ENTERGY NEW ORLEANS LLC

Federal Power Act

The Federal Power Act provides the FERC the authority to regulate:

•the transmission and wholesale sale of electric energy in interstate commerce;

•the reliability of the high voltage interstate transmission system through reliability standards;

•sale or acquisition of certain assets;

•securities issuances;

•the licensing of certain hydroelectric projects;

•certain other activities, including accounting policies and practices of electric and gas utilities; and

•changes in control of FERC jurisdictional entities or rate schedules.

The Federal Power Act gives the FERC jurisdiction over the rates charged by System Energy for Grand Gulf capacity and energy provided to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. The FERC also has jurisdiction over the rates charged by Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas to unaffiliated wholesale customers. In addition, the FERC also regulates wholesale power sales between the Utility operating companies. Moreover, the FERC regulates the MISO RTO, an independent entity that maintains functional control over the combined transmission systems of its members and administers wholesale energy, capacity, and ancillary services markets for market participants in the MISO region, including the Utility operating companies. FERC regulation of the MISO RTO includes regulation of the design and implementation of the wholesale markets administered by the MISO RTO, as well as the rates, terms, and conditions of open access transmission service over the member systems and the allocation of costs associated with transmission upgrades.

Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 65 MW of capacity.

State Regulation

Utility

Entergy Arkansas is subject to regulation by the APSC as to the following:

•utility service areas;

•fuel cost recovery, including audits of the energy cost recovery rider;

•the acquisition, sale, or lease of any public utility plant or property constituting an operating unit or system;

•certificates of convenience and necessity and certificates of environmental compatibility and public need, as applicable, for generating and transmission facilities;

•net energy metering;

•utility mergers and acquisitions and other changes of control; and

•the issuance and sale of certain securities.

Additionally, Entergy Arkansas serves a limited number of retail customers in Tennessee. Pursuant to legislation enacted in Tennessee, Entergy Arkansas is subject to complaints before the Tennessee Regulatory Authority only if it fails to treat its retail customers in Tennessee in the same manner as its retail customers in Arkansas. Additionally, Entergy Arkansas maintains limited facilities in Missouri but does not provide retail electric service to customers in Missouri. Although Entergy Arkansas obtained a certificate with respect to its Missouri facilities, Entergy Arkansas is not subject to retail ratemaking jurisdiction in Missouri.

Entergy Louisiana’s electric and gas business is subject to regulation by the LPSC as to the following:

•fuel cost recovery, including audits of the fuel adjustment clause, environmental adjustment charge, and purchased gas adjustment charge;

•certification of certain transmission projects;

•certification of capacity acquisitions, both for owned capacity and for purchase power contracts that exceed either 5 MW or one year in term;

•procurement process to acquire capacity at or above 50 MW;

•audits of the energy efficiency rider;

•avoided cost payment to non-exempt Qualifying Facilities;

•utility mergers and acquisitions and other changes of control.

Entergy Mississippi is subject to regulation by the MPSC as to the following:

•utility service areas;

•fuel cost recovery, including audits of the energy cost recovery mechanism;

•certification of generating facilities, certain transmission projects, and certain distribution projects with construction costs greater than $10 million;

•utility mergers, acquisitions, and other changes of control.

Entergy Mississippi is also subject to regulation by the APSC as to the certificate of environmental compatibility and public need for the Independence Station, which is located in Arkansas.

Entergy New Orleans is subject to regulation by the City Council as to the following:

•fuel cost recovery, including audits of the fuel adjustment charge and purchased gas adjustment charge;

•audit of the environmental adjustment charge;

•certification of the construction or extension of any new plant, equipment, property, or facility that comprises more than 2% of the utility’s rate base;

•net energy metering;

•issuance and sale of certain securities; and

•utility mergers and acquisitions and other changes of control.

To the extent authorized by governing legislation, Entergy Texas is subject to the original jurisdiction of the municipal authorities of a number of incorporated cities in Texas with appellate jurisdiction over such matters residing in the PUCT. Entergy Texas is also subject to regulation by the PUCT as to the following:

•retail rates and charges, including depreciation rates, and terms and conditions of service in unincorporated areas of its service territory, and in municipalities that have ceded jurisdiction to the PUCT;

•fuel recovery, including reconciliations (audits) of the fuel adjustment charges;

•certification of certain transmission and generation projects;

•utility service areas, including extensions into new areas;

•utility mergers, sales/acquisitions/leases of plants over $10 million, sales of greater than 50% voting stock of utilities, and transfers of controlling interest in or operation of utilities.

Regulation of the Nuclear Power Industry

Atomic Energy Act of 1954 and Energy Reorganization Act of 1974

Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose civil penalties or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, Entergy Louisiana, and System Energy, as owners of all or portions of ANO, River Bend and Waterford 3, and Grand Gulf, respectively, and Entergy Operations, as the licensee and operator of these units, are subject to the jurisdiction of the NRC.

Nuclear Waste Policy Act of 1982

Spent Nuclear Fuel

Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors. Entergy’s nuclear owner/licensee subsidiaries have been charged fees for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. The affected Entergy companies entered into contracts with the DOE, whereby the DOE is to furnish disposal services at a cost of one mill per net kWh generated and sold after April 7, 1983, plus a one-time fee for generation prior to that date. Entergy Arkansas is the only one of the Utility operating companies that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 2024 of $216 million for the one-time fee. The fees payable to the DOE may be adjusted in the future to assure full recovery. Entergy considers all costs incurred for the disposal of spent nuclear fuel, except accrued interest, to be proper components of nuclear fuel expense. Provisions to recover such costs have been or will be made in applications to regulatory authorities for the Utility plants. Entergy’s total spent fuel fees to date, including the one-time fee liability of Entergy Arkansas, have surpassed $1.7 billion (exclusive of amounts relating to Entergy plants that were paid or are owed by prior owners of those plants).

The permanent spent fuel repository in the U.S. has been legislated to be Yucca Mountain, Nevada. The DOE is required by law to proceed with the licensing of the Yucca Mountain repository (the DOE filed the license application in June 2008) and, after the license is granted by the NRC, proceed with the repository construction and commencement of receipt of spent fuel. Because the DOE has not begun accepting spent fuel, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and is in partial breach of its spent fuel disposal contracts. The DOE continues to delay meeting its obligation. Specific steps were taken to discontinue the Yucca Mountain project, including a motion to the NRC to withdraw the license application with prejudice and the establishment of a commission to develop recommendations for alternative spent fuel storage solutions. In August 2013 the U.S. Court of Appeals for the D.C. Circuit ordered the NRC to continue with the Yucca Mountain license review, but only to the extent of funds previously appropriated by Congress for that purpose and not yet used. Although the NRC completed the safety evaluation report for the license review in 2015, the previously appropriated funds are not sufficient to complete the review, including required hearings. The government has taken no effective action to date related to the recommendations of the appointed spent fuel study commission. Accordingly, large uncertainty remains regarding the time frame under which the DOE will begin to accept spent fuel from Entergy’s facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at Entergy’s nuclear sites.

Following the defunding of the Yucca Mountain spent fuel repository program, the National Association of Regulatory Utility Commissioners and others sued the government seeking cessation of collection of the one mill per net kWh generated and sold after April 7, 1983 fee. In November 2013 the D.C. Circuit ordered the DOE to submit a proposal to Congress to reset the fee to zero until the DOE complies with the Nuclear Waste Policy Act or

Congress enacts an alternative waste disposal plan. In January 2014 the DOE submitted the proposal to Congress under protest, and also filed a petition for rehearing with the D.C. Circuit. The petition for rehearing was denied. The zero spent fuel fee went into effect prospectively in May 2014.

As a result of the DOE’s failure to begin disposal of spent nuclear fuel in 1998 pursuant to the Nuclear Waste Policy Act of 1982 and the spent fuel disposal contracts, Entergy’s nuclear owner/licensee subsidiaries have incurred and will continue to incur damages. These subsidiaries have been, and continue to be, involved in litigation to recover the damages caused by the DOE’s delay in performance. See Note 8 to the financial statements for discussion of final judgments recorded by Entergy in 2022, 2023, and 2024 related to Entergy’s nuclear owner/licensee subsidiaries’ litigation with the DOE. Through 2024, Entergy’s subsidiaries have won and collected on judgments against the government totaling approximately $1.2 billion.

Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are providing their own spent fuel storage. Storage capability additions using dry casks began operations at ANO in 1996, at River Bend in 2005, at Grand Gulf in 2006, and at Waterford 3 in 2011. These facilities will be expanded as needed.

Nuclear Plant Decommissioning

Entergy Arkansas, Entergy Louisiana, and System Energy are entitled to recover from customers through electric rates the estimated decommissioning costs for ANO, Waterford 3, and Grand Gulf, respectively. In addition, Entergy Louisiana and Entergy Texas are entitled to recover from customers through electric rates the estimated decommissioning costs for the portion of River Bend subject to retail rate regulation. The collections are deposited in trust funds that can only be used in accordance with NRC and other applicable regulatory requirements. Entergy periodically reviews and updates the estimated decommissioning costs to reflect inflation and changes in regulatory requirements and technology, and then makes applications to the regulatory authorities to reflect, in rates, the changes in projected decommissioning costs.

In December 2018 the APSC ordered collections in rates for decommissioning ANO 2 and found that ANO 1’s decommissioning was adequately funded without additional collections. In November 2021, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that both ANO 1 and 2 decommissioning trusts were adequately funded without further collections, and in December 2021 the APSC ordered zero collections for ANO 1 and 2 decommissioning. In November 2022, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that ANO 1’s decommissioning trust was adequately funded, but that ANO 2’s fund had a projected shortage as a result of a decline in decommissioning trust fund investment values over the past year. The filing proposed a reinstatement of decommissioning cost recovery for ANO 2. In December 2022 the APSC ordered reinstatement of decommissioning collections for ANO 2 in accordance with the request in the November 2022 filing. In November 2023, Entergy Arkansas filed a further revised decommissioning cost recovery tariff for ANO indicating that ANO 1’s decommissioning trust continued to be adequately funded, but that ANO 2’s fund continued to require collections higher than those in effect. In December 2023 the APSC approved the proposed higher decommissioning collections for ANO 2. In October 2024, Entergy Arkansas filed a revised cost recovery tariff indicating the decommissioning trusts for both ANO 1 and 2 were adequately funded and proposing suspension of decommissioning collections for both ANO 1 and 2. In December 2024 the APSC approved suspension of decommissioning collections for both ANO 1 and 2.

In July 2010 the LPSC approved increased decommissioning collections for Waterford 3 and the Louisiana regulated share of River Bend to address previously identified funding shortfalls. This LPSC decision contemplated that the level of decommissioning collections could be revisited should the NRC grant license extensions for both Waterford 3 and River Bend. In July 2021, Entergy Louisiana made a filing with the LPSC to adjust Waterford 3 and River Bend decommissioning collections based on the latest site-specific decommissioning cost estimates for those plants. The filing sought to increase Waterford 3 decommissioning collections and decrease River Bend decommissioning collections. In August 2023, Entergy Louisiana made another filing with the LPSC requesting to maintain the same total decommissioning funding collections as currently in effect for both Waterford 3 and River

Bend combined, but also requesting to reallocate that same amount of funding by increasing the contributions for Waterford 3 and reducing the contributions for River Bend. In August 2024 the LPSC approved a stipulation settling the case involving Waterford 3 and River Bend decommissioning. The stipulation, among other things, increased Waterford 3 decommissioning collections and decreased River Bend decommissioning collections, as requested.

In December 2010 the PUCT approved increased decommissioning collections for the Texas share of River Bend to address previously identified funding shortfalls. In December 2018 the PUCT approved a settlement that eliminated River Bend decommissioning collections for the Texas jurisdictional share of the plant based on a determination by Entergy Texas that the existing decommissioning fund was adequate following license renewal. In July 2022, Entergy Texas filed a base rate case that proposed continuation of the cessation of River Bend decommissioning collections. In May 2023, Entergy Texas filed on behalf of the parties to the base rate case an unopposed settlement, which included an agreement to maintain Entergy Texas’s decommissioning funding for River Bend at a revenue requirement of $0. In August 2023 the PUCT issued an order accepting the unopposed settlement, including the proposed decommissioning funding settlement terms.

In December 2016 the NRC issued a 20-year operating license renewal for Grand Gulf. In a 2017 filing at the FERC, System Energy stated that with the renewed operating license, Grand Gulf’s decommissioning trust was sufficiently funded, and proposed, among other things, to cease decommissioning collections for Grand Gulf effective October 1, 2017. The FERC accepted a settlement including the proposed decommissioning revenue requirement by letter order in August 2018.

Entergy currently believes its decommissioning funding will be sufficient for its nuclear plants subject to retail rate regulation, although decommissioning cost inflation and trust fund performance will ultimately determine the adequacy of the funding amounts.

Plant owners are required to provide the NRC with a biennial report (annually for units that have shut down or will shut down within five years), based on values as of December 31, addressing the owners’ ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, plant owners may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. In March 2023 filings with the NRC were made reporting on decommissioning funding for all of Entergy’s subsidiaries’ nuclear plants. Those reports showed that decommissioning funding for each of the nuclear plants met the NRC’s financial assurance requirements.

Additional information with respect to Entergy’s decommissioning costs and decommissioning trust funds is found in Note 9 and Note 16 to the financial statements.

Price-Anderson Act

The Price-Anderson Act requires that reactor licensees purchase and maintain the maximum amount of nuclear liability insurance available and participate in an industry assessment program called Secondary Financial Protection in order to protect the public in the event of a nuclear power plant accident. The costs of this insurance are borne by the nuclear power industry. Congress passed legislation in 2024 extending the Price-Anderson Act for a term through 2065. The Price-Anderson Act limits the contingent liability for a single nuclear incident to a maximum assessment of approximately $165.9 million per reactor (with 95 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, Entergy Louisiana, or System Energy is liable, protection is afforded through a combination of insurance and the Secondary Financial Protection program. In addition to this, insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units is also purchased. The Price-Anderson Act and insurance applicable to the nuclear programs of Entergy are discussed in more detail in Note 8 to the financial statements.

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 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. All of the nuclear generating plants owned and operated by Entergy’s Utility business are currently in Column 1.

Environmental Regulation

Entergy’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’s businesses are in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted below. Because environmental regulations are subject to change, future compliance requirements and costs cannot be precisely estimated. Except to the extent discussed below, at this time compliance with federal, state, and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of Entergy’s businesses and is not expected to have a material effect on their competitive position, results of operations, cash flows, or financial position.

Clean Air Act and Subsequent Amendments

The Clean Air Act and its amendments establish several programs that currently or in the future may affect Entergy’s fossil-fueled generation facilities and, to a lesser extent, certain operations at nuclear and other facilities. Individual states also operate similar independent state programs or delegated federal programs that may include requirements more stringent than federal regulatory requirements. These programs include:

•new source review and preconstruction permits for new sources of criteria air pollutants, greenhouse gases, and significant modifications to existing facilities;

•acid rain program for control of sulfur dioxide (SO 2) and nitrogen oxides (NOx);

•nonattainment area programs for control of criteria air pollutants, which could include fee assessments for air pollutant emission sources under Section 185 of the Clean Air Act if attainment is not reached in a timely manner;

•hazardous air pollutant emissions reduction programs;

•interstate air transport;

•operating permit programs and enforcement of these and other Clean Air Act programs;

•regional haze programs; and

•new and existing source standards for greenhouse gas and other air emissions.

National Ambient Air Quality Standards

The Clean Air Act requires the EPA to set National Ambient Air Quality Standards (NAAQS) for ozone, carbon monoxide, lead, nitrogen dioxide, particulate matter, and sulfur dioxide and requires periodic review of those standards. When an area fails to meet an ambient standard, it is considered to be in nonattainment and is classified as “marginal,” “moderate,” “serious,” or “severe.” When an area fails to meet the ambient air standard, the EPA requires state regulatory authorities to prepare state implementation plans meant to cause progress toward bringing the area into attainment with applicable standards.

Ozone Nonattainment

Entergy Texas operates two fossil-fueled generating facilities (Lewis Creek and Montgomery County Power Station) in a geographic area that is not in attainment with the applicable NAAQS for ozone. The ozone nonattainment area that affects Entergy Texas is the Houston-Galveston-Brazoria area. Both Lewis Creek and the Montgomery County Power Station hold all necessary permits for operation and comply with applicable air quality program regulations. Measures enacted to return the area to ozone attainment could make these program regulations more stringent. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and nonattainment with the ozone NAAQS.

Revised Fine Particulate (PM 2.5) NAAQS

In March 2024 the EPA issued a final rule which revised the primary annual NAAQS for fine particulate matter, also known as PM 2.5, from 12 ug/m 3 to 9 ug/m 3. This new standard was effective May 2024 and initial attainment/nonattainment designations for areas with available information are due within two years, by May 2026. For any areas designated as nonattainment for this revised standard, State Implementation Plans (SIPs) to address nonattainment requirements will be due within 18 months of the effective date of any initial nonattainment designations. Within the areas in which the Utility operating companies operate, regulatory agency air monitor data from 2021-2023 for Pulaski County and Union County, Arkansas, West Baton Rouge Parish, Louisiana, Harris County, Texas and Hinds County, Mississippi reflect annual average PM 2.5 concentrations in excess of this new standard and monitors for several other areas reflect concentrations between 8-9 ug/m 3. Initial attainment and nonattainment designations will be based on data from 2022-2024. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and nonattainment with this revised fine particulate NAAQS.

Hazardous Air Pollutants

The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011, which had a compliance date, with a widely granted one-year extension, of April 2016. The required controls have been installed and are operational at all affected Entergy units. In May 2024 the EPA issued a final rule revising portions of the MATS rule, including a reduction to the emission limit for filterable particulate matter. The revised standard will become effective July 2027 and could require additional capital investment and/or additional other operation and maintenance costs at Entergy’s coal-fired generating units. An additional one-year extension is possible for the installation of controls, if necessary. Entergy is currently evaluating its coal units to determine whether additional controls are necessary to comply with this new lower limit.

Good Neighbor Plan/Cross-State Air Pollution Rule

In March 2005 the EPA finalized the Clean Air Interstate Rule (CAIR), which was intended to reduce SO 2 and NOx emissions from electric generation plants in order to improve air quality in twenty-nine eastern states. The rule required a combination of capital investment to install pollution control equipment and increased operating costs through the purchase of emission allowances. Entergy began implementation in 2007, including installation of controls at several facilities and the development of an emission allowance procurement strategy. Based on several court challenges, CAIR and its subsequent versions, now known as the Cross-State Air Pollution Rule (CSAPR), have been remanded to and modified by the EPA on multiple occasions.

In June 2023 the EPA published its final Federal Implementation Plan (FIP), known as the Good Neighbor Plan, to address interstate transport for the 2015 ozone NAAQS which would increase the stringency of the CSAPR program in all four of the states where the Utility operating companies operate. The FIP would significantly reduce ozone season NOx emission allowance budgets and allocations for electric generating units. Prior to issuance of the FIP, in February 2023 the EPA issued related SIP disapprovals for many states, including the four states in which the Utility operating companies operate, and these SIP disapprovals are the subject of many legal challenges, including a petition for review filed by Entergy Louisiana challenging the disapproval of Louisiana’s SIP. Stays of the SIP disapprovals have been granted in all four states in which the Utility operating companies operate, and the FIP will not go into effect while the stays are in place. Decisions on the merits regarding the respective SIP disapprovals are expected in 2025. The FIP is also subject to numerous legal challenges in various federal circuit courts of appeals, and in June 2024 the U.S. Supreme Court issued an order, in challenges filed in the D.C. Circuit, staying enforcement of the FIP pending the D.C. Circuit’s review of the rule. Entergy is monitoring this litigation and assessing its compliance options in the event that the FIP becomes effective.

Regional Haze

In June 2005 the EPA issued its final Clean Air Visibility Rule (CAVR) regulations that potentially could result in a requirement to install SO 2 and NOx pollution control technology as Best Available Retrofit Control Technology to continue operating certain of Entergy’s fossil generation units. The rule leaves certain CAVR determinations to the states. This rule establishes a series of 10-year planning periods, with states required to develop SIPs for each planning period, with each SIP including such air pollution control measures as may be necessary to achieve the ultimate goal of the CAVR by the year 2064. The various states are currently in the process of developing SIPs to implement the second planning period of the CAVR, which addresses the 2018-2028 planning period.

The second planning period (2018-2028) for the regional haze program requires states to examine sources for impacts on visibility and to prepare SIPs by July 31, 2021 to ensure reasonable progress is being made to attain visibility improvements. Entergy received information collection requests from the Arkansas and Louisiana Departments of Environmental Quality requesting an evaluation of technical and economic feasibility of various NOx and SO 2 control technologies for Independence, Nelson 6, NISCO, and Ninemile. Responses to the information collection requests were submitted to the respective state agencies. Louisiana issued its draft SIP which did not propose any additional air emissions controls for the affected Entergy units in Louisiana. Some public commenters, however, believe additional air controls are cost-effective. In August 2024, Louisiana issued a revised SIP proposal for public comment. The revised proposed SIP would not require any additional pollution control installations on any Entergy-owned units in Louisiana. Comments on the revised SIP were due in September 2024 and the Louisiana Department of Environmental Quality (LDEQ) is currently reviewing comments received on the revised proposal. The agency, like many other state agencies, did not meet the July 31, 2021 deadline to submit a SIP to the EPA for review.

Similar to the LDEQ, the Arkansas Department of Energy and Environment, Division of Environmental Quality (ADEQ) did not meet the July 31, 2021 SIP submission deadline, but subsequently submitted a final SIP to the EPA for review. The ADEQ reviewed Entergy’s Independence plant but determined that additional air emission controls would not be cost-effective considering the facility’s commitment to cease coal-fired combustion by December 31, 2030.

The Texas Commission on Environmental Quality has completed its second-planning period SIP and submitted it to the EPA for review. There were no Entergy sources selected for additional emission controls. In June 2024, the EPA entered into a consent decree that sets deadlines for the EPA to take final action on 34 states’ SIP submittals. This includes Arkansas and Texas, which are due August 2026 and May 2025, respectively.

The Mississippi Department of Environmental Quality also did not meet the July 31, 2021 SIP submission deadline. In June 2023 Mississippi issued its proposed SIP for public notice and comment but did not propose additional pollution controls for Entergy sources.

In August 2022 the EPA issued findings of failure to submit regional haze SIPs to 15 states, including Louisiana and Mississippi. These findings were effective September 2022, which started the two-year period for the EPA to either approve a SIP submitted by the state or issue a final federal plan. That two-year period expired in September 2024, but EPA has not yet proposed a FIP for Louisiana or Mississippi.

Greenhouse Gas Emissions

In May 2024 the EPA finalized rules regulating greenhouse gas emissions from new combustion turbine electric generating units (EGUs) under Section 111(b) of the Clean Air Act and from certain existing coal- and gas-fired EGUs under Section 111(d) of the Clean Air Act.

For new gas combustion turbine EGUs, the final rule includes three subcategories of emission standards based on the unit’s annual capacity factor. Applicable emission standards for each subcategory are: a heat-input based CO 2 emission standard for low load (<20% annual capacity factor) EGUs; an output-based CO 2 efficiency standard for intermediate load (>20% but <40% annual capacity factor) EGUs; and, for base load (>40% annual capacity factor) EGUs, a Phase 1 output-based CO 2 efficiency standard followed by a more stringent Phase 2 CO 2 standard which will apply beginning January 1, 2032. The Phase 2 standard was established based on an EPA determination that carbon capture and sequestration represents the best system of emission reduction for new base load combustion turbine EGUs. The final rule allows for a possible one-year extension to the compliance date for the Phase 2 standard in circumstances where a source faces a delay in installation of controls due to factors outside of the control of the EGU owner/operator.

For existing generating units, the final rule includes emission guidelines issued under Section 111(d) of the Clean Air Act and allows states two years to develop a plan to implement the new emission guidelines with respect to subject emission units within their state. The final emission guidelines require reductions in CO 2 emissions from existing coal-fired generating units which plan to operate beyond January 1, 2032 and exempts coal-fired units which plan to permanently cease operations prior to this date. Due to Entergy’s commitment to cease burning coal by the end of 2030, Entergy’s coal-fired generating units are expected to be exempt from this aspect of the final rule. The emission guidelines also include CO 2 efficiency standards for existing gas-fired steam EGUs. These emission standards will apply beginning January 1, 2030. Entergy’s existing gas-fired steam generating units are expected to meet these CO 2 emission standards. The EPA did not finalize emission guidelines for existing gas turbine EGUs and has announced plans to conduct a subsequent rulemaking for such units. Numerous lawsuits were filed in the D.C. Circuit challenging the final rule, and oral argument was held in December 2024. Entergy continues to monitor the status of the litigation.

Entergy continues to support national legislation that would most efficiently reduce economy-wide greenhouse gas emissions and increase planning certainty for electric utilities. By virtue of its proportionally large investment in low-emitting generation technologies, Entergy has a low overall carbon dioxide emission “intensity,” or rate of carbon dioxide emitted per megawatt-hour of electricity generated. In anticipation of the imposition of carbon dioxide emission limits on the electric industry, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included a formal program to stabilize owned power plant carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in reducing emissions below 2000 levels. In 2006, Entergy started including emissions from controllable power purchases in addition to its ownership share of generation and established a second formal voluntary program to stabilize power plant carbon dioxide emissions and emissions from controllable power purchases, cumulatively over the period, at 20% below 2000 levels through 2010. In 2011, Entergy extended this commitment through 2020, which it ultimately outperformed by approximately 8% both cumulatively and on an annual basis. In 2019, in connection with a climate scenario analysis following the recommendations of the Task Force on Climate-related Financial Disclosures describing climate-related governance, strategy, risk management, and metrics and targets, Entergy announced a 2030 carbon dioxide emission rate goal focused on a 50% reduction from Entergy’s base year - 2000.

In September 2020, Entergy announced a commitment to achieve net-zero greenhouse gas emissions by 2050 inclusive of all businesses, all applicable gases, and all emission scopes. In 2022, Entergy enhanced its commitment to include an interim goal of 50% carbon-free energy generating capacity by 2030 and expanded its interim emission rate goal to include all purchased power. Due to stronger than initially expected sales growth, likely necessitating the development of new generation capacity that is not carbon-free, Entergy expects that achievement of the 50% carbon-free energy generating capacity goal will be delayed for a period beyond 2030 that has not yet been determined. In addition, while current planning assumptions indicate the 2030 emission rate goal remains achievable, its achievement could also be challenged as a result of the forecasted and future sales growth. See “Risk Factors” in Part I, Item 1A for discussion of the risks associated with achieving these climate goals. Entergy’s comprehensive, third party verified greenhouse gas inventory and progress against its voluntary goals are published on its website.

Potential Legislative, Regulatory, and Judicial Developments

In addition to the specific instances described above, there are a number of legislative and regulatory initiatives that are or have recently been under consideration at the federal, state, and local level. Because of the nature of Entergy’s business, the imposition of any of these initiatives could affect Entergy’s operations. Entergy continues to monitor these initiatives and activities in order to analyze their potential operational and cost implications. These initiatives have included:

•reconsideration and revision of ambient air quality standards downward which could lead to additional areas of nonattainment;

•designation by the EPA and state environmental agencies of areas that are not in attainment with national ambient air quality standards;

•introduction of bills in Congress and development of regulations by the EPA proposing further limits on SO 2, mercury, carbon dioxide, and other air emissions. New legislation or regulations applicable to stationary sources could take the form of market-based cap-and-trade programs, direct requirements for the installation of air emission controls onto air emission sources, or other or combined regulatory programs;

•efforts in Congress or at the EPA to establish a federal carbon dioxide emission tax, control structure, or unit performance standards;

•revisions to the estimates of the Social Cost of Carbon and its use for regulatory impact analysis of federal laws and regulations;

•implementation of the regional cap and trade programs to limit carbon dioxide and other greenhouse gases;

•efforts on the local, state, and federal level to codify renewable portfolio standards, clean energy standards, or a similar mechanism requiring utilities to produce or purchase a certain percentage of their power from defined renewable energy sources or energy sources with lower emissions;

•efforts to develop more stringent state water quality standards, effluent limitations for Entergy’s industry sector, stormwater runoff control regulations, and cooling water intake structure requirements;

•efforts to restrict the previously-approved continued use of oil-filled equipment containing certain levels of polychlorinated biphenyls (PCBs) and increased regulation of per- and polyfluorinated substances or other chemicals;

•efforts by certain external groups to encourage reporting and disclosure of environmental, social, and governance risk;

•the listing of additional species as threatened or endangered, the protection of critical habitat for these species, and developments in the legal protection of eagles and migratory birds;

•the regulation of the management, disposal, and beneficial reuse of coal combustion residuals; and

•the regulation of the management and disposal and recycling of equipment associated with renewable and clean energy sources such as used solar panels, wind turbine blades, hydrogen usage, or battery storage.

Comprehensive Environmental Response, Compensation, and Liability Act of 1980

The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), authorizes the EPA to mandate clean-up by, or to collect reimbursement of clean-up costs from, owners or operators of sites at which hazardous substances may be or have been released. Certain private parties also may use CERCLA to recover response costs. Parties that transported hazardous substances to these sites or arranged for the disposal of the substances are also deemed liable by CERCLA. CERCLA has been interpreted to impose strict, joint, and several liability on responsible parties. Many states have adopted programs similar to CERCLA. Entergy subsidiaries have sent waste materials to various disposal sites over the years, and releases have occurred at Entergy facilities including nuclear facilities that have been sold to decommissioning companies. In addition, environmental laws now regulate certain of Entergy’s operating procedures and maintenance practices that historically were not subject to regulation. Some disposal sites used by Entergy subsidiaries have been the subject of governmental action under CERCLA or similar state programs, resulting in site clean-up activities. Entergy subsidiaries have participated to various degrees in accordance with their respective potential liabilities in such site clean-ups and have developed experience with clean-up costs. The affected Entergy subsidiaries have established provisions for the liabilities for such environmental clean-up and restoration activities. Details of potentially material CERCLA and similar state program liabilities are discussed in the “Other Environmental Matters” section below.

Coal Combustion Residuals

In April 2015 the EPA published the final coal combustion residuals (CCR) rule (2015 CCR Rule) regulating CCRs destined for disposal in landfills or surface impoundments as non-hazardous wastes regulated under Resource Conservation and Recovery Act Subtitle D. The final regulations created new compliance requirements including modified storage, new notification and reporting practices, product disposal considerations, and CCR unit closure criteria but excluded CCRs that are beneficially reused in certain processes. Entergy believes that on-site disposal options will be available at its facilities, to the extent needed.

Pursuant to the 2015 CCR Rule, Entergy operates groundwater monitoring systems surrounding its CCR landfills located at White Bluff, Independence, and Nelson. Monitoring to date has detected concentrations of certain listed constituents in the area but has not indicated that these constituents originated at the active landfill cells. Reporting and detection monitoring will continue as the rule requires. In late-2017, Entergy determined that certain in-ground wastewater treatment system recycle ponds at its White Bluff and Independence facilities required management under the 2015 CCR Rule. Consequently, in order to move away from using the recycle ponds, White Bluff and Independence each installed a new permanent bottom ash handling system. As of November 2020, both sites are operating the new system and no longer are sending waste to the recycle ponds. Each site commenced closure of its two recycle ponds (four ponds total) prior to the April 11, 2021 deadline for unlined recycle ponds and the ponds were certified closed in October 2023.

In May 2024 the EPA finalized a rule (2024 CCR Rule) establishing management standards for legacy CCR surface impoundments (i.e., inactive surface impoundments at inactive power plants) and establishing a new class of units referred to as CCR management units (CCRMUs) (i.e., non-containerized CCR located at a regulated CCR facility). CCR utilized in roadbeds and embankments is excluded from the CCRMU definition. Entergy does not have any legacy impoundments; however, the definition of CCR management units includes on-site areas where CCR was beneficially used. This is contrary to the 2015 CCR Rule which exempted beneficial uses that met certain criteria. Under this expanded rule, all facilities must identify and delineate any CCRMU greater than one ton and submit a facility evaluation report by February 2026. Any potential requirements for corrective action or operational changes under the 2015 CCR Rule and the 2024 CCR Rule continue to be assessed. Notably, ongoing litigation has resulted in the EPA’s continuing review of the rules. Consequently, the nature and cost of additional corrective action requirements may depend, in part, on the outcome of the litigation and further EPA review. Given the complexity and recency of the EPA guidance, Entergy is still evaluating the level of work that will ultimately be required to comply with the 2024 CCR Rule. Based on initial estimates of multiple possible remediation scenarios, Entergy recorded in 2024 a $42 million increase in its decommissioning cost liabilities for White Bluff and

Independence, along with corresponding increases in the related asset retirement cost assets that will be depreciated over the remaining useful lives of the unit. Entergy will continue to update the asset retirement obligation as the requirements of the 2024 CCR Rule are clarified. As of December 31, 2024, Entergy has recorded asset retirement obligations related to CCR management of $73 million. Additionally, all three sites (White Bluff, Independence, and Nelson) are preparing to implement measures to meet the new and updated Effluent Limitation Guidelines discussed below.

Clean Water Act

The 1972 amendments to the Federal Water Pollution Control Act (known as the Clean Water Act) provide the statutory basis for the National Pollutant Discharge Elimination System permit program, section 402, and the basic structure for regulating the discharge of pollutants from point sources to waters of the United States. The Clean Water Act requires virtually all discharges of pollutants to waters of the United States to be permitted. Section 316(b) of the Clean Water Act regulates cooling water intake structures, section 401 of the Clean Water Act requires a water quality certification from the state in support of certain federal actions and approvals, and section 404 of the Clean Water Act regulates the dredge and fill of waters of the United States, including jurisdictional wetlands.

Federal Jurisdiction of Waters of the United States

In June 2020 the EPA’s revised definition of waters of the United States in the Navigable Waters Protection Rule (NWPR) became effective, narrowing the scope of Clean Water Act jurisdiction, as compared to a 2015 definition which had been stayed by several federal courts. In August 2021 a federal district court vacated and remanded the NWPR for further consideration. The EPA and the U.S. Army Corps of Engineers (Corps) subsequently issued a statement that the agencies would revert to pre-2015 regulations pending a new rulemaking. In December 2022 the EPA and the Corps released a final definition of waters of the United States (the 2022 Rule) that replaces the NWPR with a definition that is consistent with the pre-2015 regulatory regime as interpreted by several United States Supreme Court decisions. The 2022 Rule was subject to multiple legal challenges and was enjoined from implementation or enforcement throughout Entergy’s utility service territory. In May 2023 the U.S. Supreme Court issued a decision limiting the scope of federal jurisdiction over wetlands, and in September 2023 the EPA and the Corps issued a final rule incorporating the Supreme Court decision. Most notably, the exclusion for waste treatment systems is retained.

Effluent Limitation Guidelines

The 2015 Steam Electric Effluent Limitations Guidelines required, among other things, that there be no discharge of bottom ash transport water. In 2020 the EPA finalized the Reconsideration Rule, allowing limited discharges of bottom ash transport water up to 10% of system volume, under certain defined circumstances including significant (10-year, 24-hour) rain events. The 2020 rule also created a subcategory for units that permanently cease coal combustion by December 31, 2028. Entergy’s White Bluff facility filed a notice of planned participation for this subcategory in October 2021. In May 2024 the EPA finalized a supplemental rule that retains the “retirement by 2028” subcategory, creates a new “retirement by 2034” subcategory, otherwise reinstates the zero-discharge requirement for bottom ash transport water, and imposes new requirements for leachate after the facility ceases to burn coal. Thus, units which permanently cease combustion of coal by December 31, 2028 or December 31, 2034 are exempt from the zero-discharge requirement. However, for units in the 2034 subcategory, the 10% discharge allowance must be incorporated into the facility’s discharge permit. To be covered by this exemption, both Independence and Nelson Unit 6 will need to file Notices of Planned Participation in the 2034 subcategory by December 31, 2025. To help ensure facilities cease combustion of coal by the required subcategory 2028 and 2034 dates, zero discharge of bottom ash transport water is required after April 30, 2029 and April 30, 2035, respectively. Entergy continues to evaluate the compliance pathways and obligations of this rule.

Other Environmental Matters

Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas

The EPA notified Entergy that the EPA believes Entergy is a PRP concerning PCB contamination at the F.J. Doyle Salvage facility in Leonard, Texas. The facility operated as a scrap salvage business during the 1970s to the 1990s. In May 2018 the EPA investigated the site surface and sub-surface soils, and in November 2018 the EPA conducted a removal action, including disposal of PCB contaminated soils. Entergy responded to the EPA’s information requests in May and July 2019. In November 2020 the EPA sent Entergy and other PRPs a demand letter seeking reimbursement for response costs totaling $4 million expended at the site. Liability and PRP allocation of response costs are yet to be determined. In December 2020, Entergy responded to the demand letter, without admitting liability or waiving any rights, indicating that it would engage in good faith negotiations with the EPA with respect to the demand. An initial meeting between the EPA and the PRPs took place in June 2021. Negotiations between the PRPs and the EPA are ongoing.