Item 1. Entergy Corporation, Utility operating companies, and System Energy

Entergy Corporation, Utility operating companies, and System Energy

(b)Includes activity from financial transmission rights. See Note 15 to the financial statements for discussion of financial transmission rights.

(c)Entergy New Orleans’s renewables include liquidated damage payments of $0.5 million in 2024, $0.1 million in 2023, and $2.9 million in 2022 due to the delay of in-service dates related to purchased power agreements.

Actual 2024 and projected 2025 sources of generation for the Utility operating companies and System Energy, including certain power purchases from affiliates under life of unit power purchase agreements, including the Unit Power Sales Agreement, are:

			2024
			CT / CCGT (b)						Legacy Gas						Nuclear (c)						Coal						Renewables (c) (d)						Purchased Power (e)						MISO Purchases (f)
Entergy Arkansas			29		%				1		%				56		%				6		%				4		%				—		%				4		%
Entergy Louisiana			45		%				10		%				20		%				1		%				2		%				8		%				14		%
Entergy Mississippi			65		%				2		%				20		%				7		%				1		%				—		%				5		%
Entergy New Orleans			46		%				2		%				41		%				1		%				2		%				1		%				7		%
Entergy Texas			32		%				28		%				11		%				3		%				2		%				—		%				24		%
System Energy (a)			—		%				—		%				100		%				—		%				—		%				—		%				—		%
Utility			42		%				10		%				27		%				3		%				2		%				4		%				12		%

			2025
			CT / CCGT (b)						Legacy Gas						Nuclear (c)						Coal						Renewables (c) (d)						Purchased Power (e)						MISO Purchases (f)
Entergy Arkansas			28		%				—		%				59		%				5		%				8		%				—		%				—		%
Entergy Louisiana			52		%				4		%				23		%				2		%				3		%				16		%				—		%
Entergy Mississippi			60		%				—		%				30		%				9		%				1		%				—		%				—		%
Entergy New Orleans			51		%				1		%				43		%				1		%				3		%				1		%				—		%
Entergy Texas			46		%				32		%				14		%				6		%				2		%				—		%				—		%
System Energy (a)			—		%				—		%				100		%				—		%				—		%				—		%				—		%
Utility			47		%				6		%				32		%				4		%				4		%				7		%				—		%

(a)Capacity and energy from System Energy’s interest in Grand Gulf is allocated as follows under the Unit Power Sales Agreement: Entergy Arkansas - 36%; Entergy Louisiana - 14%; Entergy Mississippi - 33%; and Entergy New Orleans - 17%. Pursuant to purchased power agreements, Entergy Arkansas is selling a portion of its owned capacity and energy from Grand Gulf to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. Effective January 1, 2025, Entergy Louisiana has divested all of its 14% share of capacity and energy from Grand Gulf and all of the capacity and energy from Grand Gulf that it purchases from Entergy Arkansas (approximately 2.43%) to Entergy Mississippi. This divestiture is being effectuated initially under a designated PPA between Entergy Louisiana and Entergy Mississippi, effective as of January 1, 2025. See Note 8 to the financial statements for discussion of Entergy Louisiana’s divestiture from the Unit Power Sales Agreement.

(b)Represents natural gas sourced for Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.

(c)The percentage of nuclear and renewable energy includes energy procured or produced for the benefit of certain customers through special tariffs, contracts, or renewable program subscriptions, and those customers retain the exclusive claims to all associated environmental attributes, renewable energy credits, and other relevant clean energy certifications.

(d)Includes generation from both owned and purchased power resources.

(e)Excludes MISO purchases and renewables purchased through purchased power agreements.

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Entergy Corporation, Utility operating companies, and System Energy

(f)In December 2013, Entergy integrated its transmission system into the MISO RTO. Entergy offers all of its generation into the MISO energy market on a day-ahead and real-time basis and bids for power in the MISO energy market to serve the demand of its customers, with MISO making dispatch decisions. The MISO purchases metric provided for 2024 is not projected for 2025.

Some of the Utility’s gas-fired plants are also capable of using fuel oil, if necessary. Although based on current economics the Utility does not expect fuel oil use in 2025, it is possible that various operational events including weather or pipeline maintenance may require the use of fuel oil.

Natural Gas

The Utility operating companies have long-term and short-term firm and interruptible gas contracts for both supply and transportation. Over 70% of the Utility operating companies’ power plants maintain some level of long-term firm transportation. Long-term, short-term, and spot-market purchases satisfy gas requirements. Entergy Texas owns a gas storage facility and Entergy Louisiana has a firm storage service agreement that provide reliable and flexible natural gas service to certain generating stations.

Many factors, including wellhead deliverability, storage, pipeline capacity, and demand requirements of end users, influence the availability and price of natural gas supplies for power plants. Demand is primarily tied to weather conditions as well as to the prices and availability of other energy sources. Pursuant to federal and state regulations, gas supplies to power plants may be interrupted during periods of shortage. To the extent natural gas supplies are disrupted or natural gas prices significantly increase, the Utility operating companies may in some instances use alternate fuels, such as oil when available, or rely to a larger extent on coal, nuclear generation, and purchased power.

Coal

Entergy Arkansas has committed to seven one- to three-year contracts that will supply at least 85% of the total coal supply needs in 2025. These contracts are staggered in term so that not all contracts have to be renewed the same year. If needed, additional Powder River Basin (PRB) coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. Based on the high cost of alternate sources, modes of transportation, and infrastructure improvements necessary for its delivery, no alternative coal consumption is expected at Entergy Arkansas during 2025. Coal will be transported to Arkansas via an existing Union Pacific transportation agreement that is expected to provide all of Entergy Arkansas’s rail transportation requirements for 2025.

Entergy Louisiana has committed to three two- to three-year contracts that will supply at least 90% of Nelson Unit 6 coal needs in 2025. If needed, additional PRB coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. For the same reasons as the Entergy Arkansas plants, no alternative coal consumption is expected at Nelson Unit 6 during 2025. Coal will be transported to Nelson via an existing transportation agreement that is expected to provide all of Entergy Louisiana’s rail transportation requirements for 2025.

For the year ended December 31, 2024, coal transportation delivery rates to Entergy Arkansas- and Entergy Louisiana-operated coal-fired units were able to fully meet supply needs and obligations, and delivery rates in 2025 are expected to continue to be consistent with 2024 delivery rates in meeting supply needs and obligations. Both Entergy Arkansas and Entergy Louisiana control a sufficient number of railcars to satisfy the rail transportation requirement.

The operator of Big Cajun 2 - Unit 3, Louisiana Generating, LLC, has advised Entergy Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2025.

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Entergy Louisiana’s and Entergy Texas’s coal nomination requests to Big Cajun 2 - Unit 3 are made on an annual basis.

Nuclear Fuel

The nuclear fuel cycle consists of the following:

• mining and milling of uranium ore to produce a concentrate;

• conversion of the concentrate to uranium hexafluoride gas;

• enrichment of the uranium hexafluoride gas;

• fabrication of nuclear fuel assemblies for use in fueling nuclear reactors; and

• disposal of spent fuel.

The Registrant Subsidiaries that own nuclear plants, Entergy Arkansas, Entergy Louisiana, and System Energy, are responsible through a shared regulated uranium pool for contracts to acquire nuclear material to be used in fueling Entergy’s Utility nuclear units. These companies own the materials and services in this shared regulated uranium pool on a pro rata fractional basis determined by the nuclear generation capability of each company. Any liabilities for obligations of the pooled contracts are on a several but not joint basis. The shared regulated uranium pool maintains inventories of nuclear materials during the various stages of processing. The Registrant Subsidiaries purchase enriched uranium hexafluoride for their nuclear plant reload requirements at the average inventory cost from the shared regulated uranium pool. Entergy Operations, Inc. contracts separately for the fabrication of nuclear fuel as agent on behalf of each of the Registrant Subsidiaries that owns a nuclear plant. All contracts for the disposal of spent nuclear fuel are between the DOE and the owner of a nuclear power plant.

Based upon currently planned fuel cycles, the Utility 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 or fixed prices through 2027. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners, including their ability to work through supply disruptions caused by global events, such as the COVID-19 pandemic, or national events, such as political disruption, or trade-related governmental actions, such as tariffs and other measures. There are a number of possible supply alternatives that may be accessed to mitigate any supplier performance failure, including potentially drawing upon Entergy’s inventory intended for later generation periods depending upon its risk management strategy at that time, although the pricing of any alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. In addition, some nuclear fuel contracts are on a non-fixed price basis subject to prevailing prices at the time of delivery.

Entergy’s ability to assure nuclear fuel supply also depends upon the performance reliability of conversion, enrichment, and fabrication services providers. There are fewer of these providers than for uranium. For conversion and enrichment services, like uranium, Entergy diversifies its supply by supplier and country and may take special measures as needed to ensure supply of enriched uranium for the reliable fabrication of nuclear fuel. For fabrication services, each plant is dependent upon the effective performance of the fabricator of that plant’s nuclear fuel, therefore, Entergy provides additional monitoring, inspection, and oversight for the fabrication process to assure reliability and quality.

The effects of market price changes may be reduced and deferred by risk management strategies, such as negotiation of floor and ceiling amounts for long-term contracts, buying for inventory or entering into forward physical contracts at fixed prices when Entergy believes it is appropriate and useful. Entergy buys uranium and conversion and enrichment services 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 United States.

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Entergy Corporation, Utility operating companies, and System Energy

Entergy Arkansas, Entergy Louisiana, and System Energy each have made arrangements to lease nuclear fuel and related equipment and services. The lessors, which are consolidated in the financial statements of Entergy and the applicable Registrant Subsidiary, finance the acquisition and ownership of nuclear fuel through credit agreements and the issuance of notes. These credit facilities are subject to periodic renewal, and the notes are issued periodically, typically for terms between three and seven years.

Natural Gas Purchased for Resale

Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with one interstate and three intrastate pipelines. Entergy New Orleans has a “no-notice” service gas purchase contract with Symmetry Energy Solutions which ensures Entergy New Orleans gas delivery at specific delivery points and at any volume within the minimum and maximum set forth in the contract amounts. The Symmetry Energy Solutions gas supply is transported to Entergy New Orleans pursuant to a transportation service agreement with Gulf South Pipeline Co. This service is subject to FERC-approved rates. Entergy New Orleans also makes interruptible spot market purchases.

Entergy Louisiana has been purchasing natural gas for resale since April 2024 under a firm contract with Symmetry Energy Solutions. Entergy Louisiana’s prior contract with Sequent Energy Management L.P. was not renewed and ended in March 2024. The gas is delivered through a combination of intrastate and interstate pipelines.

As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy Louisiana’s or Entergy New Orleans’s suppliers failed to perform their obligations to deliver gas under their supply agreements. Gulf South Pipeline Co. could curtail transportation capacity only in the event of pipeline system constraints.

Federal Regulation of the Utility

State or local regulatory authorities, as described above, regulate the retail rates of the Utility operating companies. The FERC regulates wholesale sales of electricity rates and interstate transmission of electricity, including System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. See Note 2 to the financial statements for further discussion of federal regulation proceedings.

Transmission and MISO Markets

In December 2013 the Utility operating companies integrated into the MISO RTO. Although becoming a member of MISO did not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities, MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. MISO also exercises functional control of transmission planning and congestion management and provides schedules and pricing for the commitment and dispatch of generation that is offered into MISO’s markets, as well as pricing for load that bids into the markets. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their owned and controlled generating facilities into the MISO resource adequacy construct (the annual Planning Resource Auction), as well as the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. The resource adequacy construct provided under the MISO tariff confers certain rights and imposes certain obligations upon load-serving entities, including the Utility operating companies, that are served from the transmission systems subject to MISO’s functional control, including the transmission facilities of the Utility operating companies. The MISO tariff is subject to change and has recently undergone significant changes, including changes to its overall capacity accreditation methodology. MISO is now pursuing a larger scale reassessment of its overall accreditation practices, including accreditation of renewable resources.

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Entergy Corporation, Utility operating companies, and System Energy

MISO administers a process governed by the MISO tariff and subject to the FERC regulation that governs the interconnection of new generation resources to the transmission system under MISO’s functional control. This process generally involves parties that wish to interconnect new generation resources submitting to MISO requests to do so, which are then studied and analyzed by MISO, with the participation of its member transmission owners, to determine if the interconnection of such generators requires new transmission facilities to ensure the continued reliable operations of the grid. Under MISO’s current tariff, these requests are studied and considered in clusters, generally in the order in which they are received – a system of priority known as the MISO interconnection queue.

Each Utility operating company has its own transmission pricing zone and a formula rate template (included as Attachment O to the MISO tariff) used to establish transmission rates within MISO. The terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets and the allocation of transmission upgrade costs, are subject to regulation by the FERC.

In addition, orders from each of the Utility operating companies’ respective retail regulators generally require that the Utility operating companies make periodic filings, or generally allow the retail regulator to direct the making of such filings, setting forth the results of analysis of the costs and benefits realized from MISO membership as well as the projected costs and benefits of continued membership in MISO and/or requesting approval of their continued membership in MISO.

System Energy and Related Agreements

System Energy recovers costs related to its interest in Grand Gulf through rates charged to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans for capacity and energy under the Unit Power Sales Agreement (described below). In 1998 the FERC approved requests by Entergy Arkansas and Entergy Mississippi to accelerate a portion of their Grand Gulf purchased power obligations. Entergy Arkansas’s and Entergy Mississippi’s acceleration of Grand Gulf purchased power obligations ceased effective July 2001 and July 2003, respectively, as approved by the FERC. See Note 2 to the financial statements for discussion of proceedings at the FERC related to System Energy.

Unit Power Sales Agreement

The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System Energy’s ownership and leasehold interests in Grand Gulf to Entergy Arkansas (36%), Entergy Louisiana (14%), Entergy Mississippi (33%), and Entergy New Orleans (17%). Effective January 1, 2025, Entergy Louisiana is divesting all of its rights, entitlements, and interests in such capacity and energy to Entergy Mississippi. See Note 8 to the financial statements for discussion of Entergy Louisiana’s divestiture from the Unit Power Sales Agreement. Each of these companies is obligated to make payments to System Energy for its entitlement of capacity and energy on a full cost-of-service basis regardless of the quantity of energy delivered. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenue. The financial condition of System Energy depends upon the continued commercial operation of Grand Gulf and the receipt of such payments. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans generally recover payments made under the Unit Power Sales Agreement through rates charged to their customers; however, as discussed further below, for the majority of 2025 and until it is removed from the Unit Power Sales Agreement, Entergy Louisiana will recover its payments made under the Unit Power Sales Agreement from Entergy Mississippi under a designated PPA in connection with Entergy Louisiana’s divesting to Entergy Mississippi its 14% share of capacity and energy from Grand Gulf under the Unit Power Sales Agreement and its 2.43% share of capacity and energy from Entergy Arkansas under the MSS-4 replacement tariff.

In the case of Entergy Arkansas and Entergy Louisiana, payments are also recovered through sales of electricity from their respective retained shares of Grand Gulf. Under a settlement agreement entered into with the APSC in 1985 and amended in 1988, Entergy Arkansas retains 22% of its 36% share of Grand Gulf-related costs

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Entergy Corporation, Utility operating companies, and System Energy

and recovers the remaining 78% of its share in retail rates. In the event that Entergy Arkansas is not able to sell its retained share to third parties, it may sell such energy to its retail customers at a price equal to its avoided cost, which is currently less than Entergy Arkansas’s cost from its retained share. Entergy Arkansas has life-of-resources purchased power agreements with Entergy Louisiana and Entergy New Orleans that sell a portion of the output of Entergy Arkansas’s retained share of Grand Gulf to those companies. The remainder of Entergy Arkansas’s retained share is sold to Entergy Mississippi through a separate life-of-resource purchase power agreement with Entergy Mississippi. Entergy Arkansas also has a life-of-resources purchased power agreement with Entergy Mississippi to sell a portion of the output of Entergy Arkansas’s non-retained share of Grand Gulf. Entergy Mississippi was granted cost recovery for those purchases by the MPSC through its annual unit power cost rate mechanism.

In a series of LPSC orders, court decisions, and agreements from late 1985 to mid-1988, Entergy Louisiana was granted cost recovery with respect to costs associated with Entergy Louisiana’s share of capacity and energy from Grand Gulf, subject to certain terms and conditions. Prior to the divestiture of Grand Gulf energy and capacity to Entergy Mississippi, Entergy Louisiana retained and did not recover from retail ratepayers 18% of its 14% share of the costs of Grand Gulf capacity and energy and recovers the remaining 82% of its share in rates. Entergy Louisiana was also allowed to recover through the fuel adjustment clause at 4.6 cents per kWh for the energy related to its retained portion of these costs. Alternatively, Entergy Louisiana was permitted to sell such energy to non-affiliated parties at prices above the fuel adjustment clause amount, subject to the LPSC’s approval.

Effective January 1, 2025, Entergy Louisiana has divested all of its 14% share of capacity and energy from Grand Gulf and all of the capacity and energy from Grand Gulf that it purchases from Entergy Arkansas (approximately 2.43%) to Entergy Mississippi. This divestiture is being effectuated initially under a designated PPA between Entergy Louisiana and Entergy Mississippi, which was accepted by the FERC in November 2024. The MPSC approved the MSS-4 replacement PPA, effective as of January 1, 2025. In 2025, System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans expect to file an amendment to the UPSA that will modify the purchasers’ entitlements to capacity and energy from System Energy’s share of Grand Gulf to reflect Entergy Louisiana’s divestiture, and when that amendment becomes effective, the designated PPA between Entergy Louisiana and Entergy Mississippi will terminate and Entergy Louisiana will cease to be a System Energy customer. The effectiveness of that amendment to the Unit Power Sales Agreement will be subject to the review and acceptance of the FERC.

Availability Agreement

The Availability Agreement among System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans was entered into in 1974 in connection with the original financing by System Energy of Grand Gulf. The Availability Agreement provides that System Energy make available to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans all capacity and energy available from System Energy’s share of Grand Gulf.

Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans also agreed severally to pay System Energy monthly for the right to receive capacity and energy from Grand Gulf in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement) would at least equal System Energy’s total operating expenses for Grand Gulf (including depreciation at a specified rate and expenses incurred in a permanent shutdown of Grand Gulf) and interest charges.

The allocation percentages under the Availability Agreement are fixed as follows: Entergy Arkansas - 17.1%; Entergy Louisiana - 26.9%; Entergy Mississippi - 31.3%; and Entergy New Orleans - 24.7%. The allocation percentages under the Availability Agreement would remain in effect and would govern payments made under such agreement in the event of a shortfall of operating expense funds available to System Energy from other sources, including payments under the Unit Power Sales Agreement.

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Entergy Corporation, Utility operating companies, and System Energy

System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for all of its outstanding series of first mortgage bonds, as well as for its outstanding term loan and the pollution control revenue refunding bonds issued on its behalf. In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they were prohibited by governmental action from making payments under the Availability Agreement (for example, if the FERC reduced or disallowed such payments as constituting excessive rates), they would then make subordinated advances to System Energy in the same amounts and at the same times as the prohibited payments. System Energy would not be allowed to repay these subordinated advances so long as it remained in default under the related indebtedness or in other similar circumstances.

Each of the assignment agreements relating to the Availability Agreement provides that Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans will make payments directly to System Energy. However, if there is an event of default, those payments must be made directly to the holders of indebtedness that are the beneficiaries of such assignment agreements. The payments must be made pro rata according to the amount of the respective obligations secured.

The obligations of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans to make payments under the Availability Agreement are subject to the receipt and continued effectiveness of all necessary regulatory approvals. Sales of capacity and energy under the Availability Agreement would require that the Availability Agreement be submitted to the FERC for approval with respect to the terms of such sale. No such filing with the FERC has been made because sales of capacity and energy from Grand Gulf are being made pursuant to the Unit Power Sales Agreement. If, for any reason, sales of capacity and energy are made in the future pursuant to the Availability Agreement, the jurisdictional portions of the Availability Agreement would be submitted to the FERC for approval.

Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement to System Energy have exceeded the amounts payable under the Availability Agreement and, therefore, no payments under the Availability Agreement to System Energy have ever been required. However, if Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy Louisiana and Entergy New Orleans could become subject to claims or demands by System Energy or certain of its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments because their allocated shares under the Availability Agreement exceed their allocated shares under the Unit Power Sales Agreement.

The Availability Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, without further consent of any assignees or other creditors. Effective January 1, 2025, Entergy Mississippi entered into a Reimbursement Agreement with Entergy Louisiana, under which it agreed to assume Entergy Louisiana’s rights and obligations under and to hold Entergy Louisiana harmless with respect to the Availability Agreement. That Reimbursement Agreement is intended to be in effect until the Unit Power Sales Agreement is modified to reflect Entergy Mississippi’s increased entitlements to System Energy’s share of Grand Gulf energy and capacity, following Entergy Louisiana’s divestiture of its combined 16.43% share of the Unit Power Sales Agreement and purchased power agreement entitlements to energy and capacity to Entergy Mississippi. When the Unit Power Sales Agreement modifications become effective, System Energy also anticipates implementing an Availability Agreement that reflects the Unit Power Sales Agreement entitlements of Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans.

In December 2024, System Energy, Entergy Louisiana, Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans agreed to terminate the Reallocation Agreement. See Note 8 to the financial statements for further discussion of the reallocation agreement.

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Service Companies

Entergy Services, a limited liability company wholly-owned by Entergy Corporation, provides management, administrative, accounting, legal, engineering, and other services primarily to the Utility operating companies, as well as to Entergy’s non-utility operations business. Entergy Operations is also wholly-owned by Entergy Corporation and provides nuclear management, operations, and maintenance services under contract for ANO, River Bend, Waterford 3, and Grand Gulf, subject to the owner oversight of Entergy Arkansas, Entergy Louisiana, and System Energy, respectively. Entergy Services and Entergy Operations provide their services to the Utility operating companies and System Energy on an “at cost” basis, pursuant to cost allocation methodologies for these service agreements that were approved by the FERC.

Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas

Effective December 31, 2007, Entergy Gulf States, Inc. completed a jurisdictional separation into two vertically integrated utility companies, one operating under the sole retail jurisdiction of the PUCT, Entergy Texas, and the other operating under the sole retail jurisdiction of the LPSC, Entergy Gulf States Louisiana. Entergy Texas owns all Entergy Gulf States, Inc. distribution and transmission assets located in Texas, the gas-fired generating plants located in Texas, undivided 42.5% ownership shares of Entergy Gulf States, Inc.’s 70% ownership interest in Nelson Unit 6 and 42% ownership interest in Big Cajun 2, Unit 3, which are coal-fired generating plants located in Louisiana, and other assets and contract rights to the extent related to utility operations in Texas. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, owns all of the remaining assets that were owned by Entergy Gulf States, Inc. On a book value basis, approximately 58.1% of the Entergy Gulf States, Inc. assets were allocated to Entergy Gulf States Louisiana and approximately 41.9% were allocated to Entergy Texas.

Entergy Texas purchases from Entergy Louisiana pursuant to a life-of-unit purchased power agreement a 42.5% share of capacity and energy from the 70% of River Bend subject to retail regulation. Entergy Texas was allocated a share of River Bend’s nuclear and environmental liabilities that is identical to the share of the plant’s output purchased by Entergy Texas under the purchased power agreement. In connection with the termination of the System Agreement effective August 31, 2016, the purchased power agreements that were put in place for certain legacy units at the time of the jurisdictional separation were also terminated at that time.

Entergy Louisiana and Entergy Gulf States Louisiana Business Combination

On October 1, 2015, the businesses formerly conducted by Entergy Louisiana (Old Entergy Louisiana) and Entergy Gulf States Louisiana (Old Entergy Gulf States Louisiana) were combined into a single public utility. In order to effect the business combination, under the Texas Business Organizations Code (TXBOC), Old Entergy Louisiana allocated substantially all of its assets to a new subsidiary, Entergy Louisiana Power, LLC, a Texas limited liability company (New Entergy Louisiana), and New Entergy Louisiana assumed the liabilities of Old Entergy Louisiana, in a transaction regarded as a merger under the TXBOC. Under the TXBOC, Old Entergy Gulf States Louisiana allocated substantially all of its assets to a new subsidiary (New Entergy Gulf States Louisiana) and New Entergy Gulf States Louisiana assumed the liabilities of Old Entergy Gulf States Louisiana, in a transaction regarded as a merger under the TXBOC. New Entergy Gulf States Louisiana then merged into New Entergy Louisiana with New Entergy Louisiana surviving the merger. Thereupon, Old Entergy Louisiana changed its name from “Entergy Louisiana, LLC” to “EL Investment Company, LLC” and New Entergy Louisiana changed its name from “Entergy Louisiana Power, LLC” to “Entergy Louisiana, LLC” (Entergy Louisiana). With the completion of the business combination, Entergy Louisiana holds substantially all of the assets, and has assumed the liabilities, of Old Entergy Louisiana and Old Entergy Gulf States Louisiana.

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Other Business Activities

Entergy’s non-utility operations business includes the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. Entergy’s non-utility operations business also provides decommissioning-related services to nuclear power plants owned by non-affiliated entities.

Property

Entergy’s non-utility operations business owns interests in the following non-nuclear power plants:

Plant						Location						Ownership						Net Owned Capacity (a)						Type
Independence Unit 2; 842 MW						Newark, AR						14%						121 MW(b)						Coal
Nelson Unit 6; 550 MW						Westlake, LA						11%						60 MW(b)						Coal

(a)“Net Owned Capacity” refers to the nameplate rating on the generating unit.

(b)The owned MW capacity is the portion of the plant capacity owned by Entergy’s non-utility operations business. For a complete listing of Entergy’s jointly-owned generating stations, refer to “Jointly-Owned Generating Stations” in Note 1 to the financial statements.

All generation owned by Entergy’s non-utility operations business falls under the authority of MISO. Customers for the sale of both energy and capacity from its owned generation and contracted power purchases include retail power providers, utilities, electric power co-operatives, power trading organizations, and other power generation companies. The majority of the non-utility operations businesses’ owned generation and contracted power purchases are sold under a cost-based contract.

TLG Services, a subsidiary in Entergy’s non-utility operations business, offers decommissioning, engineering, and related services to nuclear power plant owners.

Regulation of Entergy’s Business

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,

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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;

• utility service areas;

• retail rates and charges, including depreciation rates;

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

• terms and conditions of service;

• service standards;

• 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;

• avoided cost payments to non-exempt Qualifying Facilities;

• net energy metering;

• integrated resource planning;

• 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:

• utility service;

• retail rates and charges, including depreciation rates;

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

• terms and conditions of service;

• service standards;

• 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;

• integrated resource planning;

• net energy metering; and

• utility mergers and acquisitions and other changes of control.

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

• utility service;

• utility service areas;

• retail rates and charges, including depreciation rates;

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

• terms and conditions of service;

• service standards;

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

• avoided cost payments to non-exempt Qualifying Facilities;

• integrated resource planning;

• net energy metering; and

• 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:

• utility service;

• retail rates and charges, including depreciation rates;

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

• terms and conditions of service;

• service standards;

• 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;

• integrated resource planning;

• net energy metering;

• avoided cost payments to non-exempt Qualifying Facilities;

• 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;

• service standards;

• certification of certain transmission and generation projects;

• utility service areas, including extensions into new areas;

• avoided cost payments to non-exempt Qualifying Facilities;

• net energy metering; and

• 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.

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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

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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

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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.

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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 (SO2) 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

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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 (PM2.5) NAAQS

In March 2024 the EPA issued a final rule which revised the primary annual NAAQS for fine particulate matter, also known as PM2.5, from 12 ug/m3 to 9 ug/m3. 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 PM2.5 concentrations in excess of this new standard and monitors for several other areas reflect concentrations between 8-9 ug/m3. 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 SO2 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

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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 SO2 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 SO2 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.

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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 CO2 emission standard for low load (<20% annual capacity factor) EGUs; an output-based CO2 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 CO2 efficiency standard followed by a more stringent Phase 2 CO2 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 CO2 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 CO2 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 CO2 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.

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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 SO2, 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.

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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

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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.

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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.

Litigation

Entergy and its subsidiaries use legal and appropriate means to contest litigation threatened or filed against them, but the states in which Entergy and the Registrant Subsidiaries operate have 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. The litigation environment in these states poses a significant business risk to Entergy.

Asbestos Litigation (Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas)

See Note 8 to the financial statements for a discussion of this litigation.

Employment and Labor-related Proceedings (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

See Note 8 to the financial statements for a discussion of these proceedings.

Human Capital

Employees

Employees are an integral part of Entergy’s commitment to serving customers. As of December 31, 2024, Entergy subsidiaries employed 12,267 people.

Entergy Arkansas			1,314
Entergy Louisiana			1,669
Entergy Mississippi			770
Entergy New Orleans			302
Entergy Texas			741
System Energy			—
Entergy Operations			3,211
Entergy Services			4,245
Entergy Nuclear Operations			13
Other subsidiaries			2
Total Entergy			12,267

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There are 3,105 employees represented by the International Brotherhood of Electrical Workers, the United Government Security Officers of America, and the International Union, Security, Police, and Fire Professionals of America.

Below is the breakdown of Entergy’s employees by gender and race/ethnicity:

Gender (%) (a)			2024						2023
Female			23.0						23.0
Male			77.0						77.0

Race/Ethnicity (%) (a)			2024						2023
White			73.2						73.1
Black/African American			18.4						18.2
Hispanic/Latino			3.3						3.2
Asian			2.5						2.4
Other			2.6						3.1

(a)Based on employees who self-identify.

Entergy’s Approach to Human Resources

Entergy’s people and culture enable its success; that is why acquiring, retaining, and developing talent are important components of Entergy’s human resources strategy. Entergy focuses on an approach that includes, among other things, governance and oversight; safety; organizational health, including diversity, inclusion, and belonging; and talent management.

Governance and Oversight

Ensuring that workplace processes support the desired culture and strategy begins with the Board of Directors and the Office of the Chief Executive. The Talent and Compensation Committee is responsible for overseeing and monitoring the effectiveness of Entergy’s human capital strategies and initiatives, including those pertaining to talent management, diversity, inclusion and belonging, organizational health, retention, safety, and executive compensation and performance, and receives briefings on these and other topics. The Talent and Compensation Committee establishes and regularly reviews priorities, strategies, and performance on these topics.

Other committees of the Board oversee other key aspects of Entergy’s culture. For example, the Audit Committee reviews reports on enterprise risks, ethics, and compliance training and performance, as well as regular reports on calls made to Entergy’s ethics line and related investigations. To maximize the sharing of information and facilitate the participation of all Board members in these discussions, the Board schedules its regular committee meetings in a manner such that all directors can attend.

The Office of the Chief Executive, which includes Entergy’s Chief Human Resources Officer, ensures annual business plans are designed to support Entergy’s talent objectives, reviews workforce-related metrics, and regularly discusses the development, succession planning, and performance of their direct reports and other company officers.

Safety

Entergy’s safety objective is: Everyone Safe. All Day. Every Day. In 2024, Entergy set a record for its total recordable incident rate, reaching a new low of 0.41 combined employee and contractor results. This was a

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significant improvement on the company’s performance of 0.48 in 2023 and 0.51 in 2022. The recordable incident rate equals the number of recordable incidents per 100 full-time equivalents. Recordable incidents include fatalities, lost-time accidents, restricted-duty accidents, and medical attentions. Despite an active storm season in 2024, Entergy was able to manage restoration during the two named storms in Entergy’s service territory with only a single contractor heat related injury. The results of 2024 unfortunately included an increase in significant injuries and fatalities, including four contractor fatalities after almost 900 days without experiencing a single employee or contractor fatality. In response to the increase in significant injuries and fatalities, Entergy has enhanced its focused training, leadership efforts, and field presence for employees and contractors to further the objective of zero fatalities, which the company had been able to achieve in 2022 and 2023.

Organizational Health

Entergy believes that organizational health fosters an engaged and productive culture that positions Entergy to deliver sustainable value to its stakeholders. Entergy measures its progress in this area through an organizational health survey coordinated by an external third party. Since initially administering the survey in 2014, Entergy improved from an initial score of 49 (fourth quartile) to a score in 2022 of 61 (third quartile), in 2023 of 62 (third quartile), and in 2024 of 65 (third quartile). Improvement in behavioral expectations, which Entergy believes are the leading indicators of outcome improvements, suggests that Entergy is continuing to move in a positive direction.

Entergy believes that creating a culture of diversity, inclusion, and belonging drives engagement for all employees. Entergy is committed to developing and retaining a top-performing workforce with a wide variety of backgrounds, experiences, and perspectives. Entergy’s human resources department focuses on, among other things, talent management, workforce development, talent attraction/pipeline development, retention, organizational health, and diversity, inclusion, and belonging. Among other strategies, Entergy partners with colleges and vocational-technical schools to develop a more viable pipeline of future talent, while also expanding efforts to increase employee engagement and cultivate an inclusive culture with high performance. Entergy has several employee resource groups, open to all employees, offers leadership development programs to support all employees, and facilitates skills training from the executive leadership ranks down to the frontline. Through these efforts, Entergy aspires to create greater understanding and accountability regarding the behaviors and outcomes that are indicative of a premier utility.

Talent Management

Entergy’s focus on talent management is organized in three areas: developing and attracting a highly qualified workforce with a broad range of backgrounds, skill sets, and experiences, equipping its leaders to develop the organization, and building premier utility capability through employee performance management and succession programs. Entergy believes that developing a workforce with a wide variety of backgrounds, experiences, and perspectives equipped with the skills needed, today and in the future, will give it a long-term competitive advantage. The focus of Entergy’s leadership development programs is to equip managers with the skills needed to effectively develop their teams and improve the leader-employee relationship. Entergy’s talent development infrastructure, which includes a combination of business function-specific and enterprise-wide learning and development programs, is designed to ensure Entergy has qualified employees with the skills, experiences, and behaviors needed to perform today and prepare for the future. Entergy strives to achieve its strategic priorities by aligning and enhancing team and individual performance with business objectives, effectively deploying talent through succession planning, and managing workforce transitions.

Availability of SEC filings and other information on Entergy’s website

Entergy electronically files reports with the SEC, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements, and amendments to such filings. The SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding

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registrants that file electronically with the SEC at https://www.sec.gov. Copies of the reports that Entergy files with the SEC can be obtained at the SEC’s website.

Entergy uses its website, https://www.entergy.com, as a routine channel for distribution of important information, including news releases, analyst presentations, and financial information. Filings made with the SEC are posted and available without charge on Entergy’s website as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. These filings include annual and quarterly reports on Forms 10-K and 10-Q and current reports on Form 8-K (including related filings in XBRL format), proxy statements, and any amendments to such filings. All such postings and filings are available on Entergy’s Investor Relations website free of charge. Entergy is providing the address to its internet website solely for the information of investors and does not intend the address to be an active link. Notwithstanding this reference or any references to the website in this report, the contents of the website are not incorporated into this report.

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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, efforts to obtain land and secure permits for infrastructure, efforts to execute on and/or obtain regulatory approvals for generation, transmission, carbon capture and storage, or other facilities, the operation and maintenance of their assets and

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infrastructure, including with respect to climate or environmental matters, their preparedness for major storms or other extreme weather events (including accelerated resilience plans and projects, as well as executing same and/or seeking and obtaining regulatory approvals for such plans and projects) and/or the time it takes to restore service after such 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, among other things, result in project delays or cancellations or 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 potentially negatively affect legislative or regulatory processes or outcomes, including but not limited to failure to obtain requested approvals on infrastructure investments, 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. An upward trend in spending, especially with respect to infrastructure investments (including those that have already been approved by a regulator), 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 result in adverse cost recovery determinations and/or face resistance from customers and other stakeholders especially in a rising cost environment, whether due to inflation, increased tariffs or changes to governmental policies and programs, including tax incentives or tax credits, grants, guarantees, and other subsidies, 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 current 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, regulation, or governmental policy, 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

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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, including due to inflation or increased tariffs or as a result of changes to governmental policies and programs, including tax incentives or tax credits, loans, grants, guarantees, and other subsidies. 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.

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 a rising cost environment, whether due to inflation or increased tariffs and/or 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 and are subject to the same increased costs due to factors described herein as potentially impacting other capital projects, 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 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.

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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. 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, and these risks may be exacerbated by significant new load additions whether by the Utility operating companies or by other MISO load-serving entities. 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. 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, and these risks may be exacerbated by significant new load additions whether by the Utility operating companies or by other MISO load-serving entities.

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, and these risks may be exacerbated by significant new load additions.

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 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, as well as limitations on the

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ability to fund other investments to address customer needs, which limitations could have an adverse impact on the Utility operating companies’ financial results and/or customers and impede economic development opportunities that would benefit the Utility operating companies and their customers and communities. 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 due to factors described herein as potentially impacting other capital projects, and impede the ability to support economic development opportunities in the areas served by the Utility operating companies.

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 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 already reduced sales, and other non-traditional procurements, such as virtual purchase power agreements or “behind the meter” generation solutions, could, and in some instances have already 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. Advances in technology and changes in laws or regulations offer alternative methods of producing and/or consuming energy, some potentially at a reduced cost. The Utility operating companies’ future success will depend, in part, on our ability to anticipate and successfully adapt to technological developments and to offer services that meet customer demand. Failure to keep pace or manage the related costs of such changes or additional technology investments may limit customer growth and have an adverse effect on the Utility operating companies’ operations or could make the Utility operating companies less competitive and

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negatively impact Entergy’s and the Utility operating companies’ financial condition, results of operations, and cash flows.

Electricity sales to industrial customers, in particular, benefit from steady economic growth and favorable commodity markets; however, industrial sales are or may be sensitive to changes in laws, regulations, trade-related governmental actions, including tariffs and other measures, or 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 large data center customers or electrification opportunities to help such customers achieve their environmental sustainability goals. This could occur because of changes in customers’ goals or business priorities, changes in environmental policies and priorities of federal, state, and local officials and other stakeholders, competition from other companies, or decisions by such customers to seek to achieve such objectives or 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.

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

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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 the factors described in the immediately preceding sentence, 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, bans, retaliatory actions, 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 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,

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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 result in a plant shutdown or operation at less than full capacity and 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 breaches, and has won and collected on judgments against the government totaling approximately $1.2 billion through 2024, and continues to be involved in litigation to recover damages. Furthermore, Entergy is uncertain as to when the DOE will commence acceptance of 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

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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 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. The current maximum annual assessment amounts total approximately $72.2 million per occurrence for the Utility nuclear plants. The retrospective premium assessments are subject to change based on results of NEIL underwriting.

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.

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

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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.

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.

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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, governmental policy (including tax and trade policy, such as increased tariffs) or governmental programs (including tax incentives or tax credits, loans, grants, guarantees, and other subsidies), 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 or other catastrophes, that rely on fossil fuels, or that are impacted by risks related to climate change, or such sources of capital de-emphasizing their interest in investing in clean or renewable energy projects. Additionally, shifts in governmental policy surrounding tax incentives or tax credits, loans, grants, guarantees, and other subsidies may increase borrowing costs. 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 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.

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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.

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, wildfires, 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, wildfires, 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 or other impacts, including those relative to any trade or tariff issues, as well as any shortages or delays in the availability of key components, parts, and supplies such as electronic components, steel, aluminum, 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;

• 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 and working partially remotely or geopolitical risks;

• 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 and welfare benefit plan trusts or decommissioning trust funds;

• litigation;

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

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• 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.

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 or catastrophe 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; failure to obtain land and secure permits for infrastructure investments; failure to execute on and/or obtain regulatory approvals for generation, transmission, or other facilities; real or perceived violations of environmental regulations, including those related to climate change; real or perceived issues surrounding the safety or environmental concerns regarding carbon capture and storage; real or perceived issues with Entergy’s safety culture; challenges or negative reaction to Entergy’s diversity, inclusion, and belonging efforts, or work culture and environment; challenges or negative reaction to Entergy’s climate goals; inability to meet their climate goals, including as a result of increased sales growth, or to achieve their human capital strategies, or failure to demonstrate meaningful progress toward such goals or strategies; deterioration in relations with bargaining employees and labor unions representing them; inability to effectively prepare for major storms and other weather events, including accelerated resilience planning and projects and challenges in execution thereof, including obtaining necessary regulatory approvals for scope and timing of such plans and projects; 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, or termination of, construction projects, including as a result of or in connection with changes in regulation or governmental policy (such as tax and trade policy, including increased tariffs and supply chain challenges) or governmental programs (such as tax incentives or tax credits, loans, grants, guarantees, and other subsidies); 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.

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 their ability to attract and retain a qualified, inclusive, and diverse workforce with a wide variety of backgrounds, experiences, and perspectives, 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.

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Entergy Corporation, Utility operating companies, and System Energy

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 the repeal, continuation, or 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, or any other changes to or repeal of such tax credits, 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 current 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.

See Note 3 to the financial statements for discussion of the effects of the Tax Cuts and Jobs Act on 2024, 2023, and 2022 results of operations and financial condition, the provisions of 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 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.

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Entergy Corporation, Utility operating companies, and System Energy

Entergy and its subsidiaries’ ability to successfully execute on their business strategies, including their ability to execute on their growth strategies and 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.

Entergy and its subsidiaries’ future prospects and results of operations significantly depend on their ability to successfully implement their business strategies, including executing on their growth strategy and 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.

Entergy and its subsidiaries anticipate a high level of load growth in their industrial and large commercial customer segments, including from large data centers owned by a small number of large customers. Entergy and its subsidiaries may be unsuccessful in capturing such opportunities or the opportunities to serve these new large customers may not materialize to the degree currently expected. Entergy and its subsidiaries also may not have access to the capital needed to finance the incremental growth on terms and conditions satisfactory to Entergy or its subsidiaries and consistent with the maintenance of satisfactory credit ratings. Entergy and its subsidiaries may fail to execute within currently expected time frames or within currently expected costs, due to a number of factors, including failure to obtain, or any delay in obtaining, regulatory approval, shortages of qualified labor, supply chain constraints, other cost pressures, or inadequate project management and execution. Entergy and its subsidiaries may not be able to adequately protect contractually against the risks inherent in relying on such rapid growth within a small number of large customers concentrated in a single industry. These customers may represent a high percentage of total sales, revenues, and cash flow with respect to the applicable Utility operating company and thereby create business and credit concentration risks which Entergy and its subsidiaries may not be able to fully mitigate.

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 several natural gas plants and 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;

• shifting governmental policies may impact government support for capital projects, including tax incentives or tax credits, grants, guarantees, or other subsidies; and

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• 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.

The success of certain Utility operating companies’ investments in new generation and transmission assets to support large-scale data centers depends on a limited number of customers, the continued demand for electricity to power data centers, and the successful completion of the associated generation and transmission projects. Any reduction in the demand for electricity to power data centers or delays or unexpected costs associated with such projects may harm the growth prospects, future operating results, and financial condition of Entergy and these Utility operating companies.

Subject to pending regulatory approvals, certain Utility operating companies are planning to make significant infrastructure investments in new solar projects, natural gas power plants, and other transmission and generation assets to power new large-scale data centers. These infrastructure investments are being made primarily in connection with electric service agreements with a small number of customer representing significant new load to provide power for new data centers being constructed to support artificial intelligence and other technology capabilities. The Utility operating companies continue to explore similar opportunities and may engage in additional similar transactions in the future.

This concentration of business with a small number of customers in an industry based on emerging technologies, including artificial intelligence and machine learning, presents several risks for these Utility operating companies. These technologies and their related business applications have developed rapidly in recent years and continue to develop. Entergy cannot predict the rate at which or the extent to which these emerging technologies will be broadly adopted and successful as business models. Changes in industry practice or advances in these technologies could reduce the demand for electricity to power data centers. Additionally, these customers may experience business downturn, which may cause the loss of these customers or may weaken their financial condition. Similarly, customers may reduce their investment in these new technologies or abandon them entirely.

Any of these situations may result in the early termination or non-renewal of these customers’ electric service agreements or renewal on terms less favorable to the Utility operating company. Our electric service agreements with these customers include provisions for early termination payments in certain circumstances, but they do not fully protect against these risks. In the event a customer does not renew its electric service agreement, the Utility operating companies are also subject to the risk that they may not be able to enter into services agreements with new customers or that the terms of any new agreements may be less favorable to the Utility operating companies. While the assets constructed to serve these customers may otherwise be useful in the Utility operating companies’ business, there is a risk that the Utility operating companies may not be able to fully recover their investment in or a return on those assets, either through retail or wholesale rates. The small number of such customers and scale of the investment required to support those customers exacerbates this risk.

The success of these Utility operating companies’ investments in new generation and transmission assets to support large-scale data centers depends on the successful completion of large capital projects to provide electricity to these data centers. As discussed elsewhere in this report, the ability to complete large capital projects is dependent upon several factors, including, among others, the ability to obtain financing of such projects on satisfactory terms and conditions, secure regulatory permits, secure sufficient land for the siting of solar panels and power generation facilities, obtain and maintain MISO interconnection queue positions and otherwise obtain necessary interconnection or transmission service in MISO, and hire qualified labor, as well as levels of public support or opposition to these projects, and suppliers’ and contractors’ performance and ability to fulfill their obligations under contracts. Successful completion of these projects may be further influenced by changes in law or regulation, such as environmental compliance requirements or MISO tariff rules and processes, direct and indirect

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trade and tariff issues, including those associated with imported solar panels, as well as supply chain delays or disruptions, workforce challenges, and other events beyond the control of these Utility operating companies. The occurrence of any of these events may materially affect the schedule, cost, and performance of these projects. If these projects 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-offs of their investments in these projects or incur other costs or risks, including MISO market risks or charges. For additional information concerning these Utility operating companies’ investments in new generation to support large-scale data centers, see “Utility - Property and Other Generation Resources - Provision of Service to Large-Scale Data Center Customers” in Part I, Item 1.

The business, results of operations and financial condition of Entergy and these Utility operating companies could be materially adversely affected as a result of any or all of these factors.

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. Certain events may occur that may materially affect the schedule, cost, and performance of these projects. These events may relate to the actual siting and construction process, such as facing public opposition; delays in obtaining permits; challenges in securing sufficient land for the siting of solar panels, power generation facilities, and large transmission projects; shortages in materials and qualified labor; 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; supply chain delays or disruptions; and changes in the scope and timing of projects. Various economic and financial factors may include 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; and downward changes in the economy. Regulatory and legal issues include items such as changes in law or regulation, including environmental compliance requirements; and further direct and indirect trade and tariff issues, including those associated with imported solar panels or other goods or products required to complete major capital projects. Additionally, 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.

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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 and/or retain sufficient skilled contract labor resources to supplement the workforce, their results of operations, financial position, and cash flows could be negatively affected.

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 existing 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 implementing agencies’ permitting and enforcement decisions. 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.

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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 have been 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, 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. Similarly, increased load growth and the natural gas generation required to meet that increased demand could result in an increase in Entergy’s absolute greenhouse gas emissions. 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, or government programs relating to, 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

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stranded costs if Entergy’s Utility operating companies are unable to fully recover the costs and investment in generation; (iv) increase the difficulty that Entergy and its Utility operating companies have with obtaining or maintaining required environmental regulatory approvals; and (v) cause the financing needs of Entergy and its subsidiaries to increase should such changes result in a repeal or limitation on government tax credits, loans, grants, guarantees, or other subsidies incentivizing the development or utilization of alternative sources of generation , 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. 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, achievement of the 2030 emission rate goal could also be challenged as a result of the forecasted and future sales growth. Further 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.

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 has and continues to pursue and execute on 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 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. Certain accelerated resilience plans of the Utility operating companies have received regulatory approval for a limited scope and duration, generally at levels less than those proposed to the regulators. The Utility operating companies may not be able to successfully execute such plans and projects in the time and manner planned and there are risks regarding the ability to demonstrate the efficacy of the accelerated resilience investments in mitigating storm impacts, as well as in seeking and obtaining regulatory approval for additional accelerated resilience plans and projects that may be necessary. The need for this investment and these expenditures could give

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rise to execution, 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 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

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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.

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 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 performance of certain obligations, money, energy, or other commodities will not perform their obligations. If counterparties to these arrangements, such as counterparties to large customer electric service agreements or hedging arrangements, fail to perform, Entergy or its subsidiaries may seek to enforce its contractual protections, but may be unsuccessful, such as in recovering proceeds adequate to cover the related obligations, which could materially affect the applicable Utility operating company or Entergy’s non-utility business, despite any contractual protections.

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

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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 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 and phishing attacks, business email compromises, viruses, malicious code, 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 and advanced 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, misconfiguration, 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 and sophisticated 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.

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

Entergy Corporation, Utility operating companies, and System Energy

Given the fraught geopolitical landscape and 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 or otherwise, 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 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, wildfires, and other catastrophic events, in addition to an increased focus on climate issues, has had and may continue to 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, the prices of 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, the prices of 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.

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

Entergy Corporation, Utility operating companies, and System Energy

(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 System Energy, the affiliated companies, and these revenues are the subject of ongoing litigation and may be subject to future such litigation and regulatory proceedings.

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 has in the past been the subject of significant litigation, including claims for refunds and rate adjustments, and is currently the subject of a litigation proceeding at the FERC with respect to System Energy’s inclusion of pre-paid and accrued pension costs in rates. Entergy cannot predict with certainty the outcome of this proceeding or any future proceedings that may arise with respect to the Unit Power Sales Agreement.

See Note 2 to the financial statements for further discussion of the litigation proceedings that have been settled at the FERC. System Energy 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 and certain other agreements relating to certain Entergy System companies’ support of System Energy, see Note 8 to the financial statements and the “Utility - System Energy and Related Agreements” section of Part I, Item 1.

(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, including wholesale sales of electricity, 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 imposition of liens, fines, and/or civil or criminal liability. If Entergy’s non-utility operations

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

Entergy Corporation, Utility operating companies, and System Energy

were deemed to violate market behavior rules, the FERC can impose potential penalties of up to $1.544 million per day for each violation by any such entity of market-based rate rules and regulations.

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.

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.

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

Entergy Corporation, Utility operating companies, and System Energy

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.