ENTERGY CORP /DE/ (ETR) FY 2024 MD&A

Results of Operations

2024 Compared to 2023

Following are income statement variances for Utility, Parent & Other, and Entergy comparing 2024 to 2023 showing how much the line item increased or (decreased) in comparison to the prior period.

(a)Parent & Other includes eliminations, which are primarily intersegment activity.

Results of operations for 2024 include: (1) a $320 million ($253 million net-of-tax) settlement charge, reflected in Parent & Other above, recognized as a result of a group annuity contract purchased in 2024 to settle certain pension liabilities; (2) expenses of $151 million ($112 million net-of-tax), recorded at Utility in second quarter 2024, primarily consisting of regulatory charges to reflect the effects of an agreement in principle between Entergy Louisiana and the LPSC staff and the intervenors in July 2024 to renew Entergy Louisiana’s formula rate

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plan and resolve a number of other retail dockets and matters, including all formula rate plan test years prior to 2023; (3) a $132 million ($97 million net-of-tax) charge, recorded at Utility, to reflect the write-off of a previously recorded regulatory asset as a result of an adverse decision in the Entergy Arkansas opportunity sales proceeding in March 2024; and (4) a $78 million ($57 million net-of-tax) regulatory charge, recorded at Utility in first quarter 2024, primarily to reflect a settlement in principle between Entergy New Orleans and the City Council in April 2024 for additional sharing with customers of income tax benefits from the resolution of the 2016-2018 IRS audit. See Note 11 to the financial statements for discussion of the group annuity contract and settlement charge. See Note 2 to the financial statements for discussion of the Entergy Louisiana agreement in principle and the subsequently filed global stipulated settlement agreement. See Note 2 to the financial statements for discussion of the Entergy Arkansas opportunity sales proceeding. See Note 3 to the financial statements for discussion of the Entergy New Orleans April 2024 settlement in principle and discussion of the resolution of the 2016-2018 IRS audit.

Results of operations for 2023 include: (1) a $568 million reduction, recorded at Utility, and a $275 million reduction, recorded at Parent & Other, in income tax expense as a result of the resolution of the 2016-2018 IRS audit, partially offset by $98 million ($72 million net-of-tax) of regulatory charges, recorded at Utility, to reflect credits expected to be provided to customers by Entergy Louisiana and Entergy New Orleans as a result of the resolution of the 2016-2018 IRS audit; (2) the reversal of a $106 million regulatory liability, primarily associated with the Hurricane Isaac securitization, recognized in 2017 as a result of the Tax Cuts and Jobs Act, recorded at Utility, as part of the settlement of Entergy Louisiana’s test year 2017 formula rate plan filing; (3) a $129 million reduction in income tax expense as a result of Entergy Louisiana’s storm cost securitization in March 2023, partially offset by a $103 million ($76 million net-of-tax) regulatory charge, recorded at Utility, to reflect Entergy Louisiana’s obligation to provide credits to its customers as described in an LPSC ancillary order issued as part of the securitization regulatory proceeding; and (4) write-offs of $78 million ($59 million net-of-tax), recorded at Utility, as a result of Entergy Arkansas’s approved motion to forgo recovery of identified costs resulting from the 2013 ANO stator incident. See Note 3 to the financial statements for discussion of the resolution of the 2016-2018 IRS audit and discussion of the Tax Cuts and Jobs Act. See Note 2 to the financial statements for further discussion of the Entergy Louisiana formula rate plan global settlement. See Notes 2 and 3 to the financial statements for further discussion of the Entergy Louisiana March 2023 storm cost securitization. See Note 8 to the financial statements for further discussion of the ANO stator incident and the approved motion to forgo recovery.

Operating Revenues

Utility

Following is an analysis of the change in operating revenues comparing 2024 to 2023:

The Utility operating companies’ results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset

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and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.

The retail one-time bill credit represents the disbursement of settlement proceeds in the form of a one-time bill credit provided to Entergy Arkansas’s retail customers during the August 2024 billing cycle through the Grand Gulf credit rider as a result of the System Energy settlement with the APSC. There is no effect on net income because Entergy previously recorded a regulatory liability at the time of the global black box settlement reached between System Energy and the MPSC in June 2022. See Note 2 to the financial statements for discussion of the System Energy settlements with the APSC and the MPSC and discussion of Entergy Arkansas’s Grand Gulf credit rider.

Storm restoration carrying costs, representing the equity component of storm restoration carrying costs, includes $31 million recognized by Entergy Louisiana as part of its March 2023 storm cost securitization and $5 million recognized by Entergy New Orleans as part of the City Council’s approval of the Entergy New Orleans storm cost certification report in December 2023. See Note 2 to the financial statements for discussion of the storm cost securitizations.

The volume/weather variance is primarily due to an increase in weather-adjusted residential and commercial usage, partially offset by the effect of less favorable weather on residential and commercial sales. The increase in weather-adjusted residential usage is the result of higher fixed charges, partially offset by lower volumetric rates, applied to lower usage. Adding to this was an increase in industrial usage primarily due to an increase in demand from large industrial customers, primarily in the petroleum refining and chlor-alkali industries and from new customers in the technology industry.

The retail electric price variance is primarily due to:

•an increase in Entergy Arkansas’s formula rate plan rates effective January 2024;

•increases in Entergy Louisiana’s formula rate plan revenues, including increases in the distribution and transmission recovery mechanisms, effective September 2023 and September 2024;

•increases in Entergy Mississippi’s formula rate plan rates effective April 2024 and July 2024, including the implementation of the interim facilities rate adjustment effective over six months beginning in July 2024;

•increases in Entergy New Orleans’s formula rate plan rates effective September 2023 and September 2024; and

•an increase in Entergy Texas’s base rates effective June 2023 and the implementation of the distribution cost recovery factor rider effective with the first billing cycle in October 2024, partially offset by the implementation of the generation cost recovery relate-back rider for the Hardin County Peaking Facility effective over three months beginning in May 2023.

See Note 2 to the financial statements for further discussion of the regulatory proceedings discussed above.

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Total electric energy sales for Utility for the years ended December 31, 2024 and 2023 are as follows:

See Note 19 to the financial statements for additional discussion of operating revenues.

Other Income Statement Items

Utility

Other operation and maintenance expenses increased from $2,838 million for 2023 to $2,851 million for 2024 primarily due to:

•an increase of $38 million in compensation and benefits costs primarily due to higher healthcare claims activity, including lower prescription drug rebates in 2024 as compared to 2023, and higher incentive-based accruals in 2024 as compared to 2023;

•an increase of $19 million in energy efficiency expenses primarily due to the timing of recovery from customers;

•an increase of $15 million in transmission costs allocated by MISO. See Note 2 to the financial statements for discussion of the recovery of these costs;

•the effects of recording a final judgment in first quarter 2023 to resolve claims in the ANO damages case against the DOE related to spent nuclear fuel storage costs. The damages awarded included the reimbursement of approximately $10 million of spent nuclear fuel storage costs previously recorded as other operation and maintenance expenses. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation;

•an increase of $10 million in loss provisions;

•an increase of $8 million in storm damage provisions;

•an increase of $7 million in bad debt expense; and

•a gain of $7 million on the partial sale of a service center at Entergy Texas in April 2023 as part of an eminent domain proceeding.

The increase was partially offset by:

•a decrease of $54 million in power delivery expenses primarily due to lower vegetation maintenance costs;

•a decrease of $15 million in nuclear generation expenses primarily due to a lower scope of work performed in 2024 as compared to 2023 and lower nuclear labor costs;

•a decrease of $12 million in non-nuclear generation expenses primarily due to a lower scope of work, including during plant outages, performed in 2024 as compared to 2023;

•a decrease of $10 million in information technology costs primarily due to enhancements made in 2023 to certain information technology systems; and

•a decrease of $9 million in customer service center support costs primarily due to lower contract costs.

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Asset write-offs, impairments, and related charges (credits) includes:

•a $132 million charge to reflect the write-off, at Entergy Arkansas, of a previously recorded regulatory asset as a result of an adverse decision in the Entergy Arkansas opportunity sales proceeding in March 2024. See Note 2 to the financial statements for discussion of the Entergy Arkansas opportunity sales proceeding; and

•the effects of Entergy Arkansas forgoing recovery of identified costs resulting from the 2013 ANO stator incident. In third quarter 2023, Entergy Arkansas recorded write-offs of its regulatory asset for deferred fuel of $68.9 million and the undepreciated balance of $9.5 million in capital costs related to the ANO stator incident. See Note 8 to the financial statements for further discussion of the ANO stator incident and the approved motion to forgo recovery.

Depreciation and amortization expenses increased primarily due to:

•additions to plant in service;

•a reduction in depreciation expense of $41 million, recorded in third quarter 2023 at System Energy, representing the cumulative difference in depreciation expense resulting from the depreciation rates used from March 2022 through June 2023 and the depreciation rates included in the depreciation amendment proceeding settlement filing approved by the FERC in August 2023;

•the recognition of $28 million in depreciation expense in 2024 at Entergy Texas for the 2022 base rate case relate back period, effective over six months beginning January 2024. The recognition of depreciation expense for the relate back period was effective over the same period as collections from the relate back surcharge rider and results in no effect on net income. See Note 2 to the financial statements for discussion of the 2022 base rate case at Entergy Texas; and

•an increase in nuclear depreciation rates at Entergy Louisiana effective September 2024 in accordance with the global stipulated settlement agreement approved by the LPSC in August 2024. See Note 2 to the financial statements for discussion of the global stipulated settlement agreement.

The increase was partially offset by a decrease in depreciation rates at System Energy effective June 2023. See Note 2 to the financial statements for discussion of the Unit Power Sales Agreement depreciation amendment proceeding.

Other regulatory charges (credits) - net includes:

•the reversal in third quarter 2024 of a $92 million regulatory liability recognized for Entergy Arkansas’s obligation to return to customers the refund from the System Energy settlement with the APSC. The reversal of the regulatory liability offsets a reduction in gross revenues from the retail one-time bill credits provided to customers in the August 2024 billing cycle through the Grand Gulf credit rider. See Note 2 to the financial statements for discussion of the System Energy settlement with the APSC and discussion of Entergy Arkansas’s Grand Gulf credit rider;

•a regulatory credit of $16 million, recorded by Entergy Arkansas in fourth quarter 2024, to reflect the amount of the 2023 historical year netting adjustment included in the 2024 formula rate plan filing that it expects to collect from its customers during the 2025 rate effective period. See Note 2 to the financial statements for discussion of the Entergy Arkansas 2024 formula rate plan filing;

•a regulatory charge of $103 million, recorded by Entergy Louisiana in first quarter 2023, to reflect its obligation to provide credits to its customers as described in an LPSC ancillary order issued in the Hurricane Ida securitization regulatory proceeding. See Note 2 to the financial statements for discussion of the Entergy Louisiana March 2023 storm cost securitization;

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

•regulatory charges of $150 million, recorded by Entergy Louisiana in second quarter 2024, to reflect the effects of an agreement in principle between Entergy Louisiana and the LPSC staff and the intervenors in

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July 2024 to renew Entergy Louisiana’s formula rate plan and resolve a number of other retail dockets and matters, including all formula rate plan test years prior to 2023. See Note 2 to the financial statements for discussion of the Entergy Louisiana agreement in principle and the subsequently filed global stipulated settlement agreement;

•a regulatory charge of $60 million, recorded by Entergy New Orleans in fourth quarter 2023, to reflect credits expected to be provided to customers as a result of the resolution of the 2016-2018 IRS audit. See Note 3 to the financial statements for discussion of the resolution of the 2016-2018 IRS audit;

•a regulatory charge of $78 million, recorded by Entergy New Orleans in first quarter 2024, primarily to reflect a settlement in principle between Entergy New Orleans and the City Council in April 2024 for additional sharing with customers of income tax benefits from the resolution of the 2016-2018 IRS audit. See Note 3 to the financial statements for discussion of the April 2024 settlement in principle and discussion of the resolution of the 2016-2018 IRS audit; and

•the reversal in third quarter 2023 of $22 million of regulatory liabilities to reflect the recognition of certain receipts by Entergy Texas under affiliated PPAs that have been resolved. See Note 2 to the financial statements for discussion of Entergy Texas’s 2022 base rate case.

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

Other income increased primarily due to:

•changes in decommissioning trust fund activity, including portfolio rebalancing of decommissioning trust funds in 2024;

•a decrease of $56 million in non-service pension costs primarily as a result of pension settlement charges recorded in 2023 and a reduction in 2024 in the amortization of deferred pension losses as a result of an amendment to a qualified pension plan spinning-off predominantly inactive participants into a new qualified plan, extending the amortization period for deferred losses. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs;

•an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2024, including the Orange County Advanced Power Station project at Entergy Texas;

•a $15 million charge, recorded by Entergy Louisiana in first quarter 2023, for the LURC’s 1% beneficial interest in the storm trust II established as part of the March 2023 storm cost securitization; and

•an increase of $14 million in intercompany dividend income from affiliated preferred membership interests related to storm cost securitizations. The intercompany dividend income on the affiliate preferred membership interests is eliminated for consolidation purposes and has no effect on net income since the investment is in another Entergy subsidiary.

See Note 2 to the financial statements for discussion of the Entergy Louisiana storm cost securitizations.

Interest expense increased primarily due to:

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

•the issuances by Entergy Arkansas of $400 million of 5.75% Series mortgage bonds and $400 million of 5.45% Series mortgage bonds, each in May 2024;

•the issuances by Entergy Louisiana of $500 million of 5.35% Series mortgage bonds and $700 million of 5.70% Series mortgage bonds, each in March 2024;

•the issuance by Entergy Louisiana of $700 million of 5.15% Series mortgage bonds in August 2024;

•the issuance by Entergy Mississippi of $300 million of 5.85% Series mortgage bonds in May 2024;

•the issuance by Entergy Texas of $350 million of 5.80% Series mortgage bonds in August 2023; and

•the issuance by Entergy Texas of $350 million of 5.55% Series mortgage bonds in August 2024.

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The increase was partially offset by:

•the repayment by Entergy Arkansas of $375 million of 3.70% Series mortgage bonds in June 2024;

•the repayment by Entergy Louisiana of $325 million of 4.05% Series mortgage bonds in August 2023;

•the repayment by Entergy Louisiana of $300 million of 5.59% Series mortgage bonds in December 2023; and

•the repayment by Entergy Louisiana of $400 million of 5.40% Series mortgage bonds in April 2024.

See Note 5 to the financial statements for a discussion of long-term debt.

Parent and Other

Asset write-offs, impairments, and related charges (credits) includes:

•the effects of recording a favorable final judgment of $20 million in fourth quarter 2024 to resolve claims in the Northstar Vermont Yankee, LLC (previously Entergy Nuclear Vermont Yankee) final round Vermont Yankee damages case against the DOE;

•the effects of recording a favorable final judgment of $7 million in fourth quarter 2024 to resolve claims in the Holtec Palisades, LLC (previously Entergy Nuclear Palisades) final round Palisades damages case against the DOE; and

•the effects of recording a favorable final judgment of $40 million in third quarter 2023 to resolve claims in the Indian Point 2 fourth round and Indian Point 3 third round combined damages case against the DOE.

See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.

Other income (deductions) decreased primarily due to:

•a $320 million ($253 million net-of-tax) non-cash settlement charge recognized as a result of a group annuity contract purchased in 2024 to settle certain pension liabilities. See Note 11 to the financial statements for discussion of the group annuity contract and settlement charge;

•lower non-service pension income. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs; and

•an increase of $14 million in the amount of the elimination for consolidation purposes of intercompany dividend income from affiliated preferred membership interest, as discussed above.

Interest expense increased primarily due to the issuance of $1.2 billion of junior subordinated debentures in May 2024 and higher commercial paper balances. See Note 4 to the financial statements for discussion of Entergy’s commercial paper program.

Income Taxes

The effective income tax rates were 26.4% for 2024 and (41.3%) for 2023. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates and for additional discussion regarding income taxes.

2023 Compared to 2022

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy’s Annual Report on Form 10-K for the year ended December 31, 2023, filed with the SEC on February 23, 2024, for discussion of results of operations for 2023 compared to 2022.

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Income Tax Legislation and Regulation

The Inflation Reduction Act of 2022 (IRA), signed into law on August 16, 2022, significantly expanded federal tax incentives for clean energy production, including the extension of production tax credits to solar projects and certain qualified nuclear power facilities. Additionally, the IRA enacted a 1% excise tax on the buyback of public company stock and a new corporate alternative minimum tax (CAMT). Effective for tax years beginning after December 31, 2022, the CAMT imposes a 15% tax on the Adjusted Financial Statement Income (AFSI) on each corporation in a group of corporations that averages greater than $1 billion in AFSI over a three-year period. Taxpayers subject to the CAMT regime must pay the greater of 15% of AFSI or their regular federal tax liability. In September 2024 the IRS issued proposed regulations regarding the application of the CAMT. Entergy and the Registrant Subsidiaries are closely monitoring any potential impact associated with the expansion of federal tax incentives, the 1% excise tax, and CAMT. Based on current IRS guidance and internal forecasts, Entergy and the Registrant Subsidiaries may be subject to the CAMT beginning in the next two to four years. The U.S. Treasury is expected to issue further guidance that will clarify how the tax credit provisions and CAMT provisions will be interpreted and applied. This guidance will determine the amount of tax credits and incremental cash tax payments Entergy expects in the future as a result of the legislation. Prior to receiving this guidance, Entergy cannot adequately assess the expected future effects on its results of operations, financial position, and cash flows.

In March and April of 2024 the IRS issued final regulations related to applicable tax credit transferability and direct pay provisions of the IRA. In June 2024 the IRS issued final regulations related to the prevailing wage and apprenticeship requirements under the IRA. In December 2024 the IRS issued final regulations related to technology neutral production tax credits and investment tax credits. Entergy and the Registrant Subsidiaries are closely monitoring any potential effects associated with such federal tax incentives to assess the expected future effects on their results of operations, cash flows, and financial condition. Entergy Arkansas has accrued approximately $5 million of solar production tax credits associated with the Walnut Bend Solar facility, the Driver Solar facility, and the West Memphis Solar facility in 2024. As the value of such credits is expected to be provided to customers, a regulatory liability has been recorded for all credits recognized in 2024.

In April 2023 the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized and provides procedures for taxpayers to obtain automatic consent to change their method of accounting. Entergy adopted this new method of income tax accounting beginning with the 2023 federal income tax return utilizing the safe harbor method in accordance with Revenue Procedure 2023-15. The additional temporary deductions taken using the new method resulted in the recognition of deferred tax liabilities of $14.2 million for Entergy, $7.6 million for Entergy Louisiana, and $6.6 million for Entergy New Orleans.

Entergy Arkansas, Entergy Louisiana, and System Energy have the potential to generate zero-emission nuclear power production tax credits for electricity generated by their respective nuclear power facilities. Based on guidance provided by the U.S. Treasury and the IRS, the nuclear production tax credits will be calculated by multiplying the kWh of qualifying electricity by $0.003, with the value of the credits decreasing ratably, or phasing out, once the annual gross receipts from the sale of nuclear power exceed a certain threshold. If certain prevailing wage requirements are satisfied, the calculation of the credit, as described in the preceding sentence, is multiplied by a factor of five. Additional guidance is needed from the U.S. Treasury and/or the IRS to determine how the value of these credits will be calculated for power generated from nuclear facilities of rate-regulated utilities. Due to the uncertainty of value, if any, of credits Entergy Arkansas, Entergy Louisiana, or System Energy may receive, such credits have not been recognized for the nuclear power produced in 2024. Depending on the specifics of the expected additional guidance from the U.S. Treasury and/or the IRS, Entergy Arkansas, Entergy Louisiana, or System Energy may not recognize any production tax credits for their nuclear facilities, or they could recognize a significant amount each year, beginning for 2024. If the IRS does not issue any technical guidance before the due date of Entergy’s 2024 tax return, Entergy Arkansas, Entergy Louisiana, and System Energy will be required to

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reassess the determination of the availability of such credits based on any other additional information or regulatory requests. If credits are recognized in future periods, the value of such credits is expected to be provided to customers. As such, recognition of nuclear production tax credits is not expected to have a material effect on the results of operations of Entergy, Entergy Arkansas, Entergy Louisiana, or System Energy.

Entergy is not able to predict the effects of any change to or repeal of the above tax legislation, including any federal tax incentives or tax credits, on its or the Registrant Subsidiaries’ results of operations, financial position, and cash flows.

Louisiana Tax Reform

In November 2024, during the Louisiana Third Special Legislative Session of 2024, the Louisiana legislature enacted comprehensive tax reform measures, including the reduction of the corporate state income tax rate to a flat 5.5% from the current highest marginal rate of 7.5%, effective January 1, 2025. Additional enacted measures include the repeal of the Louisiana corporate franchise tax effective January 1, 2026, and an increase in the state sales tax rate to 5%, effective January 1, 2025, until January 1, 2030, when the rate decreases to 4.75%. Additionally, certain digital products and services, such as remotely accessed software and information services, will be subject to sales tax effective January 1, 2025. These products and services will also be taxable at the local level. See Note 3 to the financial statements for further discussion on the 2024 Louisiana tax reform.

Entergy Wholesale Commodities Exit from the Merchant Power Business

Entergy completed its multi-year strategy to exit the merchant nuclear power business in 2022. See Note 13 to the financial statements for discussion of the exit from the merchant nuclear power business.

Shutdown and Sale of Palisades

In July 2018, Entergy entered into a purchase and sale agreement with Holtec International to sell to a Holtec subsidiary 100% of the equity interests in the subsidiary that owns Palisades and the Big Rock Point Site, with a subsequent amendment to the purchase and sale agreement in February 2020. In December 2020, Entergy and Holtec submitted a license transfer application to the NRC requesting approval to transfer the Palisades and Big Rock Point licenses from Entergy to Holtec. In February 2021 several parties filed with the NRC petitions to intervene and requests for hearing challenging the license transfer application. In March 2021, Entergy and Holtec filed answers opposing the petitions to intervene and hearing requests, and the petitioners filed replies. In March 2021 an additional party also filed a petition to intervene and request for hearing. Entergy and Holtec filed an answer to the March 2021 petition in April 2021. The NRC issued an order approving the application in December 2021, subject to the NRC’s authority to condition, revise, or rescind the approval order based on the resolution of four pending requests for hearing. These petitions and requests for hearing remained pending with the NRC at the time of the closing of the Palisades transaction in June 2022. In July 2022 the NRC issued an order granting the Michigan Attorney General’s petition hearing request. The hearing was held in February 2023. A decision from the NRC is pending. See Note 14 to the financial statements for discussion of the sale of the Palisades plant.

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Liquidity and Capital Resources

This section discusses Entergy’s capital structure, capital spending plans and other uses of capital, sources of capital, and the cash flow activity presented in the cash flow statement.

Capital Structure

Entergy’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio is primarily due to the net issuance of long-term debt in 2024.

(a)Calculation excludes the New Orleans and Texas securitization bonds, which are non-recourse to Entergy New Orleans and Entergy Texas, respectively.

As of December 31, 2024, 21.1% of the debt outstanding is at the parent company, Entergy Corporation, and 78.9% is at the Utility. Net debt consists of debt less cash and cash equivalents. Debt consists of notes payable and commercial paper, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt, equity, and subsidiaries’ preferred stock without sinking fund. Net capital consists of capital less cash and cash equivalents. The debt to capital ratio excluding securitization bonds and net debt to net capital ratio excluding securitization bonds are non-GAAP measures. Entergy uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy’s financial condition because the securitization bonds are non-recourse to Entergy, as more fully described in Note 5 to the financial statements. Entergy also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy’s financial condition because net debt indicates Entergy’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

The Utility operating companies and System Energy seek to optimize their capital structures in accordance with regulatory requirements and to control their cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that their operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend to their parent, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that their operating cash flows are insufficient to support planned investments, the Utility operating companies and System Energy may issue incremental debt or reduce dividends, or both, to maintain their capital structures. In addition, Entergy may make equity contributions to the Utility operating companies and System Energy to maintain their capital structures in certain circumstances such as financing of large transactions or payments that would materially alter the capital structure if financed entirely with debt and reduced dividends.

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Long-term debt, including the currently maturing portion, makes up most of Entergy’s total debt outstanding. Following are Entergy’s long-term debt principal maturities and estimated interest payments as of December 31, 2024. To estimate future interest payments for variable rate debt, Entergy used the rate as of December 31, 2024. The amounts below include payments on System Energy’s Grand Gulf sale-leaseback transaction, which are included in long-term debt on the balance sheet.

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

Entergy Corporation has in place a credit facility that has a borrowing capacity of $3 billion and expires in June 2029. The facility includes fronting commitments for the issuance of letters of credit against $20 million of the total borrowing capacity of the credit facility. The commitment fee is currently 0.225% of the undrawn commitment amount. Commitment fees and interest rates on loans under the credit facility can fluctuate depending on the senior unsecured debt ratings of Entergy Corporation. The estimated interest rate for the year ended December 31, 2024 that would have been applied to outstanding borrowings under the facility was 5.96%. The following is a summary of the amounts outstanding and capacity available under the credit facility as of December 31, 2024:

Entergy Corporation’s credit facility includes a covenant requiring Entergy to maintain a consolidated debt ratio, as defined, of 65% or less of its total capitalization.  The calculation of this debt ratio under Entergy Corporation’s credit facility is different than the calculation of the debt to capital ratio above. Entergy is currently in compliance with the covenant and expects to remain in compliance with this covenant. If Entergy fails to meet this ratio, or if Entergy Corporation or one of the Registrant Subsidiaries (except Entergy New Orleans and System Energy) defaults on other indebtedness or is in bankruptcy or insolvency proceedings, an acceleration of the Entergy Corporation credit facility’s maturity date may occur.

Entergy Corporation has a commercial paper program with a Board-approved program limit of $2 billion. As of December 31, 2024, Entergy Corporation had $927.3 million of commercial paper outstanding. The weighted-average interest rate for the year ended December 31, 2024 was 5.52%.

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Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each had credit facilities available as of December 31, 2024 as follows:

(a)The interest rate is the estimated interest rate as of December 31, 2024 that would have been applied to outstanding borrowings under the facility.

(b)Borrowings under this Entergy Arkansas credit facility may be secured by a security interest in its accounts receivable at Entergy Arkansas’s option.

(c)The credit facility includes fronting commitments for the issuance of letters of credit against a portion of the borrowing capacity of the facility as follows: $5 million for Entergy Arkansas; $15 million for Entergy Louisiana; $5 million for Entergy Mississippi; $10 million for Entergy New Orleans; and $25 million for Entergy Texas.

Each of the credit facilities requires the Registrant Subsidiary borrower to maintain a debt ratio, as defined, of 65% or less of its total capitalization. Each Registrant Subsidiary is in compliance with this covenant.

In addition, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each has an uncommitted standby letter of credit facility as a means to post collateral to support their obligations to MISO and for other purposes. The following is a summary of the uncommitted standby letter of credit facilities as of December 31, 2024:

(a)As of December 31, 2024, letters of credit posted with MISO covered financial transmission rights exposure of $0.5 million for Entergy Arkansas, $0.1 million for Entergy Louisiana, $0.8 million for Entergy Mississippi, $0.1 million for Entergy New Orleans, and $0.3 million for Entergy Texas. See Note 15 to the financial statements for discussion of financial transmission rights.

(b)As of December 31, 2024, the letters of credit issued for Entergy Mississippi include $31.8 million in MISO letters of credit and $1.3 million in non-MISO letters of credit outstanding under this facility.

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Finance lease obligations are a minimal part of Entergy’s overall capital structure. Following are Entergy’s payment obligations under those leases.

Finance leases are discussed in Note 10 to the financial statements.

Operating Lease Obligations and Guarantees of Unconsolidated Obligations

Entergy has a minimal amount of operating lease obligations and guarantees in support of unconsolidated obligations. Entergy’s guarantees in support of unconsolidated obligations are not likely to have a material effect on Entergy’s financial condition, results of operations, or cash flows. Following are Entergy’s payment obligations as of December 31, 2024 on non-cancelable operating leases with a term over one year:

Operating leases are discussed in Note 10 to the financial statements.

Other Obligations

Entergy currently expects to contribute approximately $240 million to its qualified pension plans and approximately $42.8 million to its other postretirement plans in 2025, although the 2025 required pension contributions will be known with more certainty when the January 1, 2025 valuations are completed, which is expected by April 1, 2025. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

Entergy has $248 million of unrecognized tax benefits net of unused tax attributes plus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

In addition, the Registrant Subsidiaries enter into fuel and purchased power agreements that contain minimum purchase obligations. The Registrant Subsidiaries each have rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations.

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Capital Expenditure Plans and Other Uses of Capital

Following are the amounts of Entergy’s planned construction and other capital investments for 2025 through 2027.

Planned construction and capital investments refer to amounts Entergy plans to spend on routine capital projects that are necessary to support reliability of its service, equipment, or systems and to support normal customer growth. In addition to routine capital projects, they also refer to amounts Entergy plans to spend on non-routine capital investments for which Entergy is either contractually obligated, has Board approval, or otherwise expects to make to satisfy regulatory or legal requirements. Amounts include the following types of construction and capital investments:

•investments in generation projects to modernize, decarbonize, expand, and diversify Entergy’s portfolio, as well as to support customer growth, including St. Jacques Facility, Bayou Power Station, Delta Blues Advanced Power Station, Delta Solar, Penton Solar, Orange County Advanced Power Station, Lone Star Power Station, Segno Solar, Votaw Solar, and potential construction of additional generation;

•investments in the Utility nuclear fleet;

•transmission spending to improve reliability and resilience while also supporting renewables expansion and customer growth; and

•distribution and Utility support spending to improve reliability, resilience, and customer experience through projects focused on asset renewals and enhancements and grid stability.

For the next several years, the Utility’s owned and contracted generating capacity is projected to be adequate to meet MISO reserve requirements; however, MISO has implemented changes to its resource adequacy construct that generally move from an annual to a seasonal design and that changes the way that resources are assigned capacity credit. MISO has also recently obtained FERC approval to implement additional changes that further affect the assignment of capacity credit to resources. As a result of these changes, there may be seasonal variations in the capacity credit afforded to the Utility operating companies’ resources by MISO, and some resource types generally may be assigned less capacity credit than they have historically. MISO continues to pursue market design changes related to its resource adequacy construct. The FERC recently approved a reliability-based demand curve that may have the effect of increasing the clearing prices in the MISO planning resource auction and increasing the planning reserve margin requirement for the Utility operating companies. MISO is also pursuing changes to the market rules governing load modifying resources, which could affect the accreditation of these resources and, as a result, the capacity positions of the Utility operating companies. These market design changes may have an effect on both the Utility operating companies’ liquidity and the capital investment needed for long-term resources. Entergy is monitoring the evolution and application of these rules, which may require the Utility operating companies to procure additional capacity credits from the MISO market and in the longer-term may impact the incremental additional supply resources needed. The Utility’s supply plan initiative will continue to seek to transform its generation portfolio with new generation resources.  Opportunities resulting from the supply plan initiative, including new projects or the exploration of alternative financing sources, could result in increases or decreases in the capital expenditure estimates given above. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of business restructuring, regulatory constraints and requirements, governmental actions, including trade-related governmental actions, such as tariffs and other

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measures, environmental regulations, business opportunities, market volatility, economic trends, changes in project plans, and the ability to access capital, including any changes to governmental programs, such as loans, grants, guarantees, and other subsidies. Entergy is not able to predict the effect of potential changes in regulation and law, changes to governmental programs, such as loans, grants, guarantees, and other subsidies, and trade-related governmental actions, such as tariffs and other measures, on its current and planned capital projects.

Renewables

2021 Solar Certification and the Geaux Green Option

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

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

In March 2022 direct testimony from Walmart, the Louisiana Energy Users Group (LEUG), and the LPSC staff was filed. Each party recommended that the LPSC approve the resources proposed in Entergy Louisiana’s application, and the LPSC staff witness indicated that the process through which Entergy Louisiana solicited or obtained the proposals for the resources complied with applicable LPSC orders. The LPSC staff and LEUG’s witnesses made recommendations to modify the proposed Rider GGO and Entergy Louisiana’s proposed rate relief. In April 2022 the LPSC staff and LEUG filed cross-answering testimony concerning each other’s proposed modifications to Rider GGO and the proposed rate recovery. Entergy Louisiana filed rebuttal testimony in June 2022. In August 2022 the parties reached a settlement certifying the 2021 Solar Portfolio and approving implementation of Rider GGO. In September 2022 the LPSC approved the settlement. Following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities until the later of March 2023 or the completion of an environmental and economic impact study. In November 2023, St. James Parish lifted the moratorium and adopted an ordinance modifying the parish’s land use plan to establish solar as an approved land use and defining corresponding solar regulations. In March 2024 the project developer submitted a solar energy facility farm permit application to the St. James Parish planning commission to request approval for the Vacherie and St. Jacques Facilities. In June 2024 the St. James Parish council denied the application and following this denial, the project developer and one of the project’s ground lessors filed separate lawsuits seeking to overturn the council’s decision. Entergy Louisiana is currently monitoring the status of the aforementioned lawsuits and also considering alternate paths forward.

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Alternative RFP and Certification

In 2023, Entergy Louisiana made a filing to seek approval from the LPSC for an alternative to the requests for proposals (RFP) process that would enable the acquisition of up to 3 GW of solar resources on a faster timeline than the current RFP and certification process allows. The initial phase of the filing established the need for the acquisition of additional resources and the need for an alternative to the RFP process. The second phase of the filing contained the details of the proposal for the alternative competitive procurement process and the information necessary to support certification. In addition to the acquisition of up to 3 GW of solar resources, the filing also sought approval of a new renewable energy credits-based tariff, the Geaux ZERO rider. In June 2024 the LPSC issued an order approving the application. In August 2024, Entergy Louisiana issued the first RFP pursuant to this order in solicitation of solar resources that meet the requirements of the LPSC’s order. For the first RFP, the initial selection of proposals has been completed, and negotiations are in progress.

Delta Solar

In December 2024 the Bolivar County Board of Supervisors approved Entergy Mississippi’s plans to construct, own, and operate the Delta Solar facility, an 80 MW solar facility to be located in Bolivar County, Mississippi. The Delta Solar facility will cost an estimated $157.2 million, inclusive of estimated transmission interconnection costs. Construction of the Delta Solar facility qualifies for pre-certification under the State legislation providing for the pre-certification of construction of certain types of facilities that directly or indirectly provide electric service to customers who own certain data processing center projects as specified in the legislation. The Delta Solar facility is expected to be in service by the end of 2027.

Penton Solar

Entergy Mississippi plans to construct, own, and operate the Penton Solar facility, a 190 MW solar facility. The Penton Solar facility will cost an estimated $327.2 million, inclusive of estimated transmission interconnection and upgrade costs. Construction of the Penton Solar facility qualifies for pre-certification under the State legislation providing for the pre-certification of construction of certain types of facilities that directly or indirectly provide electric service to customers who own certain data processing center projects as specified in the legislation. The Penton Solar facility is expected to be in service by early 2028.

Segno Solar and Votaw Solar

In July 2024, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the Segno Solar facility, a 170 MW solar facility to be located in Polk County, Texas, and the Votaw Solar facility, a 141 MW solar facility to be located in Hardin County, Texas. The Segno Solar facility will cost an estimated $351.6 million, and the Votaw Solar facility will cost an estimated $303.8 million, in each case inclusive of estimated transmission interconnection and upgrade costs. In September 2024 the PUCT referred the proceeding to the State Office of Administrative Hearings. In December 2024 the ALJs with the State Office of Administrative Hearings adopted a revised agreed procedural schedule, with a hearing on the merits to be held in March 2025. In January 2025 certain intervenors and the PUCT staff filed testimony opposing Entergy Texas’s application. The opposing testimony argues that the proposed generation additions will have a net cost to customers, and it also challenges the design and effectiveness of the voluntary renewable energy tariff. In addition, the opposing testimony recommends that the PUCT impose conditions on any approval of Entergy Texas’s application. The conditions that certain intervenors and the PUCT staff propose include guarantees related to customer net benefits, resource production, independent investigation of any material cost overruns, and the addition of a mandatory sleeving tariff. Entergy Texas plans to file rebuttal testimony in February 2025. A PUCT decision is expected in third quarter 2025. Subject to receipt of required regulatory approval and other conditions, the Segno Solar facility is expected to be in service by early 2027, and the Votaw Solar facility is expected to be in service by mid-2028.

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Other Generation

Lake Catherine Unit 5

In November 2024, Entergy Arkansas filed an application with the APSC seeking a certificate of environmental compatibility and public need for the construction and operation of Lake Catherine Unit 5, a 446 MW hydrogen-capable simple-cycle natural gas combustion turbine facility to be located at the existing Lake Catherine facility site in Hot Spring County, Arkansas. In December 2024 other parties, including the APSC general staff, filed testimony opposing the resource, although the APSC general staff recognized the capacity need for the resource. Entergy Arkansas filed testimony in January 2025 further supporting its application, and in February 2025 the opposing parties filed responsive rebuttal testimony continuing to dispute the estimated costs and to dispute that Entergy Arkansas performed a market solicitation sufficient to demonstrate that this resource is the most reasonable option for customers. Also in February 2025, Entergy Arkansas filed surrebuttal testimony responding to the opposing parties’ testimony. A hearing, if necessary, is scheduled for early March 2025, with an APSC decision requested by the end of March 2025. Subject to receipt of required regulatory approval and other conditions, the facility is expected to be in service by the end of 2028.

Bayou Power Station

In March 2024, Entergy Louisiana filed an application with the LPSC seeking certification that the public convenience and necessity would be served by the construction of the Bayou Power Station, a 112 MW aggregated capacity floating natural gas power station with black-start capability in Leeville, Louisiana and an associated microgrid that would serve nearby areas, including Port Fourchon, Golden Meadow, Leeville, and Grand Isle. In its application, Entergy Louisiana noted that the estimated cost of the Bayou Power Station was $411 million, including estimated costs of transmission interconnection and other related costs. In October 2024, Entergy Louisiana filed a motion to suspend the procedural schedule in this proceeding in order to evaluate certain recent developments related to the project including potential changes to the estimated cost of the project. Entergy Louisiana will determine next steps for the project after fully evaluating these developments. Subject to timely approval by the LPSC and receipt of other permits and approvals, commercial operation is expected to occur by the end of 2028.

Entergy Louisiana Additional Generation and Transmission Resources

In October 2024, Entergy Louisiana filed an application with the LPSC seeking approval of a variety of generation and transmission resources proposed in connection with establishing service to a new data center to be developed by a subsidiary of Meta Platforms, Inc. in north Louisiana, for which an electric service agreement has been executed. The filing requests LPSC certification of three new combined cycle combustion turbine generation resources totaling 2,262 MW, each of which will be enabled for future carbon capture and storage, a new 500 kV transmission line, and 500 kV substation upgrades. The application also requests approval to implement a corporate sustainability rider applicable to the new customer. The corporate sustainability rider contemplates the new customer contributing to the costs of the planned future addition of 1,500 MW of new solar and energy storage resources, agreements involving carbon capture and storage at Entergy Louisiana’s existing Lake Charles Power Station, and potential future wind and nuclear resources. The combined cost of the first two new combined cycle combustion turbine generation resources is estimated to be approximately $2,387 million, and these units are expected to achieve commercial operation in 2028. The third new generation resource is currently expected to have an estimated cost similar to the first two new generation resources and is expected to achieve commercial operation in 2029. The cost of the new 500 kV transmission line is estimated to be $546 million. Entergy Louisiana anticipates funding the incremental cost to serve the customer through direct financial contributions from the customer and the revenues it expects to earn under the electric service agreement. The electric service agreement also contains provisions for termination payments that will help ensure that there is no harm to Entergy Louisiana and its customers in the event of early termination. A directive was issued at the LPSC’s November 2024 meeting for the matter to be decided by October 2025. Consistent with this directive, a procedural schedule was adopted

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setting the matter for hearing in July 2025. In February 2025 intervenors filed a motion asking the LPSC to deny Entergy Louisiana’s requested exemption from the LPSC’s order addressing competitive solicitation procedures and further asking the LPSC to dismiss the application.

In February 2025, Entergy Louisiana filed supplemental testimony with the LPSC stating that the third combined cycle combustion turbine resource presented in the October 2024 application would be sited at Entergy Louisiana’s Waterford site in Killona, Louisiana, alongside existing Entergy Louisiana generation resources. The testimony also notes that Entergy Louisiana is negotiating with the customer to increase the load associated with the customer’s project in north Louisiana and that the additional load can be served without additional generation capacity beyond what was presented in the October 2024 application, but that additional transmission facilities, which will be funded directly by the customer, are needed to serve this additional load.

Entergy Louisiana Transmission Projects

In March 2024, Entergy Louisiana filed an application seeking an exemption determination, or alternatively, a certificate of public convenience and necessity, for a transmission project that includes a new 500 kV/230 kV Commodore substation and an approximately 60-mile 230 kV line connecting the new Commodore substation to the Waterford substation. The project, which was approved by MISO in the 2023 MISO Transmission Expansion Plan, also includes certain common elements with, and right-of-way acquisition for, a future transmission project in the same area consisting of 500 kV elements. The estimated cost of the project is $498.8 million. In February 2025, Entergy Louisiana and the LPSC staff jointly filed, for consideration by the LPSC, an uncontested stipulated settlement agreement resolving all issues in the proceeding. In the motion requesting approval of the uncontested stipulated settlement agreement, the parties requested a settlement hearing in March 2025.

In December 2024, Entergy Louisiana filed an application seeking a certificate of public convenience and necessity for a 500 kV transmission project that includes the construction of a new 84-mile Commodore to Churchill 500 kV transmission line, the expansion of the Waterford 500 kV substation, the construction of a new Churchill 500 kV substation and improvements to the Churchill 230 kV substation, and the conversion of the existing 230 kV Waterford to Churchill transmission line to 500 kV, forming a 500 kV loop into the Downstream of Gypsy load pocket. The project, which was approved by MISO in the 2023 MISO Transmission Expansion Plan, shares common elements with a future transmission project in the same area consisting of 230 kV elements. The estimated cost of the project is $954.7 million.

Entergy Mississippi Additional Generation and Transmission Resources

In January 2024, Amazon Web Services announced its plan to invest in two data centers located in Madison County, Mississippi. In March 2024, Entergy Mississippi executed a large customer supply and service agreement to serve the two data centers. Entergy Mississippi will need generation and transmission resources to reliably serve all Entergy Mississippi customers, including the data centers. The large customer supply and service agreement also contains provisions which cover Entergy Mississippi’s incremental investment costs in the event of early termination. In May 2024 the MPSC approved Entergy Mississippi’s revisions to its formula rate plan to comply with state legislation passed in January 2024 allowing Entergy Mississippi to make interim rate adjustments, including the collection of a return on construction-work-in-process on a cash basis, to recover the non-fuel related annual ownership cost of certain facilities that directly or indirectly provide service to customers who own certain data processing center projects as specified in the legislation. Entergy Mississippi anticipates recovering the incremental cost to serve the customer through the revenues it expects to collect under the large customer supply and service agreement.

In February 2025, Entergy Mississippi entered into a new large customer supply and service agreement with a customer. The planned capital investment estimates for 2025-2027, shown above, include amounts related to the generation and transmission resources needed to reliably serve all Entergy Mississippi customers.

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Delta Blues Advanced Power Station

In September 2024, Entergy Mississippi announced plans to construct, own, and operate the Delta Blues Advanced Power Station, a 754 MW combined-cycle combustion turbine facility, to be located in Washington County, Mississippi. The facility will primarily be powered by natural gas, and it will also be enabled for future carbon capture and storage and for hydrogen co-firing optionality. The Delta Blues Advanced Power Station will cost an estimated $1.2 billion. State legislation passed in January 2024 provides for the pre-certification of construction for certain types of facilities that directly or indirectly provide electric service to customers who own certain data processing center projects as specified in the legislation. Construction of the Delta Blues Advanced Power Station qualifies under this legislation for pre-certification. As enabled by this legislation, Entergy Mississippi began recovery of certain costs of construction of the Delta Blues Advanced Power Station through the interim facilities rate adjustments provision of its formula rate plan rider, which rates became effective in July 2024. Non-fuel revenue collected from the data center customer will be included in the formula rate plan to offset the facility’s revenue requirement. Construction is in progress and the facility is expected to be in service by the end of 2028.

Orange County Advanced Power Station

In September 2021, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the Orange County Advanced Power Station, a new 1,215 MW combined-cycle combustion turbine facility to be located in Bridge City, Texas at an initially-estimated expected total cost of $1.2 billion inclusive of the estimated costs of the generation facilities, transmission upgrades, contingency, an allowance for funds used during construction, and necessary regulatory expenses, among others. The project includes combustion turbine technology with dual fuel capability, able to co-fire up to 30% hydrogen by volume upon commercial operation and upgradable to support 100% hydrogen operations in the future. In December 2021 the PUCT referred the proceeding to the State Office of Administrative Hearings. In March 2022 certain intervenors filed testimony opposing the hydrogen co-firing component of the proposed project and others filed testimony opposing the project outright. Also in March 2022 the PUCT staff filed testimony opposing the hydrogen co-firing component of the proposed project, but otherwise taking no specific position on the merits of the project. The PUCT staff also proposed that the PUCT establish a maximum amount that Entergy Texas may recover in rates attributable to the project. In April 2022, Entergy Texas filed rebuttal testimony addressing and rebutting these various arguments. The hearing on the merits was held in June 2022, and post-hearing briefs were submitted in July 2022. In September 2022 the ALJs with the State Office of Administrative Hearings issued a proposal for decision recommending the PUCT approve Entergy Texas’s application for certification of Orange County Advanced Power Station subject to certain conditions, including a cap on cost recovery at $1.37 billion, the exclusion of investment associated with co-firing hydrogen, weatherization requirements, and customer receipt of any contractual benefits associated with the facility’s guaranteed heat rate. In October 2022 the parties in the proceeding filed exceptions and replies to exceptions to the proposal for decision. Also in October 2022, Entergy Texas filed with the PUCT information regarding a new fixed pricing option for an estimated project cost of approximately $1.55 billion associated with Entergy Texas’s issuance of limited notice to proceed by mid-November 2022. In November 2022 the PUCT issued a final order approving the requested amendment to Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the Orange County Advanced Power Station without the investment associated with hydrogen co-firing capability, without a cap on cost recovery, and subject to certain conditions, including weatherization requirements and customer receipt of any contractual benefits associated with the facility’s guaranteed heat rate.

In December 2022, Texas Industrial Energy Consumers and Sierra Club filed motions for rehearing of the PUCT’s final order alleging the PUCT erred in granting the certification of the Orange County Advanced Power Station, in not imposing a cost cap, in including certain findings related to the reasonableness of Entergy Texas’s request for proposals from which the Orange County Advanced Power Station was selected, and in other regards. Also in December 2022, Entergy Texas filed a response to the motions for rehearing refuting the points raised therein. In January 2023 the PUCT issued letters noting that it voted to consider Texas Industrial Energy

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Consumers’ motion for rehearing at its upcoming January 2023 open meeting and voted not to consider Sierra Club’s motion for rehearing at an open meeting. At the January 2023 open meeting, the PUCT voted to grant Texas Industrial Energy Consumers’ motion for rehearing for the limited purpose of issuing an order on rehearing that excludes three findings related to Entergy Texas’s request for proposals. The order on rehearing does not change the PUCT’s certification of the Orange County Advanced Power Station or the conditions placed thereon in the PUCT’s November 2022 final order. Construction is in progress, and subject to receipt of required permits, the facility is expected to be in service by mid-2026.

Legend Power Station and Lone Star Power Station

In June 2024, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the Legend Power Station, a 754 MW combined-cycle combustion turbine facility, which will be enabled for future carbon capture and storage and for hydrogen co-firing optionality, to be located in Jefferson County, Texas, and the Lone Star Power Station, a 453 MW simple-cycle combustion turbine facility, which will be enabled with hydrogen co-firing optionality, to be located in Liberty County, Texas. In its application, Entergy Texas noted that the Legend Power Station was expected to cost an estimated $1.46 billion and the Lone Star Power Station was expected to cost an estimated $735.3 million, in each case inclusive of the estimated costs of the generation facilities, interconnection costs, transmission network upgrades, and an allowance for funds used during construction. As described in the application, Entergy Texas is considering alternative financing approaches for the Legend Power Station and plans to pursue the financing option that is in the best interest of its customers. In July 2024 the PUCT referred the proceeding to the State Office of Administrative Hearings and, also in July 2024, the ALJ with the State Office of Administrative Hearings adopted a procedural schedule, with a hearing on the merits scheduled to begin in October 2024. In September 2024, Entergy Texas filed, and the ALJ with the State Office of Administrative Hearings granted, a motion to extend the procedural schedule in this proceeding in order to address certain developments relating to the cost and scope of the Legend Power Station and the Lone Star Power Station. In December 2024, Entergy Texas filed supplemental testimony and exhibits addressing the cost and scope developments associated with the Legend Power Station and the Lone Star Power Station in further support of its application. The cost and scope developments include cost estimate increases of $139 million for Legend Power Station and $63.7 million for Lone Star Power Station and the consideration of an alternate site for Lone Star Power Station, which would reduce the estimated cost increase of the Lone Star Power Station to $36.2 million. Also in December 2024, the ALJ with the State Office of Administrative Hearings adopted a procedural schedule with a hearing on the merits to be held in April 2025. A PUCT decision is expected in July 2025. Subject to receipt of required regulatory approval and other conditions, both facilities are expected to be in service by mid-2028.

Resilience and Grid Hardening

Entergy Louisiana

In December 2022, Entergy Louisiana filed an application with the LPSC seeking a public interest finding regarding Phase I of Entergy Louisiana’s Future Ready resilience plan and approval of a rider mechanism to recover the program’s costs. Phase I in the December 2022 application reflected the first five years of a ten-year resilience plan and included investment of approximately $5 billion, including hardening investment, transmission dead-end structures, enhanced vegetation management, and telecommunications improvement. In April 2024 the LPSC approved a framework which includes an initial five-year resilience plan providing for an investment of approximately $1.9 billion with cost recovery via a forward-looking rider with semi-annual true-ups. The plan is subject to specified reporting requirements and includes a performance review of the hardened assets. The LPSC order approving the framework does not include any restrictions on Entergy Louisiana’s ability to file applications for approval of additional investments in resilience.

The LPSC had previously opened a formal rulemaking proceeding in December 2021 to investigate efforts to improve resilience of electric utility infrastructure. In April 2023 the LPSC staff issued a draft rule in the

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

Entergy New Orleans

In October 2021 the City Council passed a resolution and order establishing a docket and procedural schedule with respect to system resiliency and storm hardening. In July 2022, Entergy New Orleans filed with the City Council a response identifying a preliminary plan for storm hardening and resiliency projects, including microgrids, to be implemented over ten years at an approximate cost of $1.5 billion. In February 2023 the City Council approved a revised procedural schedule requiring Entergy New Orleans to make a filing in April 2023 containing a narrowed list of proposed hardening projects. In April 2023, Entergy New Orleans filed the required application and supporting testimony seeking City Council approval of the first phase (five years and $559 million) of a ten-year infrastructure hardening plan totaling approximately $1 billion. Entergy New Orleans also sought, among other relief, City Council approval of a resilience and storm hardening cost recovery rider to recover from customers the costs of the infrastructure hardening plan. In February 2024 the City Council approved a resolution authorizing Entergy New Orleans to implement a resilience project to be partially funded by $55 million of matching funding through the DOE’s Grid Resilience and Innovation Partnerships program. The resolution also required Entergy New Orleans to submit, no later than July 2024, a revised resilience plan consisting of projects over a three-year period. In March 2024, Entergy New Orleans filed with the City Council for approval the requested three-year resilience plan, which includes $168 million in hardening projects. The three-year resilience plan was to be in addition to the previously authorized resilience project to be partially funded by the DOE’s Grid Resilience and Innovation Partnerships program. In October 2024 the City Council approved a resolution authorizing a two-year resilience plan totaling $100 million and approved the requested resilience and storm hardening cost recovery rider. In December 2024, Entergy New Orleans notified the City Council of the subset of hardening projects from the revised three-year resilience plan to be included in the two-year resilience plan. Entergy New Orleans implemented the approved resilience and storm hardening cost recovery rider effective with the first billing cycle of January 2025.

Entergy Texas

In June 2024, Entergy Texas filed an application with the PUCT requesting approval of Phase I of its Texas Future Ready Resiliency Plan, a cost-effective set of measures to begin accelerating the resiliency of Entergy Texas’s transmission and distribution system. Phase I is comprised of projects totaling approximately $335.1 million, including approximately $137 million of projects to be funded by Entergy Texas and approximately $198 million of projects contingent upon Entergy Texas’s receipt of grant funds in that amount from the Texas Energy Fund. The projects in Phase I include distribution and transmission hardening and modernization projects and targeted vegetation management projects to mitigate the risk of wildfire. These projects are expected to be implemented within approximately three years of PUCT approval. In October 2024, Entergy Texas filed an unopposed settlement that would resolve all issues in the proceeding and the PUCT staff filed testimony in support of the unopposed settlement. In January 2025 the PUCT unanimously approved Phase I of Entergy Texas’s Texas Future Ready Resiliency Plan, including the approximately $137 million of projects to be funded by Entergy Texas and application of performance metrics consistent with the unopposed settlement. The PUCT clarified that, while not part of Entergy Texas’s Phase I plan, Entergy Texas is permitted to pursue the remaining $198 million of identified projects and Texas Energy Fund grant funding for those projects. In February 2025 the PUCT issued an

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order adopting a new rule establishing the procedures for application to the grant fund and Entergy Texas intends to pursue an application.

Dividends and Stock Repurchases

Declarations of dividends on Entergy Corporation common stock are made at the discretion of the Board. Among other things, the Board evaluates the level of Entergy Corporation common stock dividends based upon earnings per share from the Utility segment and the Parent and Other portion of the business, financial strength, and future investment opportunities. In January 2025, the Board declared a dividend of $0.60 per share. Entergy paid $982 million in 2024, $918 million in 2023, and $842 million in 2022 in cash dividends on its common stock.

In accordance with Entergy’s stock-based compensation plans, Entergy periodically grants stock options, restricted stock, performance units, and restricted stock units to key employees, which may be exercised to obtain shares of Entergy Corporation common stock. According to the plans, these shares can be newly issued shares, treasury stock, or shares purchased on the open market. Entergy’s management has been authorized by the Board to repurchase on the open market shares up to an amount sufficient to fund the exercise of grants under the plans.

In addition to the authority to fund grant exercises, the Board has authorized share repurchase programs to enable opportunistic purchases in response to market conditions. In October 2010 the Board granted authority for a $500 million share repurchase program. As of December 31, 2024, $350 million of authority remains under the $500 million share repurchase program. The amount of repurchases may vary as a result of material changes in business results or capital spending or new investment opportunities, or if limitations in the credit markets continue for a prolonged period.

Sources of Capital

Entergy’s sources to meet its capital requirements and to fund potential investments include:

•internally generated funds;

•cash on hand ($860 million as of December 31, 2024);

•storm reserve escrow accounts;

•debt and equity issuances in the capital markets, including debt issuances to refund or retire currently outstanding or maturing indebtedness;

•bank financing under new or existing facilities or commercial paper; and

•sales of assets.

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

Provisions within the organizational documents relating to preferred stock or membership interests of certain of Entergy Corporation’s subsidiaries could restrict the payment of cash dividends or other distributions on their common and preferred equity. All debt and preferred equity issuances by the Registrant Subsidiaries require prior regulatory approval and their debt issuances are also subject to requirements set forth in bond indentures and other agreements. Entergy believes that the Registrant Subsidiaries have sufficient capacity under these tests to meet foreseeable capital needs for the next twelve months and beyond.

The FERC has jurisdiction over securities issuances by the Utility operating companies and System Energy. The City Council has concurrent jurisdiction over Entergy New Orleans’s securities issuances with maturities longer than one year. The APSC has concurrent jurisdiction over Entergy Arkansas’s issuances of securities secured by

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Arkansas property, including first mortgage bond issuances. No regulatory approvals are necessary for Entergy Corporation to issue securities. The current FERC-authorized short-term borrowing limits and long-term financing authorization for Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are effective through January 2027. Entergy Arkansas has obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2025. Entergy New Orleans also has obtained long-term financing authorization from the City Council that extends through December 2025. Entergy Arkansas, Entergy Louisiana, and System Energy each has obtained long-term financing authorization from the FERC that extends through January 2027 for issuances by the nuclear fuel company variable interest entities. In addition to borrowings from commercial banks, the Registrant Subsidiaries may also borrow from the Entergy system money pool and from other internal short-term borrowing arrangements. The money pool is an intercompany cash management program that makes possible intercompany borrowing and lending arrangements, and the money pool and the other internal borrowing arrangements are designed to reduce Entergy’s subsidiaries’ dependence on external short-term borrowings. Borrowings from internal and external short-term borrowings combined may not exceed the FERC-authorized limits. See Notes 4 and 5 to the financial statements for further discussion of Entergy’s borrowing limits, authorizations, and amounts outstanding.

Equity Issuances and Equity Distribution Program

In January 2021, Entergy Corporation entered into an equity distribution sales agreement with several counterparties establishing an at the market equity distribution program, pursuant to which Entergy Corporation may offer and sell from time to time shares of its common stock. The sales agreement provides that, in addition to the issuance and sale of shares of Entergy Corporation common stock, Entergy Corporation may enter into forward sale agreements for the sale of its common stock. The aggregate number of shares of common stock sold under this sales agreement and under any forward sale agreement may not exceed an aggregate gross sales price of $3 billion. Through 2022, 2023, and 2024, Entergy Corporation utilized the equity distribution program either to sell or to enter into forward sale agreements with respect to shares of common stock with an aggregate gross sales price of approximately $2.6 billion, of which approximately $2.4 billion of aggregate gross sales price was the subject of forward sale agreements, subject to adjustment pursuant to the forward sale agreements. Entergy Corporation settled the forward sales agreements for cash proceeds of $853 million in November 2022, $48 million in November 2023, and $83 million in December 2023. There were no settlements of forward sale agreements for the year ended December 31, 2024. Entergy Corporation currently expects to issue approximately $4.7 billion of equity through 2028, which it may issue under its at the market equity distribution program or otherwise, with approximately $1.4 billion already contracted under forward sale agreements as of December 31, 2024. See Note 7 to the financial statements for discussion of the forward sales agreements and common stock issuances and sales under the equity distribution program.

Hurricane Francine

In September 2024, Hurricane Francine caused damage to the areas served by Entergy Louisiana and Entergy New Orleans. The storm resulted in widespread power outages, primarily due to damage to distribution infrastructure as a result of strong winds and heavy rain, and the loss of sales during the power outages. See Note 2 to the financial statements for discussion of Entergy Louisiana’s December 2024 storm cost recovery filing related to Hurricane Francine.

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Cash Flow Activity

As shown in Entergy’s Consolidated Statements of Cash Flows, cash flows for the years ended December 31, 2024, 2023, and 2022 were as follows:

2024 Compared to 2023

Operating Activities

Net cash flow provided by operating activities increased $194 million in 2024 primarily due to lower fuel and purchased power costs and the receipt of a $152 million advance payment in 2024 from a customer related to a generation agreement. The increase was partially offset by:

•an increase of $127 million in interest paid;

•lower collections from Utility customers, including the effect of higher deferred fuel collections in 2023; and

•one-time bill credits of $92 million in 2024 to Entergy Arkansas’s retail customers through the Grand Gulf credit rider as a result of the System Energy settlement with the APSC. See Note 2 to the financial statements for discussion of the System Energy settlement agreement with the APSC and Entergy Arkansas’s Grand Gulf credit rider.

Investing Activities

Net cash flow used in investing activities increased $1,220 million in 2024 primarily due to:

•the initial and substantial completion payments totaling approximately $393 million in 2024 for the purchase of the Driver Solar facility by Entergy Arkansas;

•an increase of $291 million in non-nuclear generation construction expenditures primarily due to higher spending by Entergy Louisiana on new generation resources in north Louisiana, by Entergy Mississippi on the Delta Blues Advanced Power Station project, and by Entergy Texas on the Legend Power Station project;

•the initial and substantial completion payments totaling approximately $240 million in 2024 for the purchase of the West Memphis Solar facility by Entergy Arkansas;

•the initial and substantial completion payments totaling approximately $186 million in 2024 for the purchase of the Walnut Bend Solar facility by Entergy Arkansas;

•an increase of $183 million in transmission construction expenditures primarily due to higher capital expenditures as a result of increased development in the Utility service area and increased spending on various transmission projects in 2024, partially offset by lower capital expenditures for storm restoration in

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2024. The decrease in storm restoration expenditures is primarily due to Hurricane Ida restoration efforts in 2023;

•net payments to storm reserve escrow accounts of $17 million in 2024 as compared to net receipts from storm reserve escrow accounts of $79 million in 2023;

•an increase of $89 million in distribution construction expenditures primarily due to increased investment in the resilience of the Utility distribution system, partially offset by lower capital expenditures for storm restoration in 2024; and

•an increase of $38 million in nuclear fuel purchases due to variations from year to year in the timing and pricing of fuel reload requirements, materials and services deliveries, and the timing of cash payments during the nuclear fuel cycle.

The increase was partially offset by:

•a decrease of $111 million in nuclear construction expenditures primarily due to decreased spending on various nuclear projects in 2024;

•an increase of $59 million in proceeds received in 2024 as compared to 2023 from the DOE resulting from litigation regarding spent nuclear fuel storage costs. See Note 8 to the financial statements for discussion of the spent nuclear fuel storage litigation;

•the substantial completion and final payments totaling approximately $35 million in 2023 for the purchase of the Sunflower Solar facility by the Entergy Mississippi tax equity partnership;

•a decrease of $28 million in facilities construction expenditures primarily due to decreased spending on various facilities projects in 2024 and the construction at Entergy Mississippi of a new transmission office in 2023; and

•a decrease of $25 million in information technology capital expenditures primarily due to decreased spending on various technology projects in 2024.

See Note 14 to the financial statements for discussion of the Driver Solar facility, the West Memphis Solar facility, the Walnut Bend Solar facility, and the Sunflower Solar facility purchases.

Financing Activities

Net cash flow provided by financing activities increased $1,844 million in 2024 primarily due to:

•long-term debt activity providing approximately $2,845 million of cash in 2024 compared to using approximately $862 million of cash in 2023;

•an increase of $192 million in advance payments from customers for construction related to transmission, distribution, and generator interconnection agreements; and

•an increase of $127 million in proceeds received from the exercise of stock options in 2024 as compared to 2023.

The increase was partially offset by:

•proceeds from securitization of $1.5 billion received by the storm trust II at Entergy Louisiana in 2023;

•net repayments of $211 million of commercial paper in 2024 as compared to net issuances of $311 million of commercial paper in 2023;

•$131 million in net proceeds from the issuance of common stock under the at the market equity distribution program in 2023. There were no issuances of common stock under the at the market equity distribution program in 2024; and

•an increase of $63 million in common stock dividends paid in 2024 as a result of an increase in the dividend paid per share in 2024 as compared to 2023.

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See Note 5 to the financial statements for details of long-term debt. See Note 2 to the financial statements for a discussion of the Entergy Louisiana March 2023 storm cost securitization. See Note 4 to the financial statements for details of Entergy’s commercial paper program. See Note 7 to the financial statements for discussion of the equity distribution program.

2023 Compared to 2022

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow Activity” in Item 7 of Entergy’s Annual Report on Form 10-K for the year ended December 31, 2023, filed with the SEC on February 23, 2024, for discussion of operating, investing, and financing cash flow activities for 2023 compared to 2022.

Rate, Cost-recovery, and Other Regulation

State and Local Rate Regulation and Fuel-Cost Recovery

The rates that the Utility operating companies charge for their services significantly influence Entergy’s financial position, results of operations, and liquidity. These companies are regulated, and the rates charged to their customers are determined in regulatory proceedings. Governmental agencies, including the APSC, the LPSC, the MPSC, the City Council, and the PUCT, are primarily responsible for approval of the rates charged to customers. Following is a summary of the Utility operating companies’ authorized returns on common equity:

Rate regulation and related regulatory proceedings and fuel and purchased power cost recovery proceedings for the Utility operating companies are discussed in Note 2 to the financial statements.

Federal Regulation

The FERC regulates wholesale sales of electricity rates and interstate transmission of electricity, including rates for 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. The current return on equity under the Unit Power Sales Agreement is 9.65%. See Note 2 and Note 8 to the financial statements for discussion of Entergy Louisiana’s divestiture from the Unit Power Sales Agreement.

Market and Credit Risk Sensitive Instruments

Market risk is the risk of changes in the value of commodity and financial instruments, or in future net income or cash flows, in response to changing market conditions. Entergy holds commodity and financial instruments that are exposed to the following significant market risks:

•The commodity price risk associated with the sale of electricity by Entergy’s non-utility operations business.

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•The interest rate and equity price risk associated with Entergy’s investments in qualified pension and other postretirement benefits trust funds. See Note 11 to the financial statements for details regarding Entergy’s qualified pension and other postretirement benefits trust funds.

•The interest rate and equity price risk associated with Entergy’s investments in nuclear plant decommissioning trust funds. See Note 16 to the financial statements for details regarding Entergy’s decommissioning trust funds.

•The interest rate risk associated with changes in interest rates as a result of Entergy’s outstanding indebtedness. Entergy manages its interest rate exposure by monitoring current interest rates and its debt outstanding in relation to total capitalization. See Notes 4 and 5 to the financial statements for the details of Entergy’s debt outstanding.

The Utility has limited exposure to the effects of market risk because it operates primarily under cost-based rate regulation. To the extent approved by their retail regulators, the Utility operating companies use commodity and financial instruments to hedge the exposure to price volatility inherent in their purchased power, fuel, and gas purchased for resale costs that are recovered from customers.

Entergy’s commodity and financial instruments are also exposed to credit risk. Credit risk is the risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement. Entergy is also exposed to a potential demand on liquidity due to credit support requirements within its supply or sales agreements.

Some of the agreements to sell the power produced by Entergy’s non-utility operations business contain provisions that require an Entergy subsidiary to provide credit support to secure its obligations under such agreement. The primary form of credit support used to satisfy these requirements is an Entergy Corporation guarantee.  Cash and letters of credit are also acceptable forms of credit support. At December 31, 2024, based on power prices at that time, Entergy had liquidity exposure of $5 million under the guarantees in place supporting its non-utility operations business transactions and $3 million of posted cash collateral.

In addition, each of the Utility operating companies has uncommitted standby letter of credit facilities as a means to post collateral to support its obligations to MISO and for other purposes. See Note 4 to the financial statements for discussion of these letter of credit facilities.

Nuclear Matters

Entergy’s Utility business includes the ownership and operation of nuclear generating plants and is, therefore, subject to the risks related to such ownership and operation. These include risks related to: the use, storage, and handling and disposal of high-level and low-level radioactive materials; the substantial financial requirements, both for capital investments and operational needs, including the financial requirements to address emerging issues related to equipment reliability, to position Entergy’s nuclear fleet to meet its operational goals; the performance and capacity factors of these nuclear plants; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license amendments, and decommissioning; the availability of interim or permanent sites for the disposal of spent nuclear fuel and nuclear waste, including the fees charged for such disposal; the sufficiency of nuclear decommissioning trust fund assets and earnings to complete decommissioning of each site when required; and limitations on the amounts of insurance recoveries for losses in connection with nuclear plant operations and catastrophic events such as a nuclear accident.

NRC Reactor Oversight Process

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

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

Critical Accounting Estimates

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

Nuclear Decommissioning Costs

Certain of the Utility operating companies and System Energy own nuclear generation facilities. Regulations require these Entergy subsidiaries to decommission the nuclear power plants after each facility is taken out of service, and cash is deposited in trust funds during the facilities’ operating lives in order to provide for this obligation. Entergy conducts periodic decommissioning cost studies to estimate the costs that will be incurred to decommission the facilities. The following key assumptions have a significant effect on these estimates.

•Timing - In projecting decommissioning costs, two assumptions must be made to estimate the timing of plant decommissioning. First, the date of the plant’s retirement must be estimated for those plants that do not have an announced shutdown date. The estimate may include assumptions regarding the possibility that the plant may have an operating life shorter than the operating license expiration. Second, an assumption must be made regarding whether all decommissioning activity will proceed immediately upon plant retirement, or whether the plant will be placed in SAFSTOR status. SAFSTOR is decommissioning a facility by placing it in a safe, stable condition that is maintained until it is subsequently decontaminated and dismantled to levels that permit license termination, normally within 60 years from permanent cessation of operations. A change of assumption regarding either the period of continued operation, the use of a SAFSTOR period, or whether Entergy will continue to hold the plant or the plant is held for sale can change the present value of the asset retirement obligation.

•Cost Escalation Factors - Entergy’s current decommissioning cost studies include an assumption that decommissioning costs will escalate over present cost levels by factors ranging from approximately 2% to 3% annually. A 50-basis point change in this assumption could change the estimated present value of the decommissioning liabilities by approximately 8% to 15%. The timing assumption influences the significance of the effect of a change in the estimated inflation or cost escalation rate because the effect increases with the length of time assumed before decommissioning activity ends.

•Spent Fuel Disposal - Federal law requires the DOE to provide for the permanent storage of spent nuclear fuel, and legislation has been passed by Congress to develop a repository at Yucca Mountain, Nevada. The DOE has not yet begun accepting spent nuclear fuel and is in non-compliance with federal law. The DOE continues to delay meeting its obligation and Entergy’s nuclear plant owners are continuing to pursue damage claims against the DOE for its failure to provide timely spent fuel storage. Until a federal site is available, however, nuclear plant operators must provide for interim spent fuel storage on the nuclear plant site, which can require the construction and maintenance of dry cask storage sites or other facilities. The costs of developing and maintaining these facilities during the decommissioning period can have a

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significant effect (as much as an average of 20% to 30% of total estimated decommissioning costs). Entergy’s decommissioning studies include cost estimates for spent fuel storage. These estimates could change in the future, however, based on the expected timing of when the DOE begins to fulfill its obligation to receive and store spent nuclear fuel. See Note 8 to the financial statements for further discussion of Entergy’s spent nuclear fuel litigation.

•Technology and Regulation - Over the past several years, more practical experience with the actual decommissioning of nuclear facilities has been gained and that experience has been incorporated into Entergy’s current decommissioning cost estimates. Given the long duration of decommissioning projects, additional experience, including technological advancements in decommissioning, could be gained and affect current cost estimates. In addition, if regulations regarding nuclear decommissioning were to change, this could affect cost estimates.

•Interest Rates - The estimated decommissioning costs that are the basis for the recorded decommissioning liability are discounted to present value using a credit-adjusted risk-free rate. When the decommissioning liability is revised, increases in cash flows are discounted using the current credit-adjusted risk-free rate. Decreases in estimated cash flows are discounted using the credit-adjusted risk-free rate used previously in estimating the decommissioning liability that is being revised. Therefore, to the extent that a revised cost study results in an increase in estimated cash flows, a change in interest rates from the time of the previous cost estimate will affect the calculation of the present value of the revised decommissioning liability.

Revisions of estimated decommissioning costs that decrease the liability also result in a decrease in the asset retirement cost asset. Revisions of estimated decommissioning costs that increase the liability result in an increase in the asset retirement cost asset, which is then depreciated over the asset’s remaining economic life. See Note 9 to the financial statements for further discussion of asset retirement obligations.

Utility Regulatory Accounting

Entergy’s Utility operating companies and System Energy are subject to retail regulation by their respective state and local regulators and to wholesale regulation by the FERC. Because these regulatory agencies set the rates the Utility operating companies and System Energy are allowed to charge customers based on allowable costs, including a reasonable return on equity, the Utility operating companies and System Energy apply accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery from customers through regulated rates. Regulatory liabilities represent (1) revenue or gains that have been deferred because it is probable such amounts will be credited to customers through future regulated rates or (2) billings in advance of expenditures for approved regulatory programs. See Note 2 to the financial statements for a discussion of rate and regulatory matters, including details of Entergy’s and the Registrant Subsidiaries’ regulatory assets and regulatory liabilities.

For each regulatory jurisdiction in which they conduct business, the Utility operating companies and System Energy assess whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. If the assessments made by the Utility operating companies and System Energy are ultimately different than actual regulatory outcomes, it could materially affect the results of operations, financial position, and cash flows of Entergy or the Registrant Subsidiaries.

Taxation and Uncertain Tax Positions

Management exercises significant judgment in evaluating the potential tax effects of Entergy’s operations, transactions, and other events. Entergy accounts for uncertain income tax positions using a recognition model under a two-step approach with a more likely-than-not recognition threshold and a measurement approach based on the

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largest amount of tax benefit that is greater than 50% likely of being realized upon settlement. Management evaluates each tax position based on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant judgment is required to determine whether available information supports the assertion that the recognition threshold has been met. Additionally, measurement of unrecognized tax benefits to be recorded in the consolidated financial statements is based on the probability of different potential outcomes. Income tax expense and tax positions recorded could be significantly affected by events such as additional transactions contemplated or consummated by Entergy as well as audits by taxing authorities of the tax positions taken in transactions. Management believes that the financial statement tax balances are accounted for and adjusted appropriately each quarter, as necessary, in accordance with applicable authoritative guidance; however, the ultimate outcome of tax matters could result in favorable or unfavorable effects on the consolidated financial statements.

Certain Entergy subsidiaries have elected to apply the mark-to-market method of accounting for income tax return purposes to wholesale power purchase agreements as appropriate under the Internal Revenue Code and U.S. Treasury Regulations. The mark-to-market tax gain or loss computed each year is based on an estimated fair market valuation which includes analyses of market prices and conditions. Entergy’s and the Registrant Subsidiaries’ mark-to-market tax position could be affected by the outcome of federal and state income tax audits should taxing authorities challenge such valuations.

Entergy’s income taxes, including unrecognized tax benefits, open audits, and other significant tax matters, are discussed in Note 3 to the financial statements. See “Income Tax Legislation and Regulation” above for discussion of income tax legislation and regulation.

Qualified Pension and Other Postretirement Benefits

Entergy sponsors qualified, defined benefit pension plans, including cash balance plans and final average pay plans. Generally, plan participation is determined based on the employee’s most recent date of hire and collective bargaining agreement, where applicable. Additionally, Entergy currently provides other postretirement health care and life insurance benefits for full-time employees whose most recent date of hire or rehire is before July 1, 2014, and who reach retirement age and meet certain eligibility requirements while still working for Entergy.

Entergy’s reported costs of providing these benefits, as described in Note 11 to the financial statements, are affected by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate for Entergy and the Registrant Subsidiaries.

Assumptions

Key actuarial assumptions utilized in determining qualified pension and postretirement health care and life insurance costs include discount rates, projected healthcare cost rates, expected long-term rate of return on plan assets, rate of increase in future compensation levels, retirement rates, expected timing and form of payments, and mortality rates.

Annually, Entergy reviews and, when necessary, adjusts the assumptions for the qualified pension and other postretirement plans. Every three-to-five years, a formal actuarial assumption experience study that compares assumptions to the actual experience of the qualified pension and postretirement health care and life insurance plans is conducted. The interest rate environment over the past few years and volatility in the financial equity markets have affected Entergy’s funding and reported costs for these benefits.

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Discount rates

In selecting an assumed discount rate to calculate benefit obligations, Entergy uses a yield curve based on high-quality corporate debt with cash flows matching the expected plan benefit payments. In estimating the service cost and interest cost components of net periodic benefit cost, Entergy discounts the expected cash flows by the applicable spot rates.

Projected health care cost trend rates

Entergy’s health care cost trend is affected by both medical cost inflation and, with respect to capped costs under the plan, the effects of general inflation. Entergy reviews actual recent cost trends and projected future trends in establishing its health care cost trend rates.

Expected long-term rate of return on plan assets

In determining its expected long-term rate of return on plan assets used in the calculation of benefit plan costs, Entergy reviews past performance, current and expected future asset allocations, and capital market assumptions of its investment consultant and some of its investment managers. Entergy conducts periodic asset/liability studies in order to set its target asset allocations.

In 2023, Entergy implemented a new asset allocation strategy for its pension assets, based on the funded status of each plan within the trust. The new strategy no longer focuses on targeting an overall asset allocation for the trust, but rather a target asset allocation for each plan within the trust that adjusts dynamically based on the funded status. The ultimate asset allocation for each plan is expected to be attained when the plan is 110% funded. The 2024 weighted-average target pension asset allocation is 35% equity and 65% fixed income securities, of which 61% is long duration fixed income.

In 2017, Entergy implemented a new asset allocation strategy for its non-taxable and taxable other postretirement assets, based on the funded status of each sub-account within each trust. The new strategy no longer focuses on targeting an overall asset allocation for each trust, but rather a target asset allocation for each sub-account within each trust that adjusts dynamically based on the funded status. This strategy was reaffirmed based upon an asset/liability study in 2024. The 2024 weighted-average target postretirement asset allocation is 24% equity and 76% fixed income securities.

See Note 11 to the financial statements for discussion of the current asset allocations for Entergy’s pension and other postretirement assets.

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Costs and Sensitivities

The estimated 2025 and actual 2024 qualified pension and other postretirement costs and related underlying assumptions and sensitivities are shown below:

(a)    In 2024, qualified pension cost included settlement costs of $328 million.

Actual asset returns have an effect on Entergy’s qualified pension and other postretirement costs. In 2024, Entergy’s actual annual return on qualified pension assets was approximately 6.7% and on other postretirement assets was approximately 7%, as compared to the 2024 expected long-term rates of return discussed above.

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

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

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

Accounting Mechanisms

In accordance with pension accounting standards, Entergy utilizes a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are amortized into expense only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees. If almost all of the plan participants are inactive, as is the case for certain qualified pension plans, the excess is amortized over the remaining life expectancy of plan participants. Additionally, accounting standards allow for the deferral of prior service costs/credits arising from plan amendments that attribute an increase or decrease in benefits to employee service in prior periods. Prior service costs/credits are then amortized into expense over the average future working life of active employees. Certain decisions, including workforce reductions, plan amendments, and plant shutdowns, may significantly reduce the expense amortization period and result in immediate recognition of certain previously-deferred costs and gains/losses in the form of curtailment gains or losses. Similarly, payments made to settle benefit obligations, including lump sum benefit payments, can also result in accelerated recognition in the form of settlement losses or gains. Several Entergy subsidiaries received regulatory approval to defer the expense portion of settlement charges and amortize into expense over time. See Note 11 to the financial statements for further discussion.

Entergy calculates the expected return on pension and other postretirement benefits plan assets by multiplying the long-term expected rate of return on assets by the market-related value (MRV) of plan assets. Entergy determines the MRV of its pension plan assets, except for the long duration fixed income assets, by calculating a value that uses a 20-quarter phase-in of the difference between actual and expected returns. For the long duration fixed income assets in the pension trust and for its other postretirement benefits plan assets, Entergy uses fair value as the MRV.

Accounting standards require an employer to recognize in its balance sheet the funded status of its benefit plans. See Note 11 to the financial statements for further discussion of Entergy’s funded status.

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Employer Contributions

Entergy contributed $270 million to its qualified pension plans in 2024. Entergy estimates pension contributions will be approximately $240 million in 2025 although the 2025 required pension contributions will be known with more certainty when the January 1, 2025, valuations are completed, which is expected by April 1, 2025.

Minimum required funding calculations as determined under Pension Protection Act guidance, as amended by the American Rescue Plan Act of 2021, are performed annually as of January 1 of each year and are based on measurements of the assets and funding liabilities as measured at that date. Any excess of the funding liability over the calculated fair market value of assets results in a funding shortfall that must be funded over a fifteen-year rolling period. The Pension Protection Act also imposes certain plan limitations if the funded percentage, which is based on calculated fair market values of assets divided by funding liabilities, does not meet certain thresholds. For funding purposes, asset gains and losses are smoothed into the calculated fair market value of assets. The funding liability is based upon a weighted-average 24-month corporate bond rate published by the U.S. Treasury which is generally subject to a corridor of the 25-year average of prior segment rates. Periodic changes in asset returns and interest rates can affect funding shortfalls and future cash contributions.

Entergy contributed $45.4 million to its other postretirement plans in 2024 and plans to contribute $42.8 million in 2025.

Other Contingencies

As a company with multi-state utility operations, Entergy is subject to a number of federal and state laws and regulations and other factors and conditions in the areas in which it operates, which potentially subjects it to environmental, litigation, and other risks. Entergy periodically evaluates its exposure for such risks and records a provision for those matters which are considered probable and estimable in accordance with GAAP.

Environmental

Entergy must comply with environmental laws and regulations applicable to air emissions, water discharges, solid waste (including coal combustion residuals), hazardous waste, toxic substances, protected species, and other environmental matters. Under these various laws and regulations, Entergy could incur substantial costs to comply or address any impacts to the environment. Entergy conducts studies to determine the extent of any required remediation and has recorded liabilities based upon its evaluation of the likelihood of loss and expected dollar amount for each issue. Additional sites or issues could be identified which require environmental remediation or corrective action for which Entergy could be liable. The amounts of environmental liabilities recorded can be significantly affected by the following external events or conditions.

•Changes to existing federal, state, or local regulation or related policies by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters.

•The identification of additional impacts, sites, issues, or the filing of other complaints in which Entergy may be asserted to be a potentially responsible party.

•The resolution or progression of existing matters through the court system or resolution by the EPA or relevant state or local authority.

Litigation

Entergy is regularly named as a defendant in a number of lawsuits involving employment, customers, and injuries and damages issues, among other matters. Entergy periodically reviews the cases in which it has been named as defendant and assesses the likelihood of loss in each case as probable, reasonably possible, or remote and records liabilities for cases that have a probable likelihood of loss and the loss can be estimated. Given the

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Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

environment in which Entergy operates, and the unpredictable nature of many of the cases in which Entergy is named as a defendant, the ultimate outcome of the litigation to which Entergy is exposed has the potential to materially affect the results of operations, financial position, and cash flows of Entergy or the Registrant Subsidiaries.

New Accounting Pronouncements

See Note 1 to the financial statements for discussion of new accounting pronouncements.

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ENTERGY CORPORATION AND SUBSIDIARIES