MPSC, the City Council, and the FERC trial staff filed oppositions to

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System Energy’s motion. As a result of the NOPA issued by the IRS in September 2020, System Energy filed, in October 2020, a new Federal Power Act section 205 filing at FERC to establish an ongoing rate base credit for the accumulated deferred income taxes resulting from the decommissioning uncertain tax position. On a prospective basis beginning with the October 2020 bill, System Energy proposes to include the accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position as a credit to rate base under the Unit Power Sales Agreement. In November 2020 the LPSC, the APSC, the MPSC, and the City Council filed a protest to the filing, and System Energy responded.

In November 2020 the IRS issued a Revenue Agent’s Report (RAR) for the 2014/2015 tax year and in December 2020 Entergy executed it. The RAR contained the same adjustment to the uncertain nuclear decommissioning tax position as that which the IRS had announced in the NOPA. In December 2020, System Energy filed a motion to lodge the RAR into the record in the FERC proceeding addressing the uncertain tax position rate base issue. In January 2021 the LPSC, the APSC, the MPSC, and the City Council filed a protest to the motion.

As a result of the RAR, in December 2020, System Energy filed amendments to its new Federal Power Act section 205 filings to establish an ongoing rate base credit for the accumulated deferred income taxes resulting from the decommissioning uncertain tax position and to credit excess accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position. The amendments both propose the inclusion of the RAR as support for the filings. In December 2020 the LPSC, the APSC, and the City Council filed a protest in response to the amendments, reiterating their prior objections to the filings. In February 2021 the FERC issued an order accepting System Energy’s Federal Power Act section 205 filings subject to refund, setting them for hearing, and holding the hearing in abeyance.

In December 2020, System Energy filed a new Federal Power Act section 205 filing to provide a one-time, historical credit of $25.2 million for the accumulated deferred income taxes that would have been created by the decommissioning uncertain tax position if the IRS’s decision had been known in 2016. In January 2021 the LPSC, APSC, MPSC, and City Council filed a protest to the filing. In February 2021 the FERC issued an order accepting System Energy’s Federal Power Act section 205 filing subject to refund, setting it for hearing, and holding the hearing in abeyance. The one-time credit was made during the first quarter 2021.

In December 2022 the FERC issued an order on the ALJ’s initial decision, which affirmed it in part and modified it in part. The FERC’s order directed System Energy to calculate refunds on three issues, and to provide a compliance report detailing the calculations. The FERC’s order also disallows the future recovery of sale-leaseback renewal costs, which is estimated at approximately $11.5 million annually for purchases from Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans through July 2036. The three refund issues are rental expenses related to the renewal of the sale-leaseback arrangements; refunds, if any, for the revenue requirement impact of including accumulated deferred income taxes resulting from the decommissioning uncertain tax positions from 2004 through the present; and refunds for the net effect of correcting the depreciation inputs for capital additions attributable to the portion of plant subject to the sale-leaseback.

As a result of the FERC order’s directives regarding the recovery of the sale-leaseback transaction, in December 2022 System Energy reduced the Grand Gulf sale-leaseback regulatory liability by $56 million, reduced the related accumulated deferred income tax asset by $94 million, and reduced the Grand Gulf sale-leaseback accumulated deferred income tax regulatory liability by $25 million, resulting in an increase in income tax expense of $13 million. In addition, the FERC determined that System Energy recognized excess depreciation expense related to property subject to the sale-leaseback. As a result, in December 2022, System Energy recorded a reduction in depreciation expense and the related accumulated depreciation of $33 million.

In January 2023, System Energy filed its compliance report with the FERC. With respect to the sale-leaseback renewal costs, System Energy calculated a refund of $89.8 million, which represented all of the sale-leaseback renewal rental costs that System Energy recovered in rates, with interest. With respect to the

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decommissioning uncertain tax position issue, System Energy calculated that no additional refunds are owed because it had already provided a one-time historical credit (for the period January 2016 through September 2020) of $25.2 million based on the accumulated deferred income taxes that resulted from the IRS’s partial acceptance of the decommissioning tax position, and because it has been providing an ongoing rate base credit for the accumulated deferred income taxes that resulted from the IRS’s partial acceptance of the decommissioning tax position since October 2020. With respect to the depreciation refund, System Energy calculated a refund of $13.7 million, which is the net total of a refund to customers for excess depreciation expense previously collected, plus interest, offset by the additional return on rate base that System Energy previously did not collect, without interest. See “System Energy Settlement with the MPSC” below for discussion of the regulatory charge and corresponding regulatory liability recorded in June 2022 related to these proceedings. The $103.5 million in total refunds calculated in the compliance filing were reclassified from long-term other regulatory liabilities to a current regulatory liability as of December 31, 2022. In January 2023, System Energy paid the refunds of $103.5 million, which included refunds of $41.7 million to Entergy Arkansas, $27.8 million to Entergy Louisiana, and $34 million to Entergy New Orleans.

In February 2023 the LPSC, the APSC, and the City Council filed protests to System Energy’s January 2023 compliance report, in which they challenged System Energy’s calculation of the refunds associated with the decommissioning tax position but did not protest the other components of the compliance report. Each of them argued that System Energy should have paid additional refunds for the decommissioning tax position issue, and the City Council estimated the total additional refunds owed to customers of Entergy Louisiana, Entergy New Orleans, and Entergy Arkansas for that issue as $493 million, including interest (and without factoring in the $25.2 million refund that System Energy already paid in 2021).

In January 2023, System Energy filed a request for rehearing of the FERC’s determinations in the December 2022 order on sale-leaseback refund issues and future lease cost disallowances, the FERC’s prospective policy on uncertain tax positions, and the proper accounting of System Energy’s accumulated deferred income taxes adjustment for the Tax Cuts and Jobs Act of 2017; and a motion for confirmation of its interpretation of the December 2022 order’s remedy concerning the decommissioning tax position. In January 2023 the retail regulators filed a motion for confirmation of their interpretation of the refund requirement in the December 2022 FERC order and a provisional request for rehearing. In February 2023 the FERC issued a notice that the rehearing requests have been deemed denied by operation of law. The deemed denial of the rehearing request initiates a sixty-day period in which aggrieved parties may petition for federal appellate court review of the underlying FERC orders; however, the FERC may issue a substantive order on rehearing as long as it continues to have jurisdiction over the case. In March 2023, System Energy filed in the United States Court of Appeals for the Fifth Circuit a petition for review of the December 2022 order. In March 2023, System Energy also filed an unopposed motion to stay the proceeding in the Fifth Circuit pending the FERC’s disposition of the pending motions, and the court granted the motion to stay.

In February 2023, System Energy submitted a tariff compliance filing with the FERC to clarify that, consistent with the releases provided in the MPSC settlement, Entergy Mississippi will continue to be charged for its allocation of the sale-leaseback renewal costs under the Unit Power Sales Agreement. See “System Energy Settlement with the MPSC” below for discussion of the settlement. In March 2023 the MPSC filed a protest to System Energy’s tariff compliance filing. The MPSC argues that the settlement did not specifically address post-settlement sale-leaseback renewal costs and that the sale-leaseback renewal costs may not be recovered under the Unit Power Sales Agreement. Entergy Mississippi’s allocated sale-leaseback renewal costs are estimated at $5.7 million annually for the remaining term of the sale-leaseback renewal.

In August 2023 the FERC issued an order addressing arguments raised on rehearing and partially setting aside the prior order (rehearing order). The rehearing order addresses rehearing requests that were filed in January 2023 separately by System Energy and the LPSC, the APSC, and the City Council.

In the rehearing order, the FERC directs System Energy to recalculate refunds for two issues: (1) refunds of rental expenses related to the renewal of the sale-leaseback arrangements and (2) refunds for the net effect of

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correcting the depreciation inputs for capital additions associated with the sale-leaseback. With regard to the sale-leaseback renewal rental expenses, the rehearing order allows System Energy to recover an implied return of and on the depreciated cost of the portion of the plant subject to the sale-leaseback as of the expiration of the initial lease term. With regard to the depreciation input issue, the rehearing order allows System Energy to offset refunds so that System Energy may collect interest on the rate base recalculations that were part of the overall depreciation rate recalculations. The rehearing order further directs System Energy to submit within 60 days of the date of the rehearing order an additional compliance filing to revise the total refunds for these two issues. As discussed above, System Energy’s January 2023 compliance filing calculated $103.5 million in total refunds, and the refunds were paid in January 2023. In October 2023, System Energy filed its compliance report with the FERC as directed in the August 2023 rehearing order. The October 2023 compliance report reflected recalculated refunds totaling $35.7 million for the two issues resulting in $67.8 million in refunds that could be recouped by System Energy. As discussed below in “System Energy Settlement with the APSC,” System Energy reached a settlement in principle with the APSC to resolve several pending cases under the FERC’s jurisdiction, including this one, pursuant to which it has agreed not to recoup the $27.3 million calculated for Entergy Arkansas in the compliance filing. As a result of the FERC’s rulings on the sale-leaseback and depreciation input issues in the August 2023 rehearing order, in third quarter 2023, System Energy recorded a regulatory asset and corresponding regulatory credit of $40 million to reflect the portion of the January 2023 refunds to be recouped from Entergy Louisiana and Entergy New Orleans. Consistent with the compliance filing, in October 2023, Entergy Louisiana and Entergy New Orleans paid recoupment amounts of $18.2 million and $22.3 million, respectively, to System Energy.

On the third refund issue identified in the rehearing requests, concerning the decommissioning uncertain tax positions, the rehearing order denied all rehearing requests, re-affirmed the remedy contained in the December 2022 order, and did not direct System Energy to recalculate refunds or to submit an additional compliance filing. On this issue, as reflected in its January 2023 compliance filing, System Energy believes it has already paid the refunds due under the remedy that the FERC outlined for the uncertain tax positions issue in its December 2022 order. In August 2023 the LPSC issued a media release in which it stated that it disagrees with System Energy’s determination that the rehearing order requires no further refunds to be made on this issue.

In September 2023, System Energy filed a protective appeal of the rehearing order with the United States Court of Appeals for the Fifth Circuit. The appeal was consolidated with System Energy’s prior appeal of the December 2022 order.

In September 2023 the LPSC filed with the FERC a request for rehearing and clarification of the rehearing order. The LPSC requests that the FERC reverse its determination in the rehearing order that System Energy may collect an implied return of and on the depreciated cost of the portion of the plant subject to the sale-leaseback, as of the expiration of the initial lease term, as well as its determination in the rehearing order that System Energy may offset the refunds for the depreciation rate input issue and collect interest on the rate base recalculations that were part of the overall depreciation rate recalculations. In addition, the LPSC requests that the FERC either confirm the LPSC’s interpretation of the refund associated with the decommissioning uncertain tax positions or explain why it is not doing so. In October 2023 the FERC issued a notice that the rehearing request has been deemed denied by operation of law. In November 2023 the FERC issued a further notice stating that it would not issue any further order addressing the rehearing request. Also in November 2023 the LPSC filed with the United States Court of Appeals for the Fifth Circuit a petition for review of the FERC’s August 2023 rehearing order and denials of the September 2023 rehearing request.

In December 2023 the United States Court of Appeals for the Fifth Circuit lifted the abeyance on the consolidated System Energy appeals and it also consolidated the LPSC’s appeal with the System Energy appeals. In February 2024 the parties filed a proposed briefing schedule under which briefing will occur from March 2024 through July 2024.

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LPSC Additional Complaints

In May 2020 the LPSC authorized its staff to file additional complaints at the FERC related to the rates charged by System Energy for Grand Gulf energy and capacity supplied to Entergy Louisiana under the Unit Power Sales Agreement. The LPSC directive noted that the initial decision issued by the presiding ALJ in the Grand Gulf sale-leaseback complaint proceeding did not address, for procedural reasons, certain rate issues raised by the LPSC and declined to order further investigation of rates charged by System Energy. The LPSC directive authorized its staff to file complaints at the FERC “necessary to address these rate issues, to request a full investigation into the rates charged by System Energy for Grand Gulf power, and to seek rate refund, rate reduction, and such other remedies as may be necessary and appropriate to protect Louisiana ratepayers.” The LPSC directive further stated that the LPSC has seen “information suggesting that the Grand Gulf plant has been significantly underperforming compared to other nuclear plants in the United States, has had several extended and unexplained outages, and has been plagued with serious safety concerns.” The LPSC expressed concern that the costs paid by Entergy Louisiana's retail customers may have been detrimentally impacted, and authorized “the filing of a FERC complaint to address these performance issues and to seek appropriate refund, rate reduction, and other remedies as may be appropriate.”

Unit Power Sales Agreement Complaint

The first of the additional complaints was filed by the LPSC, the APSC, the MPSC, and the City Council in September 2020. The first complaint raises two sets of rate allegations: violations of the filed rate and a corresponding request for refunds for prior periods; and elements of the Unit Power Sales Agreement are unjust and unreasonable and a corresponding request for refunds for the 15-month refund period and changes to the Unit Power Sales Agreement prospectively. Several of the filed rate allegations overlap with the previous complaints. The filed rate allegations not previously raised are that System Energy: failed to provide a rate base credit to customers for the “time value” of sale-leaseback lease payments collected from customers in advance of the time those payments were due to the owner-lessors; improperly included certain sale-leaseback transaction costs in rate base as prepayments; improperly included nuclear refueling outage costs in rate base; wrongly included categories of accumulated deferred income taxes as increases to rate base; charged customers based on a higher equity ratio than would be appropriate due to excessive retained earnings; and did not correctly reflect money pool investments and imprudently invested cash into the money pool. The elements of the Unit Power Sales Agreement that the complaint alleges are unjust and unreasonable include: the current cash working capital allowance of zero, uncapped recovery of incentive and executive compensation, lack of an equity re-opener, and recovery of lobbying and private airplane travel expenses. The complaint also requests a rate investigation into the Unit Power Sales Agreement and System Energy’s billing practices pursuant to section 206 of the Federal Power Act, including any issue relevant to the Unit Power Sales Agreement and its inputs. System Energy filed its answer opposing the complaint in November 2020. In its answer, System Energy argued that all of the claims raised in the complaint should be dismissed and agreed that bill adjustment with respect to two discrete issues were justified. System Energy argued that dismissal is warranted because all claims fall into one or more of the following categories: the claims have been raised and are being litigated in another proceeding; the claims do not present a prima facie case and do not satisfy the threshold burden to establish a complaint proceeding; the claims are premised on a theory or request relief that is incompatible with federal law or FERC policy; the claims request relief that is inconsistent with the filed rate; the claims are barred or waived by the legal doctrine of laches; and/or the claims have been fully addressed and do not warrant further litigation. In December 2020, System Energy filed a bill adjustment report indicating that $3.4 million had been credited to customers in connection with the two discrete issues concerning the inclusion of certain accumulated deferred income taxes balances in rates. In January 2021 the complainants filed a response to System Energy’s November 2020 answer, and in February 2021, System Energy filed a response to the complainant’s response.

In May 2021 the FERC issued an order addressing the complaint, establishing a refund effective date of September 21, 2020, establishing hearing procedures, and holding those procedures in abeyance pending the FERC’s review of the initial decision in the Grand Gulf sale-leaseback renewal complaint discussed above. System

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Energy agreed that the hearing should be held in abeyance but sought rehearing of FERC’s decision as related to matters set for hearing that were beyond the scope of FERC’s jurisdiction or authority. The complainants sought rehearing of FERC’s decision to hold the hearing in abeyance and filed a motion to proceed, which motion System Energy subsequently opposed. In June 2021, System Energy’s request for rehearing was denied by operation of law, and System Energy filed an appeal of FERC’s orders in the Court of Appeals for the Fifth Circuit. The appeal was initially stayed for a period of 90 days, but the stay expired. In November 2021 the Fifth Circuit dismissed the appeal as premature.

In August 2021 the FERC issued an order addressing System Energy’s and the complainants’ rehearing requests. The FERC dismissed part of the complaint seeking an equity re-opener, maintained the abeyance for issues related to the proceeding addressing the sale-leaseback renewal and uncertain tax positions, lifted the abeyance for issues unrelated to that proceeding, and clarified the scope of the hearing.

In November 2021 the LPSC, the APSC, and the City Council filed direct testimony and requested the FERC to order refunds for prior periods and prospective amendments to the Unit Power Sales Agreement. The LPSC’s refund claims include, among other things, allegations that: (1) System Energy should not have included certain sale-leaseback transaction costs in prepayments; (2) System Energy should have credited rate base to reflect the time value of money associated with the advance collection of lease payments; (3) System Energy incorrectly included refueling outage costs that were recorded in account 174 in rate base; and (4) System Energy should have excluded several accumulated deferred income tax balances in account 190 from rate base. The LPSC is also seeking a retroactive adjustment to retained earnings and capital structure in conjunction with the implementation of its proposed refunds. In addition, the LPSC seeks amendments to the Unit Power Sales Agreement going forward to address below-the-line costs, incentive compensation, the working capital allowance, litigation expenses, and the 2019 termination of the capital funds agreement. The APSC argues that: (1) System Energy should have included borrowings from the Entergy system money pool in its determination of short-term debt in its cost of capital; and (2) System Energy should credit customers with System Energy’s allocation of earnings on money pool investments. The City Council alleges that System Energy has maintained excess cash on hand in the money pool and that retention of excess cash was imprudent. Based on this allegation, the City Council’s witness recommends a refund of approximately $98.8 million for the period 2004-September 2021 or other alternative relief. The City Council further recommends that the FERC impose a hypothetical equity ratio such as 48.15% equity to capital on a prospective basis.

In January 2022, System Energy filed answering testimony arguing that the FERC should not order refunds for prior periods or any prospective amendments to the Unit Power Sales Agreement. In response to the LPSC’s refund claims, System Energy argues, among other things, that: (1) the inclusion of sale-leaseback transaction costs in prepayments was correct; (2) that the filed rate doctrine bars the request for a retroactive credit to rate base for the time value of money associated with the advance collection of lease payments; (3) that an accounting misclassification for deferred refueling outage costs has been corrected, caused no harm to customers, and requires no refunds; and (4) that its accounting and ratemaking treatment of specified accumulated deferred income tax balances in account 190 has been correct. System Energy further responds that no retroactive adjustment to retained earnings or capital structure should be ordered because there is no general policy requiring such a remedy, and there was no showing that the retained earnings element of the capital structure was incorrectly implemented. Further, System Energy presented evidence that all of the costs that are being challenged were long known to the retail regulators and were approved by them for inclusion in retail rates, and the attempt to retroactively challenge these costs, some of which have been included in rates for decades, is unjust and unreasonable. In response to the LPSC’s proposed going-forward adjustments, System Energy presents evidence to show that none of the proposed adjustments are needed. On the issue of below-the-line expenses, during discovery procedures System Energy identified a historical allocation error in certain months and agreed to provide a bill credit to customers to correct the error. In response to the APSC’s claims, System Energy argues that the Unit Power Sales Agreement does not include System Energy’s borrowings from the Entergy system money pool or earnings on deposits to the Entergy system money pool in the determination of the cost of capital; and accordingly, no refunds are appropriate on those issues. In response to the City Council’s claims, System Energy argues that it has reasonably managed its cash and

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that the City Council’s theory of cash management is defective because it fails to adequately consider the relevant cash needs of System Energy and it makes faulty presumptions about the operation of the Entergy system money pool. System Energy further points out that the issue of its capital structure is already subject to pending FERC litigation.

In March 2022 the FERC trial staff filed direct and answering testimony in response to the LPSC, the APSC, and the City Council’s direct testimony. In its testimony, the FERC trial staff recommends refunds for two primary reasons: (1) it concluded that System Energy should have excluded specified accumulated deferred income tax balances in account 190 associated with rate refunds; and (2) it concluded that System Energy should have excluded specified accumulated deferred income tax balances in account 190 associated with a deemed contract satisfaction and reissuance that occurred in 2005. The FERC trial staff recommends refunds of $84.1 million, exclusive of any tax gross-up or FERC interest. In addition, the FERC trial staff recommends the following prospective modifications to the Unit Power Sales Agreement: (1) inclusion of a rate base credit to recognize the time value of money associated with the advance collection of lease payments; (2) exclusion of executive incentive compensation costs for members of the Office of the Chief Executive and long-term performance unit costs where awards are based solely or primarily on financial metrics; and (3) exclusion of unvested, accrued amounts for stock options, performance units, and restricted stock awards. With respect to issues that ultimately concern the reasonableness of System Energy’s rate of return, the FERC trial staff states that it is unnecessary to consider such issues in this proceeding, in light of the pending case concerning System Energy’s return on equity and capital structure. On all other material issues raised by the LPSC, the APSC, and the City Council, the FERC trial staff recommends either no refunds or no modification to the Unit Power Sales Agreement.

In April 2022, System Energy filed cross-answering testimony in response to the FERC trial staff’s recommendations of refunds for the accumulated deferred income taxes issues and proposed modifications to the Unit Power Sales Agreement for the executive incentive compensation issues. In June 2022 the FERC trial staff submitted revised answering testimony, in which it recommended additional refunds associated with the accumulated deferred income tax balances in account 190 associated with a deemed contract satisfaction and reissuance that occurred in 2005. Based on the testimony revisions, the FERC trial staff’s recommended refunds total $106.6 million, exclusive of any tax gross-up or FERC awarded interest. Also in June 2022, System Energy filed revised and supplemental cross-answering testimony to respond to the FERC trial staff’s testimony and oppose its revised recommendation.

In May 2022 the LPSC, the APSC, and the City Council filed rebuttal testimony. The LPSC’s testimony asserts new claims, including that: (1) certain of the sale-leaseback transaction costs may have been imprudently incurred; (2) accumulated deferred income taxes associated with sale-leaseback transaction costs should have been included in rate base; (3) accumulated deferred income taxes associated with federal investment tax credits should have been excluded from rate base; (4) monthly net operating loss accumulated deferred income taxes should have been excluded from rate base; and (5) several categories of proposed rate changes, including executive incentive compensation, air travel, industry dues, and legal costs, also warrant historical refunds. The LPSC’s rebuttal testimony argues that refunds for the alleged tariff violations and other claims must be calculated by rerunning the Unit Power Sales Agreement formula rate; however, it includes estimates of refunds associated with some, but not all, of its claims, totaling $286 million without interest. The City Council’s rebuttal testimony also proposes a new, alternate theory and claim for relief regarding System Energy’s participation in the Entergy system money pool, under which it calculates estimated refunds of approximately $51.7 million. The APSC’s rebuttal testimony agrees with the LPSC’s direct testimony that retained earnings should be adjusted in a comprehensive refund calculation. The testimony quantifies the estimated impacts of three issues: (1) a $1.5 million reduction in the revenue requirement under the Unit Power Sales Agreement if System Energy’s borrowings from the money pool are included in short-term debt; (2) a $1.9 million reduction in the revenue requirement if System Energy’s allocated share of money pool earnings are credited through the Unit Power Sales Agreement; and (3) a $1.9 million reduction in the revenue requirement for every $50 million of refunds ordered in a given year, without interest. In total, excluding the settled issues noted below, the claims seek more than $700 million in refunds and interest, based on charges to all Unit Power Sales Agreement purchasers including Entergy Mississippi.

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In June 2022 a new procedural schedule was adopted, providing for additional rounds of testimony and for the hearing to begin in September 2022. The hearing concluded in December 2022.

In November 2022, System Energy filed a partial settlement agreement with the APSC, the City Council, and the LPSC that resolved the following issues raised in the Unit Power Sales Agreement complaint: advance collection of lease payments, aircraft costs, executive incentive compensation, money pool borrowings, advertising expenses, deferred nuclear refueling outage costs, industry association dues, and termination of the capital funds agreement. The settlement provided that System Energy would provide a black-box refund of $18 million (inclusive of interest), plus additional refund amounts with interest to be calculated for certain issues to be distributed to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans as the Utility operating companies other than Entergy Mississippi purchasing under the Unit Power Sales Agreement. The settlement further provided that if the APSC, the City Council, or the LPSC agrees to the global settlement System Energy entered into with the MPSC (discussed below), and such global settlement includes a black-box refund amount, then the black-box refund for this settlement agreement shall not be incremental or in addition to the global black-box refund amount. The settlement agreement addressed other matters as well, including adjustments to rate base beginning in October 2022, exclusion of certain other costs, and inclusion of money pool borrowings, if any, in short-term debt within the cost of capital calculation used in the Unit Power Sales Agreement. In April 2023 the FERC approved the settlement agreement. The refund provided for in the settlement agreement was included in the May 2023 service month bills under the Unit Power Sales Agreement.

In May 2023 the presiding ALJ issued an initial decision finding that System Energy should have excluded multiple identified categories of accumulated deferred income taxes from rate base when calculating Unit Power Sales Agreement bills. Based on this finding, the initial decision recommended refunds; System Energy estimates that those refunds for Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans would total approximately $116 million plus $152 million of interest through December 31, 2023. The initial decision also finds that the Unit Power Sales Agreement should be modified such that a cash working capital allowance of negative $36.4 million is applied prospectively. If the FERC ultimately orders these modifications to cash working capital be implemented, the estimated annual revenue requirement impact is expected to be immaterial. On the other non-settled issues for which the complainants sought refunds or changes to the Unit Power Sales Agreement, the initial decision ruled against the complainants.

The initial decision is an interim step in the FERC litigation process, and an ALJ’s determination made in an initial decision is not controlling on the FERC. System Energy disagrees with the ALJ’s findings concerning the accumulated deferred income taxes issues and cash working capital. In July 2023, System Energy filed a brief on exceptions to the initial decision’s accumulated deferred income taxes findings. Also in July 2023, the APSC, the LPSC, the City Council, and the FERC trial staff filed separate briefs on exceptions. The APSC’s brief on exceptions challenges the ALJ’s determinations on the money pool interest and retained earnings issues. The LPSC’s brief on exceptions challenges the ALJ’s determinations regarding the sale-leaseback transaction costs, legal fees, and retained earnings issues. The City Council’s brief on exceptions challenges the ALJ’s determinations on the money pool and cash management issues. The FERC trial staff’s brief on exceptions challenges the ALJ’s determinations on the cash working capital issue as well as certain of the accumulated deferred income taxes issues. In August 2023 all parties filed separate briefs opposing exceptions. System Energy filed a brief opposing the exceptions of the APSC, the LPSC, and the City Council. The APSC, the LPSC, and the City Council filed separate briefs opposing the exceptions raised by System Energy and the FERC trial staff. The FERC trial staff filed its own brief opposing certain exceptions raised by System Energy, the APSC, the LPSC, and the City Council. The case is now pending a decision by the FERC. Refunds, if any, that might be required will become due only after the FERC issues its order reviewing the initial decision.

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Grand Gulf Prudence Complaint

The second of the additional complaints was filed at the FERC in March 2021 by the LPSC, the APSC, and the City Council against System Energy, Entergy Services, Entergy Operations, and Entergy Corporation. The second complaint contains two primary allegations. First, it alleges that, based on the plant’s capacity factor and alleged safety performance, System Energy and the other respondents imprudently operated Grand Gulf during the period 2016-2020, and it seeks refunds of at least $360 million in alleged replacement energy costs, in addition to other costs, including those that can only be identified upon further investigation. Second, it alleges that the performance and/or management of the 2012 extended power uprate of Grand Gulf was imprudent, and it seeks refunds of all costs of the 2012 uprate that are determined to result from imprudent planning or management of the project. In addition to the requested refunds, the complaint asks that the FERC modify the Unit Power Sales Agreement to provide for full cost recovery only if certain performance indicators are met and to require pre-authorization of capital improvement projects in excess of $125 million before related costs may be passed through to customers in rates. In April 2021, System Energy and the other respondents filed their motion to dismiss and answer to the complaint. System Energy requested that the FERC dismiss the claims within the complaint. With respect to the claim concerning operations, System Energy argues that the complaint does not meet its legal burden because, among other reasons, it fails to allege any specific imprudent conduct. With respect to the claim concerning the uprate, System Energy argues that the complaint fails because, among other reasons, the complainants’ own conduct prevents them from raising a serious doubt as to the prudence of the uprate. System Energy also requests that the FERC dismiss other elements of the complaint, including the proposed modifications to the Unit Power Sales Agreement, because they are not warranted. Additional responsive pleadings were filed by the complainants and System Energy during the period from March through July 2021. In November 2022 the FERC issued an order setting the complaint for settlement and hearing procedures. In February 2023 the FERC issued an order denying rehearing and thereby affirming its order setting the complaint for settlement and hearing procedures. In July 2023 the FERC chief ALJ terminated settlement procedures and appointed a presiding ALJ to oversee hearing procedures. In September 2023 a procedural schedule for hearing procedures was established. Pursuant to that schedule, the complainant’s testimony was filed in December 2023. System Energy’s answering testimony is due April 2024, and additional rounds of testimony are due through October 2024. The hearing is scheduled to begin in January 2025, with the presiding ALJ’s initial decision due in July 2025.

In September 2023 the LPSC authorized its staff to file an additional complaint concerning the prudence of System Energy’s operation and management of Grand Gulf in the year 2022. In October 2023 the LPSC, the APSC, and the City Council filed what they styled as an amended and supplemental complaint with the FERC against System Energy, Entergy Services, and Entergy Operations. As discussed below in “System Energy Settlement with the APSC”, the APSC has settled all of its claims related to this proceeding. The amended complaint states that it is being filed for three primary purposes: (1) to include System Energy’s performance in 2021-2022 in the scope of the hearing; (2) to explicitly allege that System Energy’s inadequate performance, excessive costs, unplanned outages, and costs attributable to safety violations violate the contractual obligation to maintain and operate the plant in accordance with “good utility practice”; and (3) to provide and substantiate allegations concerning the damages attributable to the alleged breach of contractual obligations. The amended complaint alleges that potentially more than $1 billion in damages may be due. In November 2023, System Energy and the other Entergy respondents filed an answer and motion to dismiss the amended and supplemental complaint.

System Energy Settlement with the MPSC

In June 2022, System Energy, Entergy Mississippi, and additional named Entergy parties involved in thirteen docketed proceedings before the FERC filed with the FERC a partial settlement agreement and offer of settlement. The settlement memorializes the Entergy parties’ agreement with the MPSC to globally resolve all actual and potential claims between the Entergy parties and the MPSC associated with those FERC proceedings and with System Energy’s past implementation of the Unit Power Sales Agreement. The Unit Power Sales Agreement is a FERC-jurisdictional formula rate tariff for sales of energy and capacity from System Energy’s owned and leased share of Grand Gulf to Entergy Mississippi, Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans.

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Entergy Mississippi purchases the greatest single amount, nearly 40% of System Energy’s share of Grand Gulf, after its additional purchases from affiliates are considered. The settlement therefore limits System Energy’s overall refund exposure associated with the identified proceedings because they will be resolved completely as between the Entergy parties and the MPSC.

The settlement provided for a black-box refund of $235 million from System Energy to Entergy Mississippi, which was to be paid within 120 days of the settlement’s effective date (either the date of the FERC approval of the settlement without material modification, or the date that all settling parties agree to accept modifications or otherwise modify the settlement in response to a proposed material modification by the FERC). In addition, beginning with the July 2022 service month, the settlement provided for Entergy Mississippi’s bills from System Energy to be adjusted to reflect: an authorized rate of return on equity of 9.65%, a capital structure not to exceed 52% equity, a rate base reduction for the advance collection of sale-leaseback rental costs, and the exclusion of certain long-term incentive plan performance unit costs from rates. The settlement was approved by the MPSC in June 2022 and the FERC in November 2022.

System Energy previously recorded a provision and associated liability of $37 million for elements of the applicable litigation. In June 2022, System Energy recorded a regulatory charge of $551 million ($413 million net-of-tax), increasing the regulatory liability to $588 million, which consisted of $235 million for the settlement with the MPSC and $353 million for potential future refunds to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans. System Energy paid the black-box refund of $235 million to Entergy Mississippi in November 2022. See “System Energy Regulatory Liability for Pending Complaints” below for discussion of the regulatory liability related to complaints against System Energy as of December 31, 2023.

System Energy Settlement with the APSC

In October 2023, System Energy, Entergy Arkansas, and additional named Entergy parties involved in multiple docketed proceedings pending before the FERC reached a settlement in principle with the APSC to globally resolve all of their actual and potential claims in those dockets and with System Energy’s past implementation of the Unit Power Sales Agreement. The settlement also covers the amended and supplemental complaint, discussed above in “Grand Gulf Prudence Complaint,” filed at the FERC in October 2023. System Energy, Entergy Arkansas, additional Entergy parties, and the APSC filed the settlement agreement and supporting materials with the FERC in November 2023. The Unit Power Sales Agreement is a FERC-jurisdictional formula rate tariff for sales of energy and capacity from System Energy’s owned and leased share of Grand Gulf to Entergy Mississippi, Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans. As discussed above in “System Energy Settlement with the MPSC,” System Energy previously settled with the MPSC with respect to these complaints before the FERC. Entergy Mississippi has nearly 40% of System Energy’s share of Grand Gulf’s output, after its additional purchases from affiliates are considered. The settlements with both the APSC and the MPSC represent almost 65% of System Energy’s share of the output of Grand Gulf.

The terms of the settlement with the APSC align with the $588 million global black box settlement reached between System Energy and the MPSC in June 2022 and provide for Entergy Arkansas to receive a black box refund of $142 million from System Energy, inclusive of $49.5 million already received by Entergy Arkansas from System Energy. In November 2022 the FERC approved the System Energy settlement with the MPSC and stated that the settlement “appears to be fair and reasonable and in the public interest.”

In addition to the black box refund of $142 million described above, beginning with the November 2023 service month, the settlement provides for Entergy Arkansas’s bills from System Energy to be adjusted to reflect an authorized rate of return on equity of 9.65% and a capital structure not to exceed 52% equity.

In December 2023 the FERC trial staff and the LPSC filed comments. The FERC trial staff commented that it “believes that the settlement is fair, and in the public interest,” and neither it nor the LPSC oppose the settlement. In December 2023 the $93 million black box refund to Entergy Arkansas was reclassified from long-

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term other regulatory liabilities to accounts payable - associated companies on System Energy’s balance sheet. If the FERC approves the filed settlement in accordance with its terms, it will become binding upon the Entergy parties and the APSC.

System Energy Regulatory Liability for Pending Complaints

Prior to June 2022, System Energy recorded a provision and associated liability of $37 million for elements of the complaints against System Energy. In June 2022, as discussed in “System Energy Settlement with the MPSC” above, System Energy recorded a regulatory charge of $551 million ($413 million net-of-tax), increasing System Energy’s regulatory liability to $588 million, which consisted of $235 million for the settlement with the MPSC and $353 million for potential future refunds to Entergy Arkansas, Entergy New Orleans, and Entergy Louisiana. The $142 million of refunds for Entergy Arkansas, discussed above in “System Energy Settlement with the APSC” is covered within the $353 million previously recorded. System Energy paid the black-box refund of $235 million to Entergy Mississippi in November 2022. As discussed above in “Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue,” in January 2023 System Energy paid refunds of $103.5 million as a result of the FERC’s order in December 2022 in that proceeding and recouped $40.5 million of the $103.5 million from Entergy Louisiana and Entergy New Orleans in October 2023. In addition, as discussed above in “Unit Power Sales Agreement Complaint,” a black-box refund of $18 million was made by System Energy in 2023 in connection with a partial settlement in that proceeding.

Based on analysis of the pending complaints against System Energy and potential future settlement negotiations with the LPSC and the City Council, in third quarter 2023, System Energy recorded a regulatory charge of $40 million to increase System Energy’s regulatory liability related to complaints against System Energy. As discussed above, in December 2023 the $93 million black box refund to Entergy Arkansas was reclassified from the regulatory liability to accounts payable - associated companies on System Energy’s balance sheet. System Energy’s remaining regulatory liability related to complaints against System Energy as of December 31, 2023 is $178 million. This regulatory liability is consistent with the settlement agreements reached with the MPSC and the APSC, as described above, taking into account amounts already or expected to be refunded.

Unit Power Sales Agreement

System Energy Formula Rate Annual Protocols Formal Challenge Concerning 2020 Calendar Year Bills

System Energy’s Unit Power Sales Agreement includes formula rate protocols that provide for the disclosure of cost inputs, an opportunity for informal discovery procedures, and a challenge process. In February 2022, pursuant to the protocols procedures, the LPSC, the APSC, the MPSC, the City Council, and the Mississippi Public Utilities Staff filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2020. The formal challenge alleges: (1) that it was imprudent for System Energy to accept the IRS’s partial acceptance of a previously uncertain tax position; (2) that System Energy should have delayed recording the result of the IRS’s partial acceptance of the previously uncertain tax position until after internal tax allocation payments were made; (3) that the equity ratio charged in rates was excessive; (4) that sale-leaseback rental payments should have been excluded from rates; and (5) that all issues in the ongoing Unit Power Sales Agreement complaint proceeding should also be reflected in calendar year 2020 bills. While System Energy disagrees that any refunds are owed for the 2020 calendar year bills, the formal challenge estimates that the financial impact of the first through fourth allegations is approximately $53 million; it does not provide an estimate of the financial impact of the fifth allegation. However, $17 million of the $53 million is attributable to the sale-leaseback rental payments. These were refunded to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans in January 2023 as a result of the FERC order received in the Grand Gulf sale-leaseback renewal complaint and uncertain tax position rate base issue. Entergy Mississippi’s portion of the refund was included within the settlement with the MPSC, as discussed below.

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In March 2022, System Energy filed an answer to the formal challenge in which it requested that the FERC deny the formal challenge as a matter of law, or else hold the proceeding in abeyance pending the resolution of related dockets.

System Energy Formula Rate Annual Protocols Formal Challenge Concerning 2021 Calendar Year Bills

In March 2023, pursuant to the protocols procedures discussed above, the LPSC, the APSC, and the City Council filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2021. The formal challenge alleges: (1) that it was imprudent for System Energy to accept the IRS’s partial acceptance of a previously uncertain tax position; (2) that System Energy used incorrect inputs for retained earnings that are used to determine the capital structure; (3) that the equity ratio charged in rates was excessive; and (4) that all issues in the ongoing Unit Power Sales Agreement complaint proceeding should also be reflected in calendar year 2021 bills. The first, third, and fourth allegations are identical to issues that were raised in the formal challenge to the calendar year 2020 bills. The formal challenge to the calendar year 2021 bills states that the impact of the first allegation is “tens of millions of dollars,” but it does not provide an estimate of the financial impact of the remaining allegations.

In May 2023, System Energy filed an answer to the formal challenge in which it requested that the FERC deny the formal challenge as a matter of law, or else hold the proceeding in abeyance pending the resolution of related dockets.

Depreciation Amendment Proceeding

In December 2021, System Energy submitted to the FERC proposed amendments to the Unit Power Sales Agreement to adopt updated rates for use in calculating Grand Gulf plant depreciation and amortization expenses. The proposed amendments would result in higher charges to the Utility operating companies that buy capacity and energy from System Energy under the Unit Power Sales Agreement. In February 2022 the FERC accepted System Energy’s proposed increased depreciation rates with an effective date of March 1, 2022, subject to refund pending the outcome of the settlement and/or hearing procedures. In June 2023 System Energy filed with the FERC an unopposed offer of settlement that it had negotiated with intervenors to the proceeding. In August 2023 the FERC approved the settlement, which resolves the proceeding. In third quarter 2023, System Energy recorded a reduction in depreciation expense of $41 million representing the cumulative difference in depreciation expense resulting from the depreciation rates used from March 2022 through June 2023 and the depreciation rates included in the settlement filing approved by the FERC. In October 2023, System Energy filed a refund report with the FERC. The refund provided for in the refund report was included in the September 2023 service month bills under the Unit Power Sales Agreement. No comments or protests to the refund report were filed.

Pension Costs Amendment Proceeding

In October 2021, System Energy submitted to the FERC proposed amendments to the Unit Power Sales Agreement to include in rate base the prepaid and accrued pension costs associated with System Energy’s qualified pension plans. Based on data ending in 2020, the increased annual revenue requirement associated with the filing is approximately $8.9 million. In March 2022 the FERC accepted System Energy’s proposed amendments with an effective date of December 1, 2021, subject to refund pending the outcome of the settlement and/or hearing procedures. In August 2023 the FERC chief ALJ terminated settlement procedures and designated a presiding ALJ to oversee hearing procedures. In October 2023, System Energy filed direct testimony in support of its proposed amendments. Under the procedural schedule, testimony will be filed through April 2024, and the hearing is scheduled to begin in May 2024. The presiding ALJ’s initial decision is expected to be due in September 2024.

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Management’s Financial Discussion and Analysis

Nuclear Matters

System Energy owns and, through an affiliate, operates the Grand Gulf nuclear generating plant and is, therefore, subject to the risks related to such ownership and operation. These include risks related to: the use, storage, and handling and disposal of high-level and low-level radioactive materials; the substantial financial requirements, both for capital investments and operational needs, including the financial requirements to address emerging issues related to equipment reliability, to position Grand Gulf to meet its operational goals; the performance and capacity factors of Grand Gulf; the risk of an adverse outcome to a challenge to the prudence of operations at Grand Gulf; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license amendments, and decommissioning; the availability of interim or permanent sites for the disposal of spent nuclear fuel and nuclear waste, including the fees charged for such disposal; the sufficiency of nuclear decommissioning trust fund assets and earnings to complete decommissioning of the site when required; and limitations on the amounts of insurance recoveries for losses in connection with nuclear plant operations and catastrophic events such as a nuclear accident. In the event of an unanticipated early shutdown of Grand Gulf, System Energy may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. Grand Gulf’s operating license expires in 2044.

Environmental Risks

System Energy’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that System Energy is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Critical Accounting Estimates

The preparation of System Energy’s financial statements in conformity with GAAP requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in these assumptions and measurements could produce estimates that would have a material effect on the presentation of System Energy’s financial position, results of operations, or cash flows.

Nuclear Decommissioning Costs

See “Nuclear Decommissioning Costs” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.

Utility Regulatory Accounting

See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.

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Taxation and Uncertain Tax Positions

See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.

Qualified Pension and Other Postretirement Benefits

System Energy’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are affected by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.

Cost Sensitivity

The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).

Actuarial AssumptionChange in AssumptionImpact on 2024 Qualified Pension CostImpact on 2023 Qualified Projected Benefit Obligation

Increase/(Decrease)

Discount rate(0.25%)$235$6,886

Rate of return on plan assets(0.25%)$659$—

Rate of increase in compensation0.25%$247$1,227

The following chart reflects the sensitivity of postretirement benefits cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).

Actuarial AssumptionChange in AssumptionImpact on 2024 Postretirement Benefits CostImpact on 2023 Accumulated Postretirement Benefit Obligation

Increase/(Decrease)

Discount rate(0.25%)($5)$909

Health care cost trend0.25%$56$663

Each fluctuation above assumes that the other components of the calculation are held constant.

Costs and Employer Contributions

Total qualified pension cost for System Energy in 2023 was $12.6 million, including $6.4 million in settlement costs. System Energy anticipates 2024 qualified pension cost to be $5.2 million. System Energy contributed $15.5 million to its qualified pension plans in 2023 and estimates 2024 pension contributions will approximate $16.7 million, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024 valuations are completed, which is expected by April 1, 2024.

Total postretirement health care and life insurance benefit income for System Energy in 2023 was $348 thousand. System Energy expects 2024 postretirement health care and life insurance benefit income to approximate $913 thousand. System Energy contributed $480 thousand to its other postretirement plans in 2023 and expects 2024 contributions to approximate $34 thousand.

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Other Contingencies

See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.

New Accounting Pronouncements

See the “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholder and Board of Directors of

System Energy Resources, Inc.

Opinion on the Financial Statements

We have audited the accompanying balance sheets of System Energy Resources, Inc. (the “Company”) as of December 31, 2023 and 2022, the related statements of operations, cash flows, and changes in common equity (pages 467 through 472 and applicable items in pages 47 through 238), for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that is material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing separate opinion on the critical audit matters or on the accounts or disclosures to which they relate.

Rate and Regulatory Matters — System Energy Resources, Inc. — Refer to Note 2 to the financial statements

Critical Audit Matter Description

The Company is subject to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.

The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the FERC sets the rates the Company is allowed to charge customers based on allowable costs, including a reasonable

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return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.

We identified the impact of rate regulation as a critical audit matter due to the judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the (1) likelihood of recovery in future rates of incurred costs and the (2) likelihood of refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the FERC, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities involved specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and auditor judgment to evaluate management estimates and the subjectivity of audit evidence.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertainty of future decisions by the FERC, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities included the following, among others:

•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

•We read relevant regulatory orders issued by the FERC for the Company to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the FERC’s treatment of similar costs under similar circumstances. We evaluated external information and compared to management’s recorded regulatory asset and liability balances for completeness.

•For regulatory matters in process, we inspected the Company’s and intervenors’ filings with the FERC, initial Administrative Law Judge decisions and FERC orders issued, and settlement offers and agreements with the FERC for any evidence that might contradict management’s assertions.

•We obtained an analysis from management and support from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.

•We obtained representation from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management’s assertion that amounts are probable of recovery, refund, or a future reduction in rates.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 23, 2024

We have served as the Company’s auditor since 2001.

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SYSTEM ENERGY RESOURCES, INC.

STATEMENTS OF OPERATIONS

For the Years Ended December 31,

202320222021

(In Thousands)

OPERATING REVENUES

Electric$586,603 $658,812 $570,848

OPERATING EXPENSES

Operation and Maintenance:

Fuel, fuel-related expenses, and gas purchased for resale71,762 50,216 58,313

Nuclear refueling outage expenses26,745 24,482 27,244

Other operation and maintenance207,765 226,557 214,322

Decommissioning41,773 40,235 38,693

Taxes other than income taxes29,224 29,428 27,842

Depreciation and amortization90,858 111,889 105,978

Other regulatory charges (credits) - net(57,429)503,162 26,214

TOTAL410,698 985,969 498,606

OPERATING INCOME (LOSS)175,905 (327,157)72,242

OTHER INCOME (DEDUCTIONS)

Allowance for equity funds used during construction7,531 8,312 6,188

Interest and investment income13,131 5,096 82,744

Miscellaneous - net(9,101)(19,616)(18,991)

TOTAL11,561 (6,208)69,941

INTEREST EXPENSE

Interest expense48,416 37,381 38,393

Allowance for borrowed funds used during construction(1,754)(1,325)(1,047)

TOTAL46,662 36,056 37,346

INCOME (LOSS) BEFORE INCOME TAXES140,804 (369,421)104,837

Income taxes32,032 (92,828)(1,977)

NET INCOME (LOSS)$108,772 ($276,593)$106,814

See Notes to Financial Statements.

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SYSTEM ENERGY RESOURCES, INC.

STATEMENTS OF CASH FLOWS

For the Years Ended December 31,

202320222021

(In Thousands)

OPERATING ACTIVITIES

Net income (loss)$108,772 ($276,593)$106,814

Adjustments to reconcile net income (loss) to net cash flow provided by operating activities:

Depreciation, amortization, and decommissioning, including nuclear fuel amortization195,045 194,411 198,067

Deferred income taxes, investment tax credits, and non-current taxes accrued32,982 (85,720)11,191

Changes in assets and liabilities:

Receivables8,359 (19,530)6,054

Accounts payable78,655 (11,948)23,973

Taxes accrued19,804 (25,321)(50,059)

Interest accrued1,363 (123)(1,008)

Other working capital accounts20,749 (38,764)25,096

Other regulatory assets(31,239)(19,575)143,417

Other regulatory liabilities11,009 21,252 40,884

Pension and other postretirement liabilities(21,259)(35,354)(49,308)

Other assets and liabilities(150,668)304,545 (253,910)

Net cash flow provided by operating activities273,572 7,280 201,211

INVESTING ACTIVITIES

Construction expenditures(121,075)(164,797)(100,474)

Allowance for equity funds used during construction7,531 8,312 6,188

Nuclear fuel purchases(80,663)(96,659)(45,180)

Proceeds from sale of nuclear fuel46,242 18,855 21,724

Decrease (increase) in other investments(3)300 (300)

Proceeds from nuclear decommissioning trust fund sales390,004 346,504 1,022,170

Investment in nuclear decommissioning trust funds(412,823)(357,463)(1,025,779)

Changes in money pool receivable - net94,981 (19,236)(71,741)

Net cash flow used in investing activities(75,806)(264,184)(193,392)

FINANCING ACTIVITIES

Proceeds from the issuance of long-term debt715,545 1,022,472 662,423

Retirement of long-term debt(758,437)(986,829)(727,510)

Capital contribution from parent— 135,000 —

Change in money pool payable - net12,246 — —

Common stock dividends and distributions paid(170,000)— (96,000)

Net cash flow provided by (used in) financing activities(200,646)170,643 (161,087)

Net decrease in cash and cash equivalents(2,880)(86,261)(153,268)

Cash and cash equivalents at beginning of period2,940 89,201 242,469

Cash and cash equivalents at end of period$60 $2,940 $89,201

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:

Cash paid (received) during the period for:

Interest - net of amount capitalized$45,196 $39,848 $39,340

Income taxes($19,810)$18,413 $54,959

Noncash investing activities:

Accrued construction expenditures$25,301 $28,960 $23,388

See Notes to Financial Statements.

469

SYSTEM ENERGY RESOURCES, INC.

BALANCE SHEETS

ASSETS

December 31,

20232022

(In Thousands)

CURRENT ASSETS

Cash and cash equivalents:

Cash$60 $78

Temporary cash investments— 2,862

Total cash and cash equivalents60 2,940

Accounts receivable:

Associated companies54,544 158,601

Other6,861 6,145

Total accounts receivable61,405 164,746

Materials and supplies - at average cost155,565 135,346

Deferred nuclear refueling outage costs8,603 33,377

Prepayments and other3,373 9,097

TOTAL229,006 345,506

OTHER PROPERTY AND INVESTMENTS

Decommissioning trust funds1,342,317 1,142,914

TOTAL1,342,317 1,142,914

UTILITY PLANT

Electric5,495,728 5,425,449

Construction work in progress130,866 102,987

Nuclear fuel160,655 193,004

TOTAL UTILITY PLANT5,787,249 5,721,440

Less - accumulated depreciation and amortization3,493,299 3,412,257

UTILITY PLANT - NET2,293,950 2,309,183

DEFERRED DEBITS AND OTHER ASSETS

Regulatory assets:

Other regulatory assets446,360 415,121

Other730 1,422

TOTAL447,090 416,543

TOTAL ASSETS$4,312,363 $4,214,146

See Notes to Financial Statements.

470

SYSTEM ENERGY RESOURCES, INC.

BALANCE SHEETS

LIABILITIES AND EQUITY

December 31,

20232022

(In Thousands)

CURRENT LIABILITIES

Currently maturing long-term debt$57 $300,037

Accounts payable:

Associated companies118,523 21,701

Other73,580 58,178

Taxes accrued27,401 7,597

Interest accrued12,954 11,591

Sale-leaseback/depreciation regulatory liability— 103,497

Other4,354 4,071

TOTAL236,869 506,672

NON-CURRENT LIABILITIES

Accumulated deferred income taxes and taxes accrued405,744 376,070

Accumulated deferred investment tax credits46,960 44,692

Regulatory liability for income taxes - net107,458 110,840

Other regulatory liabilities782,912 665,024

Decommissioning1,084,234 1,042,461

Pension and other postretirement liabilities19,491 40,750

Long-term debt738,402 477,868

Other1,754 2

TOTAL3,186,955 2,757,707

Commitments and Contingencies

COMMON EQUITY

Common stock, no par value, authorized 1,000,000 shares; issued and outstanding 789,350 shares in 2023 and 2022

916,850 1,086,850

Accumulated deficit(28,311)(137,083)

TOTAL888,539 949,767

TOTAL LIABILITIES AND EQUITY$4,312,363 $4,214,146

See Notes to Financial Statements.

471

SYSTEM ENERGY RESOURCES, INC.

STATEMENTS OF CHANGES IN COMMON EQUITY

For the Years Ended December 31, 2023, 2022, and 2021

Common StockRetained Earnings (Accumulated Deficit)Total

(In Thousands)

Balance at December 31, 2020$951,850 $128,696 $1,080,546

Net income— 106,814 106,814

Common stock dividends and distributions— (96,000)(96,000)

Balance at December 31, 2021$951,850 $139,510 $1,091,360

Net loss— (276,593)(276,593)

Capital contribution from parent135,000 — 135,000

Balance at December 31, 2022$1,086,850 ($137,083)$949,767

Net income — 108,772 108,772

Common stock dividends and distributions(170,000)— (170,000)

Balance at December 31, 2023$916,850 ($28,311)$888,539

See Notes to Financial Statements.

472

Item 2. Properties

Information regarding the registrant’s properties is included in Part I, Item 1. - Entergy’s Business under the sections titled “Utility - Property and Other Generation Resources” and “Other Business Activities - Property” in this report.