ML25085A211

Decommissioning Funding Status Report Per 10 CFR 50.75(f)(1) - Entergy Operations, Inc

ML25085A211
Person / Time
Site:	Grand Gulf, Arkansas Nuclear, River Bend, Waterford
Issue date:	03/26/2025
From:	Couture P Entergy Operations
To:	Office of Nuclear Reactor Regulation, Document Control Desk
References
CNRO2025-00004
Download: ML25085A211 (1)

Text

Phil Couture Senior Manager Fleet Regulatory Assurance - Licensing 601-368-5102 Entergy Operations, Inc., 1340 Echelon Parkway, Jackson, MS 39213 CNRO2025-00004 10 CFR 50.75(f)(1)

March 26, 2025 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, DC 20555-0001

Subject:

Decommissioning Funding Status Report per 10 CFR §50.75(f)(1) - Entergy Operations, Inc.

Arkansas Nuclear One, Units 1 & 2 Docket Nos. 50-313 & 50-368 License Nos. DPR-51 & NPF-6 Grand Gulf Nuclear Station, Unit 1 Docket No. 50-416 License No. NPF-29 River Bend Station, Unit 1 Docket No. 50-458 License No. NPF-47 Waterford 3 Steam Electric Station Docket No. 50-382 License No. NPF-38 10 CFR 50.75(f)(1) requires each power reactor licensee to report to the United States Nuclear Regulatory Commission (NRC) by March 31, 1999, and every two years thereafter, on the status of its decommissioning funding for each reactor, or share of a reactor, that it owns. On behalf of Entergy Arkansas, LLC for Arkansas Nuclear One (ANO), System Entergy Resources, Inc. (SERI) and Cooperative Energy (formerly South Mississippi Electric Power Association (SMEPA)) for Grand Gulf Nuclear Station (GGNS), Entergy Louisiana, LLC for River Bend Station (RBS) and Waterford 3 Steam Electric Station (WF3), Entergy Operations, Inc. hereby submits the information requested for power reactors operated by Entergy Operations, Inc.

The estimated minimum decommissioning fund values were determined using the NRCs methodology in NUREG-1307, Rev 20.

The 70 percent regulated interest of RBS contains funds accumulated for separate rate regulatory jurisdictions. There are not separate trust funds for the individual jurisdictions responsible for decommissioning of the 70 percent regulated share of RBS. Balances in the nuclear decommissioning trust for the 70 percent regulated share of RBS attributable to the separate jurisdictions are accounted for by the Trustee, The Bank of New York Mellon. The following information provides the balances in the 70 percent regulated share trust attributable to each of the relevant jurisdictions as of December 31, 2024:

CNRO2025-00004 Page 2 of 4 Louisiana

$401,838,238 Texas

$379,399,601 FERC

$ 21,232,232 The trust fund amounts reported for each facility in the responses to item 3 in the attachments represent the market value of decommissioning trust funds as of December 31, 2024 net of any material current income tax liability on realized gains, interest, dividends and other income of the trusts. Cooperative Energy is a not-for-profit electric cooperative, and is exempt from federal income tax. Accordingly, the amounts reported as of December 31, 2024 of funds separately accumulated by Cooperative Energy for GGNS decommissioning were after-tax amounts. The trusts for the following plants had balances on their 2024 tax liabilities (in thousands), not reflected in the trust fund balances, as follows (does not include Cooperative Energy):

ANO $ 0 GGNS $ 0 RBS

$ 0 WF3

$ 0 In accordance with guidance provided by the NRC Staff in April 2014 requests for additional information (Accession No. ML14120A273) that "[f]uture 10 CFR 50.75(f) reports should clearly delineate estimated reactor and ISFSI decommissioning costs," the information in Attachments 1-4 includes line item 2 identifying the ISFSI decommissioning obligation, from the most recent 10 CFR 72.30 filing. This obligation is also accounted for in the Excess/Shortfall calculations for each plant in Attachment 5.

The information provided in Attachments 1-4 is based on NRC Regulatory Issue Summary 2001-07. Consistent with your letter dated March 11, 2011 (Accession No. ML110280410),

we are providing with this submittal or incorporating by reference certain agreements providing for original (not resale) nuclear plant power sales (that may, from time to time, include decommissioning collections) between Entergy operating companies that invoke Federal Energy Regulatory Commission (FERC) tariffs. Considering these agreements and the applicable NRC regulations, Entergy respectfully asserts that these rate-making tariffs should not be viewed as "contractual obligations" as that term is used within 10 CFR 50.75(e)(1)(v).

These arrangements describe exchanges among regulated utilities that operate within the confines of a FERC-approved tariff, under the ratemaking jurisdiction of the FERC. As such, the various agreements are simply extensions of the FERC tariff and not the type of "contractual obligations" contemplated by 10 CFR 50.75(e)(1)(v), and Entergys decommissioning funding is still provided by the external sinking fund method in accordance with 10 CFR 50.75(e)(1)(ii). In an abundance of caution and in a spirit of cooperation, however, Entergy is providing or incorporating various tariff agreements for each affected plant.

Additionally, Attachment 5 includes Minimum Funding Assurance calculation worksheets (not required for this filing) derived from Datasheet 4 of LIC-205 Revision 6 for the plants, provided for the convenience of the reviewer.

The aforementioned worksheets, using the December 31, 2024 trust fund balances, indicate that all of the plants covered by this submittal met or exceeded the NRCs funding requirements.

This submittal contains no new regulatory commitments. Should you have any questions or require additional information, please contact me at 601-368-5102.

CNRO2025-00004 Page 3 of 4 Respectfully, Phil Couture PC/LJS/chm

References:

1) NUREG-1307, "Report on Waste Burial Charges," Revision 20, dated February 2025.

2) NRC Regulatory Issue Summary 2001-07, "10 CFR 50.75(f)(1) Reports on the Status of Decommissioning Funds (Due March 31, 2001)."

Attachments:

1 Entergy Arkansas, LLC - ANO 1 & 2 Status Reports 1-A Entergy Arkansas, LLC - Calculation of Minimum Amount 2

SERI & Cooperative Energy - GGNS Status Report 2-A SERI & Cooperative Energy - Calculation of Minimum Amount 2-B SERI Unit Power Sales Agreement - Rate Schedule FERC No. 2 3

Entergy Louisiana, LLC RBS Status Report - 70% Regulated 3-A Entergy Louisiana, LLC - Calculation of Minimum Amount 3-B Entergy Louisiana, LLC RBS Status Report - 30% Non-Regulated 4

Entergy Louisiana, LLC - Waterford 3 Status Report 4-A Entergy Louisiana, LLC - Calculation of Minimum Amount 4-B Entergy Louisiana, LLC - Waterford 3 Purchase Power Agreement 5

Minimum Funding Assurance Calculation Worksheets Digitally signed by Philip Couture DN: cn=Philip Couture, o=Entergy, ou=Regulatory Assurance, email=pcoutur@entergy.com Date: 2025.03.26 07:33:06 -05'00' Philip Couture

CNRO2025-00004 Page 4 of 4 cc:

NRC Region IV Regional Administrator NRC Senior Resident Inspector - ANO, GGNS, RBS, WF3 NRC Project Manager - ANO, GGNS, RBS, WF3 Arkansas Department of Health Mississippi Department of Health Louisiana Department of Environmental Quality

CNRO2025-00004 Entergy Arkansas, LLC - ANO 1 & 2 Status Reports

CNRO2025-00004 Page 1 of 2 ENTERGY ARKANSAS, LLC Status Report of Decommissioning Funding For Year Ending December 31, 2024 - 10 CFR 50.75(f)(1)

Plant Name: Arkansas Nuclear One Unit 1 (ANO 1)

1. Minimum Financial Assurance (MFA)

Estimated per 10 CFR 50.75(b) and (c) (2024$):

$510.8 million1

2. ISFSI Obligation as of 12/31/24

$7.6 million2

3. Decommissioning Trust Fund Total As of 12/31/24:

$878.5 million

4. Annual amounts remaining to be collected:

$03

5. Assumptions used in determining rates of escalation in decommissioning costs, rates of earnings on decommissioning funds, and rates of other factors used in funding projections 2% annual real rate of return per 10 CFR 50.75(e)(1)(i)

6. Contracts upon which licensee is relying For Decommissioning Funding:

See Footnote4

7. Modifications to Method of Financial Assurance since Last Report:

None

8. Material Changes to Trust Agreements:

None 1

See Attachment 1-A 2

From Entergys ISFSI Decommissioning Funding Plans Pursuant to 10 CFR 72.30, December 05, 2024 (Accession No. ML24340A243). The ISFSI obligation is shared equally between ANO 1 and ANO 2.

3 Decommissioning funding has been suspended by the Arkansas Public Service Commission in Docket No. 87-166-TF. The NRC has granted license renewal to May 20, 2034.

4 See the agreements provided as Attachment 1-C in the decommissioning financial assurance filing dated March 28, 2019, NRC Accession No. ML19087A327, incorporated herein by reference. The licensee believes these contracts do not qualify as contractual obligations, but rather are simply cost of service recovery mechanisms as defined in 10 CFR §50.75(e)(1)(ii)(A). Out of an abundance of caution, the licensee identifies this information here. By FERC Order dated March 21, 2019, these agreements were modified to substitute Entergy Arkansas, LLC for Entergy Arkansas, Inc. The amended agreements were accepted by FERC in a letter order dated March 21, 2019.

CNRO2025-00004 Page 2 of 2 ENTERGY ARKANSAS, LLC Status Report of Decommissioning Funding For Year Ending December 31, 2024 - 10 CFR 50.75(f)(1)

Plant Name: Arkansas Nuclear One Unit 2 (ANO 2)

1. Minimum Financial Assurance (MFA)

Estimated per10 CFR 50.75(b) and (c) (2024$):

$531.9 million5

2. ISFSI Obligation as of 12/31/24

$7.6 million6

3. Decommissioning Fund Total As of 12/31/24:

$726.0 million

4. Annual amounts remaining to be collected:

$07

5. Assumptions used in determining rates of escalation in decommissioning costs, rates of earnings on decommissioning funds, and rates of other factors used in funding projections:

2% annual real rate of return per 10 CFR 50.75(e)(1)(i)

6. Contracts upon which licensee is relying See Footnote8 For Decommissioning Funding:

7. Modifications to Method of Financial Assurance since Last Report:

None

8. Material Changes to Trust Agreements:

None 5

See Attachment 1-A 6

From Entergys ISFSI Decommissioning Funding Plans Pursuant to 10 CFR 72.30, December 05, 2024 (Accession No. ML24340A243). The ISFSI obligation is shared equally between ANO 1 and ANO 2.

7 Decommissioning funding has been suspended by the Arkansas Public Service Commission in Docket No. 87-166-TF. The NRC has granted license renewal to July 17, 2038.

8 See the agreements provided as Attachment 1-C in the decommissioning financial assurance filing dated March 28, 2019, NRC Accession No. ML19087A327, incorporated herein by reference. The licensee believes these contracts do not qualify as contractual obligations, but rather are simply cost of service recovery mechanisms as defined in 10 CFR §50.75(e)(1)(ii)(A). Out of an abundance of caution, the licensee identifies this information here. By FERC Order dated March 21, 2019, these agreements were modified to substitute Entergy Arkansas, LLC for Entergy Arkansas, Inc. The amended agreements were accepted by FERC in a letter order dated March 21, 2019.

-A CNRO2025-00004 Entergy Arkansas, LLC - Calculation of Minimum Amount Arkansas Nuclear One Units 1 and 2

CNRO2025-00004 -A Page 1 of 1 ENTERGY ARKANSAS, LLC Calculation for Minimum Amount - ANO For Year Ending December 31, 2024 - 10 CFR 50.75(f)(1)

Entergy Arkansas, Inc.:

100% ownership interest Plant Location:

Russellville, Arkansas Reactor Type:

Pressurized Water Reactor ("PWR")

ANO Unit 1 Power Level:

<3,400 MWt (2,568 MWt)

ANO Unit 1 PWR Base Year 1986$:

$97,598,400 ANO Unit 2 Power Level:

<3,400 MWt (3,026 MWt)

ANO Unit 2 PWR Base Year 1986$:

$101,628,800 Labor Region:

South Waste Burial Facility:

Generic Disposal Site 10 CFR 50.75(c)(2) Escalation Factor Formula:

0.65(L) +0.13(E) +0.22(B)

Factor L=Labor (South) 3.279 E=Energy (PWR) 2.9210 B=Waste Burial-Vendor (PWR) 12.40511 PWR Escalation Factor:

0.65(L) +0.13(E) +0.22(B)=

5.23 1986 PWR Base Year $ Escalated:

ANO1: $97,598,400

• Factor=

$510,849,545 ANO2: $101,628,800

• Factor=

$531,945,465 9

Bureau of Labor Statistics, Series Report ID: CIU2010000000220i (4th Quarter 2024) 10 Bureau of Labor Statistics, Series Report ID: wpu0543 and wpu0573 (December 2024) 11 Nuclear Regulatory Commission: NUREG-1307 Revision 20, Table 2-1 (2024)

CNRO2025-00004 SERI & Cooperative Energy - GGNS Status Report

CNRO2025-00004 Page 1 of 1 SYSTEM ENERGY RESOURCES, INC. and COOPERATIVE ENERGY Status Report of Decommissioning Funding For Year Ending December 31, 2024 - 10 CFR 50.75(f)(1)

Plant Name: Grand Gulf Station (Owned & leased 90% by System Energy Resources, Inc. (SERI) and 10% by Cooperative Energy)

1. Minimum Financial Assurance (MFA)

Estimated per 10 CFR 50.75(b) and (c) (2024$):

SERI (90% ownership share)

$616.5 million12 Cooperative Energy (10% ownership share)

$68.5 million

2. ISFSI Obligation as of 12/31/2413 SERI

$11.31 million Cooperative Energy

$1.26 million

3. Decommissioning Fund Total as of 12/31/24:

SERI

$1,529.1 million Cooperative Energy

$135.3 million

4. Annual amounts remaining to be collected:

None

5. Assumptions used:

Rate of Escalation of Decommissioning Costs:

SERI See item below Cooperative Energy 3.0%

Rate of Earnings on Decommissioning Funds:

SERI 2% real rate of return per 10 CFR 50.75(e)(1)(i)

Cooperative Energy Approx. 2.91%14 Authority for use of Real Earnings Over 2%:

SERI N/A Cooperative Energy Cooperative Energy Board

6. Contracts upon which licensee is relying For Decommissioning Funding:

See Footnote15

7. Modifications to Method of Financial Assurance since Last Report:

None

8. Material Changes to Trust Agreements:

SERI None Cooperative Energy None 12 See Attachment 2-A 13 From Entergys ISFSI Decommissioning Funding Plans Pursuant to 10 CFR 72.30, December 05, 2024 (Accession No. ML24340A243).

14 Established by Cooperative Energy board resolution. A copy of that resolution was previously provided in the licensees March 27, 2015 decommissioning financial assurance filing as Attachment 2-C, Accession No. ML15092A183, and is incorporated herein by reference.

15 For SERI, see the Unit Power Sales Agreement, Rate Schedule FERC. No. 2, in Attachment 2-B below. It is the licensees position that this agreement is not 10 CFR §50.75(e)(1)(v) contractual obligations, but rather a cost of service tariff which may appropriately be used to fund the external sinking fund in accordance with 10 CFR §50.75(e)(1)(ii). Out of abundance of caution, the licensee identifies this information here.

-A CNRO2025-00004 SERI & Cooperative Energy - Calculation of Minimum Amount

CNRO2025-00004 -A Page 1 of 1 SYSTEM ENERGY RESOURCES, INC. and COOPERATIVE ENERGY Calculation for Minimum Amount For Year Ending December 31, 2024 - 10 CFR 50.75(f)(1)

System Energy Resources, Inc.:

90% ownership/leasehold interest Cooperative Energy:

10% ownership interest Plant Location:

Port Gibson, Mississippi Reactor Type:

Boiling Water Reactor ("BWR")

Power Level:

>3,400 MWt BWR Base Year 1986$:

$135,000,000 Labor Region:

South Waste Burial Facility:

Generic Disposal Site 10 CFR 50.75(c)(2) Escalation Factor Formula:

0.65(L) +0.13(E) +0.22(B)

Factor L=Labor (South) 3.2716 E=Energy (BWR) 2.9517 B=Waste Burial-Vendor (BWR) 11.65818 BWR Escalation Factor:

0.65(L) +0.13(E) +0.22(B)=

5.073 1986 BWR Base Year $ Escalated:

$135,000,000* Factor=

$684,957,600 System Energy interest (90%):

$616,461,840 Cooperative Energy interest (10%):

$ 68,495,760 Total

$684,957,600 16 Bureau of Labor Statistics, Series Report ID: CIU2010000000220i (4th Quarter 2024) 17 Bureau of Labor Statistics, Series Report ID: wpu0543 and wpu0573 (December 2024) 18 Nuclear Regulatory Commission: NUREG-1307 Revision 20, Table 2-1 (2024)

-B CNRO2025-00004 SERI Unit Power Sales Agreement - Rate Schedule FERC No. 2

FILING PUBLIC UTILITY System Energy Resources, Inc.

Rate Schedule FERC No. 2 PUBLIC UTILITIES RECEIVING SERVICE UNDER RATE SCHEDULE Entergy Arkansas, LLC Entergy Louisiana, LLC Entergy Mississippi, LLC Entergy New Orleans, LLC SERVICE TO BE PROVIDED UNDER RATE SCHEDULE Wholesale Sale of Electric Power CNRO2025-00004 -B Page 1 of 31

Unit Power Sales Agreement THIS AGREEMENT, made, entered into, and effective as of this 10th day of June, 1982, as amended from time to time thereafter, and as revised to comply with Federal Energy Regulatory Commission (FERC) Opinion Nos. 446 and 446-A and FERC Order No.614, between and among Entergy Arkansas, LLC (EAL), Entergy Louisiana, LLC (ELL),

Entergy Mississippi, LLC (EML), Entergy New Orleans, LLC (ENOL) and System Energy Resources, Inc. (System Energy).

WITNESSETH THAT:

WHEREAS, System Energy was incorporated on February 11, 1974 under the laws of the State of Arkansas to own certain future generating capacity for the Entergy System, of which EAL, ELL, EML and ENOL (System Companies) are members; and WHEREAS, System Energy has accordingly undertaken the ownership and financing of an undivided interest in, and construction of, the Grand Gulf Generating Station, a one-unit, nuclear-fueled electric generating station on the east bank of the Mississippi River near Port Gibson, Mississippi (Project); and WHEREAS, the System Companies own and operate electric generating, transmission and distribution facilities in Arkansas, Louisiana and Mississippi and generate, transmit and sell electric energy both at retail and wholesale in such states; and WHEREAS, System Energy has agreed to sell to EAL, ELL, EML and ENOL (Purchasers) specified percentages of all of the capacity and energy available to System Energy from the Project, and the System Companies have agreed to join with System Energy, before the date Unit I of the Project is placed in service, in executing an agreement which will set forth in detail the terms and conditions for the sale of such capacity and energy by System Energy to the System Companies; and WHEREAS, Unit 1 is expected to be placed in commercial operation in the first quarter of 1983; NOW, THEREFORE, System Energy and the System Companies mutually understand and agree as follows:

1.1 System Energy shall, subject to the terms and conditions of this Agreement, make available, or cause to be made available, to the Purchasers all of the capacity and energy which shall be available to System Energy at the Project, including test energy produced during the course of the construction and testing of Unit 1 of the Project (Power).

1.2 The Purchasers shall, subject to the terms and conditions of this Agreement, be entitled to receive all of the Power which shall be available to System Energy at the Project in accordance with their respective Entitlement Percentages. The Entitlement Percentages are as follows:

CNRO2025-00004 -B Page 2 of 31

3 Entitlement Percentages Unit No. 1 EAL 36%

ELL 14%

EML 33%

ENOL 17%

100%

1.3 Commencing with the earlier of (a) the date of commercial operation of the Unit or (b) December 31, 1984 and continuing monthly thereafter until this Agreement is terminated pursuant to the provisions of Section 9 hereof, in consideration of the right to receive its Entitlement Percentage of such Power from the unit, each Purchaser will pay System Energy an amount determined pursuant to the Monthly Grand Gulf Power Charge Formula, which is attached hereto as Appendix 1.

2.

The performance of the obligations of System Energy hereunder shall be subject to the receipt and continued effectiveness of all authorizations of governmental regulatory authorities at the time necessary to permit System Energy to perform its duties and obligations hereunder, including the receipt and continued effectiveness of all authorizations by governmental regulatory authorities at the time necessary to permit the completion by System Energy of the construction of the Project, the operation of the Project, and for System Energy to make available to the Purchasers all of the Power available to System Energy at the Project.

System Energy shall use its best efforts to secure and maintain all such authorizations by governmental regulatory authorities.

3.

System Energy shall operate and maintain the Project in accordance with good utility practice. Outages for inspection, maintenance, refueling, repairs and replacements shall be scheduled in accordance with good utility practice and, insofar as practicable, shall be mutually agreed to by System Energy and the Purchasers.

4.

Delivery of Power sold to the Purchasers pursuant to this Agreement shall occur at the Projects step-up transformer and shall be made in the form of three-phase, sixty hertz alternating current at a nominal voltage of 500 kilovolts. System Energy will supply and maintain all necessary metering equipment for determining the quantity and conditions of delivery under this Agreement. System Energy will furnish to the Purchasers such summaries of meter reading and other metering information as may reasonably be requested.

5.

Monthly bills shall be calculated in accordance with the provisions of the Monthly Grand Gulf Power Charge Formula, attached hereto as Appendix 1.

6.

Nothing contained herein shall be construed as affecting in any way the right of System Energy to unilaterally make application to FERC for a change in the rates contained herein or any other term or condition of this Agreement under Section 205 of the Federal Power Act and pursuant to FERC Rules and Regulations promulgated thereunder.

7.

No Purchaser shall be entitled to set off against any payment required to be made by it under this Agreement (a) any amounts owed by System Energy to any Purchaser or (b) the amount of any claim by any Purchaser against System Energy. The foregoing, however, shall CNRO2025-00004 -B Page 3 of 31

4 not affect in any other way the rights and remedies of any Purchaser with respect to any such amounts owed to any Purchaser by System Energy or any such claim by any Purchaser against System Energy.

8.

The invalidity and unenforceability of any provision of this Agreement shall not affect the remaining provisions hereof.

9.

This Agreement shall continue until terminated by mutual agreement of all parties hereto.

10.

This Agreement shall be binding upon the parties hereto and their successors and assigns, but no assignment hereof, or of any right to any funds due or to become due under this Agreement, shall in any event relieve either any Purchaser or System Energy of any of their respective obligations hereunder, or, in the case of the Purchasers, reduce to any extent their entitlement to receive all of the Power available to System Energy from time to time at the Project.

11.

The agreements herein set forth have been made for the benefit of the Purchasers and System Energy and their respective successors and assigns and no other person shall acquire or have any right under or by virtue of this Agreement.

12.

The Purchasers and System Energy may, subject to the provisions of this Agreement, enter into a further agreement or agreements between the Purchasers and System Energy, setting forth detailed terms and provisions relating to the performance by the Purchasers and System Energy of their respective obligations under this Agreement. No agreement entered into under this Section 12 shall, however, alter to any substantive degree the obligations of any party to this Agreement in any manner inconsistent with any of the foregoing sections of this Agreement.

13.

Each of the Purchasers shall, at any time and from time to time, be entitled to assign all of its right, title and interest in and to all of the power to which any of them shall be entitled under this Agreement, but no Purchaser shall, by such assignment, be relieved of any of its obligations and duties under this Agreement except through the payment to System Energy, by or on behalf of such Purchaser, of the amount or amounts which such Purchaser shall be obligated to pay pursuant to the terms of this Agreement.

CNRO2025-00004 -B Page 4 of 31

5 IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed as of the day and year first above written SYSTEM ENERGY RESOURCES, INC., formerly MIDDLE SOUTH ENERGY, INC.

By:

/S/

F W. Lewis ENTERGY ARKANSAS, LLC, formerly ARKANSAS POWER AND LIGHT COMPANY By:

/S/

Jerry Maulden ENTERGY LOUISIANA, LLC, formerly LOUISIANA POWER AND LIGHT COMPANY By:

/S/

J. Wyatt ENTERGY MISSISSIPPI, LLC, formerly MISSISSIPPI POWER AND LIGHT COMPANY By:

/S/

D. C. Lutkin ENTERGY NEW ORLEANS, LLC, formerly NEW ORLEANS PUBLIC SERVICE INC.

By:

/S/

James M. Cain CNRO2025-00004 -B Page 5 of 31

6 SYSTEM ENERGY RESOURCES, INC.

MONTHLY GRAND GULF POWER CHARGE FORMULA

1.

GENERAL This Grand Gulf Power Charge Formula (PCF) sets out the procedures that shall be used to determine the monthly amounts which System Energy Resources, Inc. (SERI) shall charge Entergy Arkansas, LLC (EAL); Entergy Louisiana, LLC (ELL); Entergy Mississippi, LLC (EML); and Entergy New Orleans, LLC (ENOL) (referred to hereafter, collectively, as Purchasers, or, individually, as Purchaser), for capacity and energy from the Grand Gulf Nuclear Station (Grand Gulf) pursuant to the Unit Power Sales Agreement (UPSA) between SERI and the Purchasers to which this document is attached as Appendix 1. The monthly charges for capacity (Monthly Capacity Charges) shall be determined in accordance with the provisions of Section 2 below. The monthly charges for fuel (Monthly Fuel Charges) shall be determined in accordance with the provisions of Section 3 below. The Monthly Capacity Charges and the Monthly Fuel Charges determined in accordance with the provisions of this PCF shall be billed to the Purchasers monthly in accordance with the provisions of Section 4 below.

2.

MONTHLY CAPACITY CHARGE The Monthly Capacity Charge to be billed to each of the Purchasers for any service month shall be determined by applying the Monthly Capacity Charge Formula set out in Attachment A to the applicable cost data.

CNRO2025-00004 -B Page 6 of 31

7

3.

MONTHLY FUEL CHARGE The Monthly Fuel Charge to be billed to each of the Purchasers for any service month shall be determined by applying the Monthly Fuel Charge Formula set out in Attachment B to fuel cost data for the service month.

4.

BILLING On or before the fifth workday of each month SERI shall render a billing to each of the Purchasers reflecting the Purchasers Monthly Capacity Charge and Monthly Fuel Charge for the immediately preceding service month. In addition, any applicable and appropriate adjustments shall be reflected in each of the monthly billings. The monthly billings shall be payable in immediately available funds on or before the 15th day of such month.

After the 15th day of such month, interest shall accrue on any balance due to SERI, or owed by SERI, at the rate required for refunds rendered pursuant to the requirements of Section 35.19.a of the Code of Federal Regulations. Entergy Services LLC, acting as agent for SERI and the Purchasers, may prepare the necessary billings to the Purchasers and arrange for payment in accordance with the above requirements.

5.

EFFECTIVE DATE AND TERM This PCF shall be effective for service rendered on and after December 12, 1995 and shall continue in effect until modified or terminated in accordance with the provisions of this PCF or applicable regulations or laws.

CNRO2025-00004 -B Page 7 of 31

Attachment A Page 1 of 5 Page 8 SYSTEM ENERGY RESOURCES, INC.

MONTHLY CAPACITY CHARGE FORMULA DETERMINATION OF MONTHLY CAPACITY CHARGES MONTH, XXXX LINE NO DESCRIPTION AMOUNT REFERENCE/SOURCE 1

CAPACITY REVENUE REQUIREMENT Page 3, Line 1 2

CREDIT, PER STIPULATION AND AGREEMENT IN DOCKET NO. FA89-28 SERI Rate Schedule FERC No. 6 3

ADJUSTMENT TO REFLECT UNPROTECTED EXCESS ADIT PER TAX CUTS AND JOBS ACT OF 2017 Attachment E 4

5 ONE-TIME CREDIT BASED ON IRS DETERMINATION OF THE FORMERLY UNCERTAIN 2015 COGS TAX POSITION (1)

O&M EXPENSE TRUE-UP ADJUSTMENTS PURSUANT TO THE SEPTEMBER 2022 PARTIAL SETTLEMENT(3)

Attachment G Supporting Workpapers 6

ADJUSTED CAPACITY REVENUE REQUIREMENT Line 1 Line 2 Line 3 -

Line 4 - Line 5 7

MONTHLY CAPACITY CHARGE FOR EAL 36%

• Line 6 8

MONTHLY CAPACITY CHARGE FOR ELL 14%

• Line 6 9

MONTHLY CAPACITY CHARGE FOR EML (2) 33%

• Line 6 10 MONTHLY CAPACITY CHARGE FOR ENOL 17%

• Line 6 NOTES:

(1) THE CREDIT IS EQUAL TO THE CUMULATIVE EFFECT ON THE REVENUE REQUIREMENT FROM JANUARY 1, 2016, THROUGH SEPTEMBER 30, 2020, INCLUSIVE OF INTEREST PER 18 C.F.R. § 35.19A THROUGH MARCH 15, 2021, ASSUMING THE AMOUNT OF THE 2015 COST OF GOODS SOLD TAX POSITION ACTUALLY ALLOWED BY THE IRS HAD BEEN TREATED AS CERTAIN WHEN ASSERTED.

(2) PURSUANT TO THE JUNE 2022 SETTLEMENT IN DOCKET NOS. EL17-41 ET AL., BEGINNING WITH BILLS FOR THE JULY SERVICE MONTHLY CAPACITY CHARGE FOR EML SHALL BE ADJUSTED TO REFLECT:

a.

A COMMON EQUITY COST OF 9.65%; AND

b.

A CAPITALIZATION RATIO THAT SHALL NOT EXCEED 52.0% COMMON EQUITY.

THESE ADJUSTMENTS SHALL HAVE NO EFFECT ON THE MONTHLY CAPACITY CHARGE FOR EAL, ELL, OR ENOL. A WORKPAPER SUPPORTING THE TOTAL ADJUSTMENT AND FINAL EML MONTHLY CAPACITY CHARGES SHALL BE INCLUDED IN THE FILES PRODUCED ANNUALLY PURSUANT TO THE PROTOCOLS PROCESS.

(3) INCLUDE ON AN ANNUAL BASIS ADJUSTMENTS TO EXCLUDED EXPENSES DURING THE PRECEDING YEAR MADE PURSUANT TO THE SEPTEMBER 2022 SETTLEMENT IN DOCKET NO. EL20-72. AS PROVIDED IN ATTACHMENT A, PAGES 3 & 3.1, NOTE 3, ANY ADJUSTMENT ESTIMATED ON A MONTHLY BASIS BASED ON PRIOR YEARS DATA WILL BE REVIEWED AND TRUED UP ON AN ANNUAL BASIS.

CNRO2025-00004 -B Page 8 of 31

Attachment A Page 2 of 5 Page 9 SYSTEM ENERGY RESOURCES, INC.

MONTHLY CAPACITY CHARGE FORMULA DEVELOPMENT OF RATE BASE (1)

MONTH, XXXX LINE NO DESCRIPTION AMOUNT REFERENCE/SOURCE 1

PLANT IN SERVICE FERC Accounts 101, 106 (2) 2 ACCUMULATED DEPRECIATION & AMORTIZATION FERC Accounts 108, 111 (3) 3 NET UTILITY PLANT Line 1 Plus Line 2 4

NUCLEAR FUEL FERC Accounts 120.2-120.4 5

AMORTIZATION OF NUCLEAR FUEL FERC Account 120.5 6

MATERIALS & SUPPLIES FERC Accounts 154, 163 7

PREPAYMENTS FERC Account 165 8

DEFERRED REFUELING OUTAGE COSTS FERC Account 182.3 9

10 11 ACCUMULATED DEFERRED INCOME TAXES PREPAID (ACCRUED) PENSION COSTS SALE-LEASEBACK RENTAL PAYMENTS COLLECTED IN ADVANCE OF PAYMENT TO OWNER-LESSORS FERC Accounts 190, 281, 282, 283 (4)

FERC Accounts 182.38P& 253.012 (5)

FERC Account 232 (6) 12 RATE BASE Sum of Lines 3 - 11 NOTES:

(1)

TO BE DETERMINED BASED ON DATA AS OF THE END OF THE MONTH IMMEDIATELY PRECEDING THE CURRENT SERVICE MONTH.

(2)

PRIOR TO INCLUDING CWIP, INCLUSIVE OF AFUDC, IN PLANT IN SERVICE AND RATE BASE, SERI WILL CALCULATE THE AFUDC RATE, EFFECTIVE JANUARY 1, 2023, CONSISTENT WITH THE METHODOLOGY APPROVED BY THE COMMISSION IN DOCKET NO. ER23-____-000.

(3)

THE BALANCE FOR ACCUMULATED DEPRECIATION AND AMORTIZATION IS TO BE REDUCED BY ANY DECOMMISSIONING RESERVE AND RESERVE FOR DISPOSAL OF NUCLEAR FUEL INCLUDED IN FERC ACCOUNTS 108 AND 111 WHICH REPRESENT MONIES HELD BY THIRD PARTIES.

(4)

INCLUDING ADIT RESULTING FROM IRS RESOLUTION OF THE 2015 TAX POSITION TO INCLUDE THE DECOMMISSIONING LIABILITY IN COST OF GOODS SOLD.

(5)

PREPAID (ACCRUED) PENSION COSTS INCLUDES ACCOUNTS 253012 - PENSION LIABILITY - FUNDED STATUS, 18238P -

REGULATORY ASSET FOR UNRECOGNIZED LOSSES AND POTENTIALLY ACCOUNT 254 - REGULATORY LIABILITY FOR UNRECOGNIZED GAINS.

(6)

PURSUANT TO THE SEPTEMBER 2022 SETTLEMENT IN DOCKET NO. EL20-72, BEGINNING WITH BILLS FOR THE OCTOBER 2022 SERVICE MONTH, THE BALANCE IN ACCOUNT 232 FOR THE MONTHLY SALE-LEASEBACK LEASE PAYMENTS COLLECTED IN ADVANCE OF PAYMENT BY SERI TO THE OWNER-LESSORS SHALL BE USED TO REDUCE RATE BASE.

CNRO2025-00004 -B Page 9 of 31

Attachment A Page 3 of 5 Page 10 SYSTEM ENERGY RESOURCES, INC.

MONTHLY CAPACITY CHARGE FORMULA DEVELOPMENT OF CAPACITY REVENUE REQUIREMENT (1)

MONTH, XXXX LINE NO DESCRIPTION AMOUNT REFERENCE/SOURCE 1

CAPACITY REVENUE REQUIREMENT Determined as described in Note 2 below.

2 OPERATION & MAINTENANCE EXPENSE (3)

FERC Accounts 517, 519-525, 528-532, 556, 557, 560-573, 901-905, 920-931, 935 3

DEPRECIATION EXPENSE FERC Account 403-Excluding Decommissioning Exp 4

DECOMMISSIONING EXPENSE (4)

FERC Account 403-Decommissioning Expense 5

AMORTIZATION EXPENSE FERC Accounts 404, 407.3, 407.4 6

TAXES OTHER THAN INCOME TAXES FERC Account 408.1 7

CURRENT STATE INCOME TAX Page 4, Line 18 8

CURRENT FEDERAL INCOME TAX Page 4, Line 25 9

PROVISION FOR DEFERRED INCOME TAX-STATE State Portion of FERC Accounts 410.1, 411.1 (5) 10 PROVISION FOR DEFERRED INCOME TAX-FEDERAL Federal Portion of FERC Accounts 410.1, 411.1 (5) 11 INVESTMENT TAX CREDIT-NET FERC Account 411.4 12 GAINS/LOSSES ON DISPOSITION OF UTILITY PLANT FERC Accounts 411.6, 411.7 13 UTILITY OPERATING EXPENSES Sum of Lines 2 - 12 14 UTILITY OPERATING INCOME Line 1 minus Line 13 15 VERIFICATION:

16 RATE BASE Page 1, Line 12 17 RATE OF RETURN ON RATE BASE 12*(Line 14 / Line 16)

(Must equal Line 18) 18 COST OF CAPITAL Weighted Cost Rate from Page 5, Line 6 NOTES:

1)

ALL EXPENSES ARE TO BE THOSE FOR THE CURRENT SERVICE MONTH.

2)

THE CAPACITY REVENUE REQUIREMENT FOR THE SERVICE MONTH IS THE VALUE THAT RESULTS IN A UTILITY OPERATING INCOME WHICH, WHEN DIVIDED BY THE RATE BASE (DETERMINED IN ACCORDANCE WITH PAGE 2) AND MULTIPLIED BY 12 PRODUCES A RATE OF RETURN ON RATE BASE EQUAL TO THE COST OF CAPITAL (DETERMINED IN ACCORDANCE WITH PAGE 5). PLEASE NOTE FOR EML, THE COST OF CAPITAL IS DETERMINED PURSUANT TO THE JUNE 2022 SETTLEMENT IN DOCKET NOS. EL17-41 ET AL., BEGINNING WITH BILLS FOR THE JULY 2022 SERVICE MONTH. SEE NOTE 10 ON ATTACHMENT A, PAGE 5.

CNRO2025-00004 -B Page 10 of 31

Attachment A Page 3.1 of 5 Page 11

3)

EXCLUSIVE OF FUEL EXPENSE IN FERC ACCOUNT 518. IN ADDITION, PURSUANT TO THE SEPTEMBER 2022 SETTLEMENT IN DOCKET NO. EL20-72, BEGINNING WITH BILLS FOR THE OCTOBER 2022 SERVICE MONTH: (A) INCLUSION OF AIRCRAFT COSTS THAT ARE OR SHOULD PROPERLY BE RECORDED IN ACCOUNTS 517, 519-525, 528-532, 556, 557, 560-573, 901-905, 920-931, 935 SHALL BE LIMITED TO COSTS ALLOCATED TO SERI VIA DIRECT ASSIGNMENT PROJECT CODE AND COSTS ALLOCATED VIA NUCLEAR-BASED PROJECT CODE; SHALL EXCLUDE COST CODES FOR UNREGULATED NUCLEAR PLANTS; AND SHALL BE SUBJECT TO A CAP OF NO MORE THAN $1,500 PER PERSON PER FLIGHT (APPLIED PRIOR TO THE ALLOCATION OF THE FLIGHTS COST ACROSS BUSINESS UNITS); (B) ANNUAL INCENTIVE PLAN EXPENSES THAT ARE OR SHOULD PROPERLY BE RECORDED IN ACCOUNT 920 AND ANY NUCLEAR OPERATING AND MAINTENANCE EXPENSE ACCOUNT (ACCOUNTS 517-525, 528-532) SHALL BE REDUCED TO EXCLUDE THE PORTION OF ANNUAL INCENTIVE PLAN EXPENSES AWARDED BASED ON FINANCIAL GOALS AND ALLOCATED TO SERI; (C) LONG TERM INCENTIVE PLAN EXPENSES THAT ARE OR SHOULD PROPERLY BE RECORDED IN ACCOUNT 920 AND ANY NUCLEAR OPERATING AND MAINTENANCE EXPENSE ACCOUNT (ACCOUNTS 517-525, 528-532) SHALL BE REDUCED TO EXCLUDE EXPENSES FOR STOCK OPTIONS, RESTRICTED STOCK AWARDS, AND PERFORMANCE UNIT AWARDS FOR MANAGEMENT LEVEL 1 THROUGH 4 EMPLOYEES; (D) INCLUSION OF ADVERTISING EXPENSES RECORDED IN ACCOUNT 930.1 SHALL BE LIMITED TO EXPENSES FOR SAFETY-BASED ADVERTISING. MONTHLY ESTIMATES OF EXCLUSIONS FOR THESE ISSUES SHALL BE INCLUDED BASED ON THE PRIOR SERVICE YEARS DATA AND SHALL BE TRUED UP NO LATER THAN MARCH 31 OF THE YEAR FOLLOWING THE SERVICE YEAR. SUPPORTING WORKPAPERS FOR THE ADJUSTMENT(S)

WILL BE PROVIDED PURSUANT TO SECTION II.B.6(C) OF THE ANNUAL FORMULA RATE PROTOCOLS.

4)

SHOULD THE FERC APPROVE A CHANGE IN SYSTEM ENERGYS SCHEDULE OF ANNUAL DECOMMISSIONING EXPENSES DURING THE SERVICE MONTH, THE MONTHLY LEVEL IN EFFECT AS OF THE END OF THE MONTH SHALL BE UTILIZED.

OTHERWISE, THE AMOUNT CHARGED TO FERC ACCOUNT 403 FOR THE SERVICE MONTH SHALL BE UTILIZED, AS SHOWN ON ATTACHMENT C.

5)

RESTRICTED TO THOSE ITEMS FOR WHICH CORRESPONDING TIMING DIFFERENCES ARE INCLUDED IN THE ADJUSTMENTS TO NET INCOME BEFORE INCOME TAX (SEE PAGE 4, LINE 10).

CNRO2025-00004 -B Page 11 of 31

Attachment A Page 4 of 5 Page 12 SYSTEM ENERGY RESOURCES, INC.

MONTHLY CAPACITY CHARGE FORMULA DEVELOPMENT OF CURRENT INCOME TAX EXPENSE MONTH, XXXX LINE NO DESCRIPTION AMOUNT REFERENCE/SOURCE 1

CAPACITY REVENUE REQUIREMENT Page 3, Line 1 2

OPERATION 8, MAINTENANCE EXPENSE Page 3, Line 2 3

DEPRECIATION EXPENSE Page 3, Line 3 4

DECOMMISSIONING EXPENSE Page 3, Line 4 5

AMORTIZATION EXPENSE Page 3, Line 5 6

TAXES OTHER THAN INCOME Page 3, Line 6 7

NET INCOME BEFORE INCOME TAXES Line 1 - (Sum of Lines 2-6) 8 ADJUSTMENTS TO NET INCOME BEFORE INCOME TAX:

9 INTEREST SYNCHRONIZATION Rate Base (Page 1, Line 12) * (-1)

• Total Debt Rate (Page 5, Line 4)/12 10 OTHER ADJUSTMENTS See Note 1 11 TOTAL ADJUSTMENTS Line 9 plus Line 10 12 TAXABLE INCOME Line 7 plus Line 11 COMPUTATION OF STATE INCOME TAX 13 STATE TAXABLE INCOME BEFORE ADJUSTMENTS Line 12 14 NET ADJUSTMENT TO STATE TAXABLE INCOME See Note 1 15 STATE TAXABLE INCOME Line 13 plus Line 14 16 STATE INCOME TAX BEFORE ADJUSTMENTS Line 15

• Mississippi State Tax Rate (2) 17 ADJUSTMENTS TO STATE TAX See Note 1 18 CURRENT STATE INCOME TAX Sum of Lines 16 - 17 COMPUTATION OF FEDERAL INCOME TAX 19 FEDERAL TAXABLE INCOME BEFORE ADJUSTMENTS Line 12 20 CURRENT STATE INCOME TAX DEDUCTION Line 18 (Shown as deduction) 21 OTHER ADJUSTMENTS TO FEDERAL TAXABLE INCOME See Note 1 22 FEDERAL TAXABLE INCOME Sum of Lines 19-21 23 FEDERAL INCOME TAX BEFORE ADJUSTMENTS Line 22

• Federal Tax Rate (2) 24 ADJUSTMENTS TO FEDERAL TAX See Note 1 and Note 3 25 CURRENT FEDERAL INCOME TAX Sum of Lines 23 - 24 NOTES:

1)

ITEMS FROM MONTHLY TAX DETERMINATION THAT ARE APPROPRIATE FOR RATEMAKING PURPOSES.

2)

RATE IN EFFECT AT THE END OF THE SERVICE MONTH.

3)

INCLUDING A ONE-TIME CREDIT OF EXCESS DEFERRED FEDERAL INCOME TAXES RESULTING FROM IRS RESOLUTION OF THE 2015 TAX POSITION TO INCLUDE THE DECOMMISSIONING LIABILITY IN COST OF GOODS SOLD.

CNRO2025-00004 -B Page 12 of 31

Attachment A Page 5 of 5 Page 13 SYSTEM ENERGY RESOURCES, INC.

MONTHLY CAPACITY CHARGE FORMULA DEVELOPMENT OF COST OF CAPITAL (1)

MONTH, XXXX LINE NO CAPITAL SOURCE CAPITAL AMOUNT (2)(3)

CAPITALIZATION RATIO (4)

COST RATE WEIGHTED COST RATE (8) 1 DEBT 2

LONG TERM FERC Accts 221, 224, 225, 226, 181, 189 (5) 3 SHORT TERM (6) 4 TOTAL TERM (7) 5 COMMON EQUITY FERC Accts 201, 208, 216 (SEE NOTE 9) 6 TOTAL NA NOTES:

(1)

TO BE DETERMINED BASED ON DATA AS OF THE END OF THE MONTH IMMEDIATELY PRECEDING THE CURRENT SERVICE MONTH.

(2)

LONG TERM DEBT SHALL INCLUDE ALL ISSUES AND REFLECT THE PRINCIPAL AMOUNT.

(3)

SHORT TERM DEBT SHALL INCLUDE ONLY THAT PORTION NOT REFLECTED IN THE CALCULATION OF SERIS RATE FOR ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION.

(4)

APPLICABLE CAPITAL AMOUNT DIVIDED BY THE TOTAL CAPITAL AMOUNT.

(5)

AVERAGE COST RATE FOR ALL OUTSTANDING ISSUES INCLUDING APPLICABLE AMORTIZATION OF DEBT DISCOUNT, PREMIUM, AND EXPENSE TOGETHER WITH AMORTIZATION OF LOSS OR GAIN ON REACQUIRED DEBT.

(6)

THE AVERAGE COST RATE FOR ELIGIBLE SHORT TERM DEBT.

(7)

WEIGHTED AVERAGE COST RATE FOR LONG TERM DEBT AND SHORT TERM DEBT.

(8)

CAPITALIZATION RATIO FOR THE APPLICABLE CAPITAL SOURCE MULTIPLIED BY THE CORRESPONDING COST RATE.

(9)

THE COMMON EQUITY COST RATE SHALL BE AS FOLLOWS:

A.

FOR SERVICE FROM DECEMBER 12, 1995 THROUGH JULY 30, 2000 THE RATE SHALL BE 10.58%.

B.

FOR SERVICE AFTER JULY 30, 2000 THE RATE SHALL BE 10.94%.

CNRO2025-00004 -B Page 13 of 31

Attachment B Page 14 SYSTEM ENERGY RESOURCES, INC.

MONTHLY FUEL CHARGE FORMULA MONTH, XXXX LINE NO DESCRIPTION AMOUNT REFERENCE/SOURCE 1

FUEL EXPENSE FOR APPLICABLE SERVICE MONTH FERC Account 518 2

MONTHLY FUEL CHARGE FOR EAL 36%

• Line 1 3

MONTHLY FUEL CHARGE FOR ELL 14%

• Line 1 4

MONTHLY FUEL CHARGE FOR EML 33%

• Line 1 5

MONTHLY FUEL CHARGE FOR ENOL 17%

• Line 1 CNRO2025-00004 -B Page 14 of 31

Attachment C Page 15 System Energy Resources, Inc.

Grand Gulf Decommissioning Model Revenue Requirement Summary

($000)

Revenue Requirement Line No.

Year Owned Portion Leased Portion Total 1

1995 6,813 1,208 8,021 2

1996 11,195 1,997 13,192 3

1997 11,195 1,997 13,192 4

1998 11,195 1,997 13,192 5

1999 11,195 1,997 13,192 6

2000 11,195 1,997 13,192 7

2001 13,624 2,431 16,055 8

2002 13,624 2,431 16,055 9

2003 13,624 2,431 16,055 10 2004 13,624 2,431 16,055 11 2005 13,624 2,431 16,055 12 2006 16,590 2,960 19,550 13 2007 16,590 2,960 19,550 14 2008 16,590 2,960 19,550 15 2009 16,590 2,960 19,550 16 2010 16,590 2,960 19,550 17 2011 20,184 3,601 23,785 18 2012 20,184 3,601 23,785 19 2013 20,184 3,601 23,785 20 2014 20,184 3,601 23,785 21 2015 20,184 2,101 22,285 22 2016 24,550 0

24,550 23 2017 18,412 0

18,412 24 2018 0

0 0

25 2019 0

0 0

26 2020 0

0 0

27 2021 0

0 0

28 2022 0

0 0

29 2023 0

0 0

30 2024 0

0 0

31 2025 0

0 0

32 2026 0

0 0

33 2027 0

0 0

34 2028 0

0 0

35 2029 0

0 0

36 2030 0

0 0

37 2031 0

0 0

CNRO2025-00004 -B Page 15 of 31

Attachment C Page 16 System Energy Resources, Inc.

Grand Gulf Decommissioning Model Revenue Requirement Summary

($000)

Revenue Requirement Line No.

Year Owned Portion Leased Portion Total 38 2032 0

0 0

39 2033 0

0 0

40 2034 0

0 0

41 2035 0

0 0

42 2036 0

0 0

43 2037 0

0 0

44 2038 0

0 0

45 2039 0

0 0

46 2040 0

0 0

47 2041 0

0 0

48 2042 0

0 0

49 2043 0

0 0

50 2044 0

0 0

CNRO2025-00004 -B Page 16 of 31

Attachment D Ln No Plant Account Function / Plant Account Description Depreciation Rates (1)

Nuclear Production Plant in Service (5) 1 3201 Nuclear Production Land 2

3210 Structures and Improvements 1.20%

3 3220 Reactor Plant Equipment 2.95%

4 3230 Turbogenerator Units 3.08%

5 3240 Accessory Electric Equipment 1.26%

6 3250 Miscellaneous Power Plant Equipment 2.19%

Transmission Plant in Service 7

3530 Station Equipment 4.12%

General Plant in Service 8

3912 Information Systems 20.00%

9 3913 Data Handling Equipment 6.67%

10 3971 Communication Equipment 10.00%

11 3972 Communication Equipment - Microwave 10.00%

General Plant True-up (2)

Depr. Expense $

(1/1/21 - 2/28/22)

(2)

Monthly Fixed Depr. Expense $

(3/1/22 - 9/30/22) (2) 12 3912 Information Systems 109,071 163,720 13 3913 Data Handling Equipment 48 32 14 3971 Communication Equipment 15,719 (69,661) 15 3972 Communication Equipment - Microwave 9,744 12,334 16 Total General Plant True-up (2) 134,582 106,425 Intangible Plant in Service (3) 17 3030 Misc. Intangible - 5 year life 20.00%

18 3030 Misc. Intangible - 10 year life 10.00%

19 3030 Misc. Intangible - 15 year life 6.67%

20 3030 Misc. Intangible - EOL Note (4)

Notes:

(1)

SYSTEM ENERGY RESOURCES, INC.

Depreciation & Amortization Rates Currently Effective Amortization Rates (3)

The above Depreciation Rates are those established through settlement in Docket ER22-736.

CNRO2025-00004 -B Page 17 of 31

Page 18 Notes continued:

(2)

(3)

(4)

(5)

SERI's General Plant Depreciation Rates are based on identified retirement schedules as permitted under FERC Accounting Release 15. SERI adopted the scheduled retirements approach for General Plant Depreciation Rates on October 11, 2017 in Docket No. ER17-2219. As of December 31, 2020, the remaining net book value of $2,629,124 will continue being amortized at the $134,582 each month until new depreciation rates become effective March 1, 2022. At that time the new general plant reserve deficiency amortization of $106,425 will become effective for 7 months. Therefore, on September 30, 2022 the identified General Plant will be fully depreciated and no additional depreciation expense will be incurred associated with these assets. All General Plant additions subsequent to December 31, 2020, will be subject to the applicable rates as stated on lines 8 through 11 above.

Intangible Plant was not addressed in SERI's 2021 Depreciation Study. These rates are the currently effective amortization rates which will remain in effect.

The rate for Miscellaneous Intangible Plant - End of Life ("EOL") is recalculated for future additions such that EOL - Misc. Intangible Plant is amortized over the remaining licensed life of Grand Gulf.

Grand Gulf's NRC license is currently expected to expire on November 1, 2044. As of December 31, 2020 the remaining licensed life is 288 months. The Amortization Rate for EOL-Misc. Intangible Plant additions is (1 / remaining months of SERI's licensed life at that time).

As identified in the Depreciation Study submitted as part of SERIs December 28, 2021 FERC Filing, the net salvage percentage for each Nuclear Production Plant account is as follows: Account 3210, -

2%; Account 3220, -2%; Account 3230, -7%; Account 3240, -4%; Account 3250, 1%; and Account 3530, -15%. See Depreciation Study at Attachment C, Exhibit DJC-3, page 1.

CNRO2025-00004 -B Page 18 of 31

Attachment E Page 19 A

B C

D E

F G

H Service Month Unprotected Excess ADIT Beginning Balance (1)

Unprotected Excess ADIT Monthly Amortization (2)

Excess Unprotected ADIT Ending Balance (3)

Annual Before-tax Cost of Capital (4)

Monthly Return on Unamortized Balance (5)

Unprotected Excess ADIT Monthly Amortization with Tax Gross-Up (6)

Monthly Adjustment for Unprotected Excess ADIT (7) 1 Jun-18 (58,970,779) 8,424,397 (50,546,382) 11,225,046 2

Jul-18 (50,546,382) 8,424,397 (42,121,985) 11,225,046 3

Aug-18 (42,121,985) 8,424,397 (33,697,588) 11,225,046 4

Sep-18 (33,697,588) 8,424,397 (25,273,191) 11,225,046 5

Oct-18 (25,273,191) 8,424,397 (16,848,794) 11,225,046 6

Nov-18 (16,848,794) 8,424,397 (8,424,397) 11,225,046 7

Dec-18 (8,424,397) 8,424,397 11,225,046 Note:

(1)

(2) Unprotected Excess ADIT Balance at 12/31/17 divided by 7 (3) Column B + Column C (4)

(5) Column B x Column E /12 (6) Column C

• Tax Gross-up where Tax Gross-up Factor = 1 / [1 - (Federal Tax Rate * (1 - Mississippi Tax Rate)) + Mississippi Tax Rate].

(7)

Unprotected Excess ADIT Balance as of 12/31/17. This balance is subject to true-up based on SERIs 2017 Federal Income Tax Return and the actual amount returned to SERIs customers through UPSA billings from June 2018 through December 2018.

Before-tax Cost of Capital = Weighted Debt Cost Rate (Att A, Pg 5, Ln 4) + Weighted Common Equity Cost Rate (Att A, Pg 5, Ln 5) x Tax Gross-up Factor.

Column F + Column G. Adjustment to be applied as a reduction to the Capacity Revenue Requirement on Att A, Pg 1, Ln 3 over the 7 months of June 2018 through December 2018.

System Energy Resources, Inc.

Capacity Revenue Requirement Adjustment to Reflect Unprotected Excess Accumulated Deferred Income Taxes Associated with the Tax Cuts and Jobs Act of 2017 CNRO2025-00004 -B Page 19 of 31

Attachment G Page 20 System Energy Resources, Inc.

One-Time Credit (1)

Payable in the February 2021 Service Month Billing FERC Interest Through March 15, 2021 Description Amount Revenue Requirement Principal Amount

$22,195,965 FERC Interest 3,049,923 Total One-Time Credit (2)

$25,245,888 Notes:

(1) The credit is equal to the cumulative effect on the revenue requirement from January 1, 2016, through September 30, 2020, inclusive of interest per 18 C.F.R. § 35.19a through March 15, 2021, assuming the amount of the 2015 Cost of Goods Sold Tax Position actually allowed by the IRS had been treated as certain when asserted.

(2) The Total One-Time Credit is included on Attachment A, Page 1, Line 4.

CNRO2025-00004 -B Page 20 of 31

Attachment:

Protocols Protocols-1 Formula Rate ProtocolsSection I.

Applicability The following Information Exchange and Challenge Procedures shall apply to the SERI UPSA.

Section II.

Copies of UPSA Bills A.

SERI will provide Grand Gulf monthly bills for each calendar year beginning with calendar year 2019, together with information and workpapers that show how the bills were determined, to the designated representatives of the APSC, CNO, LPSC, and MPSC (Interested Parties) not later than March 31 of the following year (Annual Bills). The bills and workpapers will be provided for all formula rate inputs such that customers can determine which Uniform System of Accounts are included and excluded from recovery through the UPSA, in native format with working formulas intact. These workpapers will identify which SERI trial balance accounts and/or sub-accounts are being excluded from the formula rate input amounts, when the amount reported in SERIs Form No. 1 differs in any respect from the amount to be collected from customers. The UPSA workpapers will be in a format similar to the supporting workpapers (designated as a WP) included in each Entergy Operating Companys MISO Attachment O transmission formula rate. SERI will also make the bills and workpapers available for public viewing by posting such information to the Entergy website not later than March 31. Annually, SERI will also report in its FERC Form No. 1 on schedule page 106b Information on Formula Rates Formula Rate Variances or on the applicable FERC Form No. 1 schedule page, detailed information regarding which SERI trial balance accounts and/or sub-accounts and the related account/sub-CNRO2025-00004 -B Page 21 of 31

Attachment:

Protocols Protocols-2 account balances that have been excluded from the UPSA formula rate inputs and differ from the amounts reported in SERIs FERC Form No. 1.

B.

The Annual Bills provided by SERI will:

1.

Include a workable data-populated formula and underlying workpapers in native format with all formulas and links intact.

2.

Provide the formula rate calculations and all inputs thereto, as well as supporting documentation and workpapers for data that are used in the formula rate.

3.

Provide sufficient information to enable Interested Parties to replicate the calculation of the formula.

4.

With respect to any change in accounting that affects inputs to the formula rate or the resulting charges billed under the formula rate (Accounting Change),

identify and explain any Accounting Changes, including

a.

The initial implementation of an accounting standard or policy;

b.

the initial implementation of accounting practices for unusual or unconventional items where FERC has not provided specific accounting direction;

c.

correction of errors and prior period adjustments that impact the revenue requirement;

d.

the implementation of new estimation methods or policies that change prior estimates; and

e.

changes to income tax elections.

5.

SERI must identify all items included in the Annual Bills at an amount other CNRO2025-00004 -B Page 22 of 31

Attachment:

Protocols Protocols-3 than on a historical cost basis (e.g., fair value adjustments).

6.

On or before June 15 of each year, SERI shall provide the interested parties with the following:

a.

The underlying data and calculations, with an accompanying narrative, reconciling any differences between the inputs shown on the monthly UPSA bills for the prior calendar year and the corresponding accounts on SERI's FERC Form No. 1.

b.

The Annual Prepaid (Accrued) Pension Cost Workpaper (Pension Cost WP) detailing the determination of Prepaid (Accrued) Pension Cost in support of Attachment A, Page 2, Line 10 as of December 31 of the prior calendar year.

c.

The O&M Expense True-Up Workpapers detailing the annual true-up of excluded expenses in support of Attachment A, Page 1, Line 5. With respect to the adjustments for executive annual incentive plan expenses, these workpapers shall include the table depicting the percentage of annual incentive plan expenses that are awarded to Entergy Services, LLC employees, based on financial-metrics for the prior service year; this percentage shall be used to calculate the exclusion of such costs that are billed to SERI.

7.

On or before May 1 of each year, SERI shall make an Informational Filing with FERC providing the details of the year-end, actuarially determined Prepaid (Accrued) Pension Cost as of December 31 of the preceding calendar year.

C.

SERI shall hold an open meeting among Interested Parties (Annual Meeting)

CNRO2025-00004 -B Page 23 of 31

Attachment:

Protocols Protocols-4 between the date SERI provides the Annual Bills and a date that is no later than July

1. No less than seven (7) days prior to such Annual Meeting, SERI shall provide notice to the Interested Parties of the time, date, and location of the Annual Meeting.

The Annual Meeting shall (i) permit SERI to explain and clarify its Annual Bills and (ii) provide Interested Parties an opportunity to seek information and clarifications from SERI about the Annual Bills.

Section III.

Information Exchange Procedures Each set of Annual Bills shall be subject to the following information exchange procedures (Information Exchange Procedures):

A.

Interested Parties shall have until October 1 (unless such period is extended with the written consent of SERI or by FERC) to serve reasonable information and document requests on SERI (Information Exchange Period). If October 1 falls on a weekend or a holiday recognized by FERC, the deadline for submitting all information and document requests shall be extended to the next business day. Such information and document requests shall be limited to what is necessary to determine:

(1) the extent or effect of an Accounting Change; (2) whether the Annual Bills fail to include data properly recorded in accordance with these protocols; (3) the proper application of the UPSA formula and procedures in these protocols; (4) the accuracy of data and consistency with the UPSA formula of the charges shown in the Annual Bills; (5) the prudence of actual costs and expenditures; CNRO2025-00004 -B Page 24 of 31

Attachment:

Protocols Protocols-5 (6) the effect of any change to the underlying Uniform System of Accounts or FERC Form No. 1; (7) the addition to or deletion from any account/subaccount or detailed input in a workpaper due to an Accounting Change or such other changes implemented during the previous calendar year; or (8) any other information that may reasonably have substantive effect on the calculation of the charges pursuant to the UPSA formula.

The information and document requests shall not otherwise be directed to ascertaining whether the formula rate is just and reasonable.

B.

SERI shall make a good faith effort to respond to information and document requests pertaining to the Annual Bills within fifteen (15) business days of receipt of such requests. SERI shall respond to all information and document requests by no later than October 31, unless the Information Exchange Period is extended by SERI or FERC.

C.

SERI shall not claim that responses to information and document requests provided pursuant to these protocols are subject to any settlement privilege in any subsequent FERC proceeding addressing the UPSA.

Section IV. Challenge Procedures A.

Interested Parties shall have until November 21 (unless such period is extended with the written consent of SERI or by FERC order) to review the inputs, supporting explanations, allocations, and calculations and to notify SERI in writing, which may be made electronically, of any specific Informal Challenges. The period of time from receipt of copies of the Annual Bills on March 31 until November 21 shall be referred CNRO2025-00004 -B Page 25 of 31

Attachment:

Protocols Protocols-6 to as the Review Period. If November 21 falls on a weekend or a holiday recognized by FERC, the deadline for submitting all Informal Challenges shall be extended to the next business day. Failure to pursue an issue through an Informal Challenge or to lodge a Formal Challenge regarding any issue with the current set of Annual Bills shall bar pursuit of such issue in a Challenge Procedure as set forth in these protocols with respect to that Annual Bill cycle, but shall not bar pursuit of such issue or the lodging of a Formal Challenge as to such issue as it relates to subsequent Annual Bills.

B.

A party submitting an Informal Challenge to SERI must specify the inputs, supporting explanations, allocations, calculations, or other information to which it objects, and provide an appropriate explanation and documents to support its challenge. SERI shall make a good faith effort to respond to any Informal Challenge within twenty (20) business days of notification of such challenge. SERI shall appoint a senior representative to work with the party that submitted the Informal Challenge (or its representative) toward a resolution of the challenge. If SERI disagrees with such challenge, SERI will provide the Interested Party(ies) with an explanation supporting the inputs, supporting explanations, allocations, calculations, or other information. No Informal Challenge may be submitted after November 21, and SERI must respond to all Informal Challenges by no later than December 21, unless the Review Period is extended by SERI or FERC.

C.

Formal Challenges shall be filed pursuant to these protocols and shall satisfy all of the following requirements.

(1)

A Formal Challenge shall:

(a)

Clearly identify the action or inaction which is alleged to violate the CNRO2025-00004 -B Page 26 of 31

Attachment:

Protocols Protocols-7 filed UPSA formula or protocols; (b)

Explain how the action or inaction violates the filed UPSA formula or protocols; (c)

Set forth the business, commercial, economic, or other issues presented by the action or inaction as such relate to or affect the party filing the Formal Challenge, including:

(i)

The extent or effect of an Accounting Change; (ii)

Whether the Annual Bills fail to include data properly recorded in accordance with these protocols; (iii)

The proper application of the UPSA formula and procedures in these protocols; (iv)

The accuracy of data and consistency with the UPSA formula of the charges shown in the Annual Bills; (v)

The prudence of actual costs and expenditures; (vi)

The effect of any change to the underlying Uniform System of Accounts; or (vii)

Any other information that may reasonably have substantive effect on the calculation of the charge pursuant to the formula.

(d)

Make a good faith effort to quantify the financial impact or burden (if any) created for the party filing the Formal Challenge as a result of the action or inaction; (e)

State whether the issues presented are pending in an existing Commission proceeding or a proceeding in any other forum in which CNRO2025-00004 -B Page 27 of 31

Attachment:

Protocols Protocols-8 the filing party is a party, and if so, provide an explanation why timely resolution cannot be achieved in that forum; (f)

State the specific relief or remedy requested, including any request for stay or extension of time, and the basis for that relief; (g)

Include all documents that support the facts in the Formal Challenge in possession of, or otherwise attainable by, the filing party, including, but not limited to, contracts and affidavits; and (h)

State whether the filing party utilized the Informal Challenge procedures described in these protocols to dispute the action or inaction raised by the Formal Challenge, and, if not, describe why not.

(2)

Service. Any person filing a Formal Challenge must serve a copy of the Formal Challenge on SERI. Service to SERI must be simultaneous with filing at the Commission. Simultaneous service can be accomplished by electronic mail in accordance with § 385.2010(f)(3), facsimile, express delivery, or messenger. The party filing the Formal Challenge shall serve the individual listed as the contact person for SERI and Entergy Services, LLC listed on the FERC website.

D.

Informal and Formal Challenges shall be limited to all issues that may be necessary to determine: (1) the extent or effect of an Accounting Change; (2) whether the Annual Bills fail to include data properly recorded in accordance with these protocols; (3) the proper application of the UPSA formula and procedures in these protocols; (4) the accuracy of data and consistency with the UPSA formula of the charges shown in the Annual Bills; CNRO2025-00004 -B Page 28 of 31

Attachment:

Protocols Protocols-9 (5) the prudence of actual costs and expenditures; (6) the effect of any change to the underlying Uniform System of Accounts; or (7) any other information that may reasonably have substantive effect on the calculation of the charge pursuant to the UPSA formula.

E.

Any changes or adjustments to the Annual Bills resulting from the Information Exchange and Informal Challenge processes that are agreed to by SERI will be reported in the Informational Filing described in Section VI of these protocols.

F.

An Interested Party shall have until February 28 following the Review Period (unless such date is extended with the written consent of SERI to continue efforts to resolve the Informal Challenge) to make a Formal Challenge with FERC, which shall be served on SERI. Failure to pursue an issue through an Informal Challenge regarding any issue as to a given set of Annual Bills shall bar a Formal Challenge on such issue with respect to that Annual Bill cycle, but shall not bar pursuit of such issue or the lodging of a Formal Challenge as to such issue as it relates to subsequent Annual Bills.

SERI shall respond to the Formal Challenge by the deadline established by FERC. A party may not pursue a Formal Challenge if that party did not submit an Informal Challenge on any issue during the applicable Review Period.

G.

In any proceeding initiated by FERC concerning the Annual Bills or in response to a Formal Challenge, SERI shall bear the burden, consistent with section 205 of the Federal Power Act, of proving that it has correctly applied the terms of the formula rate consistent with these protocols, and that it followed the applicable requirements and procedures in the UPSA. Nothing herein is intended to alter the burdens applied by CNRO2025-00004 -B Page 29 of 31

Attachment:

Protocols Protocols-10 FERC with respect to prudence challenges.

H.

Except as specifically provided herein, nothing herein shall be deemed to limit in any way the right of SERI to file unilaterally, pursuant to Federal Power Act section 205 and the regulations thereunder, to change the formula rate or any of its inputs (including, but not limited to, rate of return), or the right of any other party to request such changes pursuant to section 206 of the Federal Power Act and the regulations thereunder.

I.

No party shall seek to modify the formula rate under the Challenge Procedures set forth in these protocols and the Annual Bills shall not be subject to challenge by anyone for the purpose of modifying the UPSA formula. Any modifications to the UPSA formula will require, as applicable, a Federal Power Act section 205 or section 206 filing.

J.

Any Interested Party seeking changes to the application of the UPSA formula due to a change in the Uniform System of Accounts shall first raise the matter with SERI before pursuing a Formal Challenge.

Section V.

Changes to Annual Bills Any changes to the data inputs, or as the result of any FERC proceeding to consider the Annual Bills, or as a result of the procedures set forth herein, shall be incorporated into the formula rate calculations on a going forward basis beginning with the UPSA bill that immediately follows the resolution of all challenges in an Annual Bill cycle. In addition, SERI will calculate refunds/surcharges for any changes or adjustments to the Annual Bills resulting from the Information Exchange and Informal Challenge processes that are agreed to by SERI for all prior months where the improper amounts were included in the UPSA bill, beginning with the first monthly bill that the improper amount was improperly CNRO2025-00004 -B Page 30 of 31

Attachment:

Protocols Protocols-11 included in the preceding calendar year. The refunds/surcharges will be included as a one-time adjustment on the UPSA bill immediately following the resolution of all challenges in an Annual Bill cycle. Interest on any refund or surcharge shall be calculated in accordance with 18 C.F.R. § 35.19a.

Section VI.

Informational Filing A.

By January 31 of each year, SERI shall submit to FERC an informational filing (Informational Filing). The Informational Filing must describe any corrections or adjustments made during the previous calendar year and must describe all aspects of the UPSA formula or its inputs that are the subject of an ongoing dispute under the Informal or Formal Challenge procedures. SERI will also describe any refunds to be made pursuant to Section V above.

B.

Any challenges to the implementation of the UPSA formula must be made through the Challenge Procedures described in these protocols or in a separate complaint proceeding and not in response to the Informational Filing.

Section VII. Reservation of Rights Nothing herein is intended to limit a party's right to file a complaint under Section 206 of the Federal Power Act, or a party's right to oppose such complaint on any grounds.

CNRO2025-00004 -B Page 31 of 31

CNRO2025-00004 Entergy Louisiana, LLC RBS Status Report - 70% Regulated

CNRO2025-00004 Page 1 of 1 ENTERGY LOUISIANA, LLC.

Status Report of Decommissioning Funding For Year Ending December 31, 2024 - 10 CFR 50.75(f)(1)

Plant Name: River Bend Station (70% Regulated Interest)

1. Minimum Financial Assurance (MFA)

Estimated per 10 CFR 50.75(b) and (c) (2024$):

$468.2 million19

2. ISFSI Obligation as of 12/31/24

$8.02 million20

3. Decommissioning Fund Total As of 12/31/24:

$802.5 million

4. Annual amounts remaining to be collected:

See Footnote21

5. Assumptions used:

Rate of Escalation of Decommissioning Costs:

See item below Rate of Earnings on Decommissioning Funds:

2% real rate of return per 10 CFR 50.75(e)(1)(i)

Authority for use of Real Earnings Over 2%:

N/A

6. Contracts upon which licensee is relying For Decommissioning Funding:

See footnote 22

7. Modifications to Method of Financial Assurance since Last Report:

None

8. Material Changes to Trust Agreements:

None 19 See Attachment 3-A.

20 From Entergys ISFSI Decommissioning Funding Plans Pursuant to 10 CFR 72.30, December 05, 2024 (Accession No. ML24340A243), 70% of River Bend value.

21 Decommissioning funds are currently being collected for River Bend, however, as a conservatism and to simplify this report, Entergy is not relying on those funds for this report.

22 See the unit power purchase agreement under a FERC tariff for the Texas-jurisdictional share of the River Bend 70% share provided as Attachment 3-D in the decommissioning financial assurance filing dated March 28, 2019, NRC Accession No. ML19087A327, incorporated herein by reference. The licensee believes this contract does not qualify as a contractual obligation, but rather is simply a cost of service recovery mechanism as defined in 10 CFR §50.75(e)(1)(ii)(A). Out of an abundance of caution, the licensee identifies this information here.

-A CNRO2025-00004 Entergy Louisiana, LLC - Calculation of Minimum Amount River Bend Station

CNRO2025-00004 -A Page 1 of 1 ENTERGY LOUISIANA, LLC.

Calculation for Minimum Amount For Year Ending December 31, 2024 - 10 CFR 50.75(f)(1)

Entergy Louisiana, LLC:

Factors below used for all of ownership interests Plant Location:

West Feliciana Parish, Louisiana Reactor Type:

Boiling Water Reactor ("BWR")

Power Level:

<3,400 MWt (3,091MWt)

BWR Base Year 1986$:

$131,819,000 Labor Region:

South Waste Burial Facility:

Generic Disposal Site 10 CFR 50.75(c)(2) Escalation Factor Formula:

0.65(L) +0.13(E) +0.22(B)

Factor L=Labor (South) 3.2723 E=Energy (BWR) 2.9524 B=Waste Burial-Vendor (BWR) 11.65825 BWR Escalation Factor:

0.65(L) +0.13(E) +0.22(B)=

5.073 1986 BWR Base Year $ Escalated:

$131,819,000

• Factor=

$668,817,969 River Bend 70% Regulated Interest:

$468,172,579 River Bend 30% Non-Regulated Interest:

$200,645,391 Total

$668,817,970 23 Bureau of Labor Statistics, Series Report ID: CIU2010000000220i (4th Quarter 2024) 24 Bureau of Labor Statistics, Series Report ID: wpu0543 and wpu0573 (December 2024) 25 Nuclear Regulatory Commission: NUREG-1307 Revision 20, Table 2-1 (2024)

-B CNRO2025-00004 Entergy Louisiana, LLC RBS Status Report - 30% Non-Regulated

CNRO2025-00004 -B Page 1 of 1 ENTERGY LOUISIANA, LLC.

Status Report of Decommissioning Funding For Year Ending December 31, 2024 - 10 CFR 50.75(f)(1)

Plant Name: River Bend Station (30% Non-Regulated Interest)

1. Minimum Financial Assurance (MFA)

Estimated per 10 CFR 50.75(b) and (c) (2024$):

$200.6 million26

2. ISFSI Obligation as of 12/31/24

$3.44 million27

3. Decommissioning Fund Total As of 12/31/24:

$712.3 million

4. Annual amounts remaining to be collected:

None

5. Assumptions used:

Rate of Escalation of Decommissioning Costs:

See next item Rate of Earnings on Decommissioning Funds:

2% real rate of return per 10 CFR 50.75(e)(1)(i)

Authority for use of Real Earnings Over 2%:

N/A

6. Contracts upon which licensee is relying For Decommissioning Funding:

None28

7. Modifications to Method of Financial Assurance since Last Report:

None

8. Material Changes to Trust Agreements:

None 26 See Attachment 3-A.

27 From Entergys ISFSI Decommissioning Funding Plans Pursuant to 10 CFR 72.30, December 05, 2024 (Accession No. ML24340A243), 30% of River Bend value.

28 The River Bend 30% share is sold under contract, but since the 30% share is fully funded with a pre-paid decommissioning fund, the licensee does not rely on this contract for decommissioning (although it does contain some decommissioning provisions). See the agreement provided as -E in the decommissioning financial assurance filing dated March 28, 2019, NRC Accession No. ML19087A327, incorporated herein by reference.

CNRO2025-00004 Entergy Louisiana, LLC - Waterford 3 Status Report

CNRO2025-00004 Page 1 of 1 ENTERGY LOUISIANA, LLC.

Status Report of Decommissioning Funding For Year Ending December 31, 2024 - 10 CFR 50.75(f)(1)

Plant Name: Waterford 3 Steam Electric Station

1. Minimum Financial Assurance (MFA)

Estimated per 10 CFR 50.75(b) and (c) (2024$):

$549.6 million29

2. ISFSI Obligation as of 12/31/24

$10.69 million30

3. Decommissioning Fund Total As of 12/31/24:

$914.4 million

4. Annual amounts remaining to be collected:

See Footnote31

5. Assumptions used:

Rate of Escalation of Decommissioning Costs:

See item below Rate of Earnings on Decommissioning Funds:

2% real rate of return per 10 CFR 50.75(e)(1)(i)

Authority for use of Real Earnings Over 2%:

N/A

6. Contracts upon which licensee is relying For Decommissioning Funding:

See Footnote32

7. Modifications to Method of Financial Assurance since Last Report:

None

8. Material Changes to Trust Agreements:

None 29 See Attachment 4-A.

30 From Entergys ISFSI Decommissioning Funding Plans Pursuant to 10 CFR 72.30, December 05, 2024 (Accession No. ML24340A243).

31 Decommissioning funds are currently being collected for Waterford 3, however, as a conservatism and to simplify this report, Entergy is not relying on those funds for this report.

32 See the unit power purchase agreement under a FERC tariff for Waterford 3 provided as Attachment 4-C in the decommissioning financial assurance filing dated March 25, 2021, NRC Accession No. ML21084A809, incorporated herein by reference. That unit power purchase agreement was replaced with the agreement provided in Attachment 4-B below, effective January 1, 2025. The licensee believes these agreements do not qualify as contractual obligations, but rather are simply cost of service recovery mechanisms as defined in 10 CFR §50.75(e)(1)(ii)(A). Out of an abundance of caution, the licensee identifies this information here.

-A CNRO2025-00004 Entergy Louisiana, LLC - Calculation of Minimum Amount Waterford 3

CNRO2025-00004 -A Page 1 of 1 ENTERGY LOUISIANA, LLC.

Calculation for Minimum Amount For Year Ending December 31, 2024 - 10 CFR 50.75(f)(1)

Entergy Louisiana, LLC:

100% ownership interest Plant Location:

Taft, Louisiana Reactor Type:

Pressurized Water Reactor ("PWR")

Power Level:

>3,400 MWt PWR Base Year 1986$:

$105,000,000 Labor Region:

South Waste Burial Facility:

Generic Disposal Site 10 CFR 50.75(c)(2) Escalation Factor Formula:

0.65(L) +0.13(E) +0.22(B)

Factor L=Labor (South) 3.2733 E=Energy (PWR) 2.9234 B=Waste Burial-Vendor (PWR) 12.40535 PWR Escalation Factor:

0.65(L) +0.13(E) +0.22(B)=

5.23 1986 PWR Base Year $ Escalated:

$105,000,000

• Factor=

$549,591,000 33 Bureau of Labor Statistics, Series Report ID: CIU2010000000220i (4th Quarter 2024) 34 Bureau of Labor Statistics, Series Report ID: wpu0543 and wpu0573 (December 2024) 35 Nuclear Regulatory Commission: NUREG-1307 Revision 20, Table 2-1 (2024)

-B CNRO2025-00004 Entergy Louisiana, LLC - Waterford 3 Purchase Power Agreement

AGREEMENT This Agreement is effective as of January 1, 2025, between Entergy Louisiana, LLC (ELL or Seller) and Entergy New Orleans, LLC (ENO or Buyer, and together with the Seller, the Parties).

WHEREAS, the former Entergy Louisiana, LLC (Legacy ELL) transferred to the former Entergy New Orleans, Inc. (Legacy ENO) certain Legacy ELL assets (and related liabilities) that are necessary to provide electric service to customers in the Fifteenth Ward of the City of New Orleans, commonly referred to as Algiers (the Algiers Transaction); and WHEREAS, as part of the Algiers Transaction, Legacy ELL agreed to make a unit power sale from the designated generating units and designated power purchase agreements set forth on Attachment A (respectively, Designated Generating Units and Designated Power Purchases) to Legacy ENO; and WHEREAS, the Agreement among Entergy Arkansas, Inc., Legacy ELL, Legacy ENO, Entergy Mississippi, Inc. and Entergy Services, Inc. (hereinafter referred to as the System Agreement), was filed with FERC on April 30, 1982, and became effective on January 1, 1983, and was amended in 1993 to incorporate Entergy Gulf States, Inc., and its successors Entergy Gulf States Louisiana, L.L.C. (EGSL or Legacy EGSL) and Entergy Texas, Inc., in 2008; and WHEREAS, on October 1, 2015, Legacy EGSL and Legacy ELL completed a transaction in which those entities combined substantially all of their respective assets and liabilities into a single successor public utility operating company now known as ELL; and WHEREAS, on October 1, 2015, ELL succeeded to the tariffs and rate schedules of Legacy EGSL and Legacy ELL; and CNRO2025-00004 -B Page 1 of 7

2 WHEREAS, pursuant to a Settlement Agreement approved by FERC in Docket Nos.

ER14-75, et al., on December 29, 2015, the System Agreement terminated effective August 31, 2016 at 11:59:59 Central Daylight Time; and WHEREAS, the Parties previously executed this Agreement to provide for a unit power purchase by Buyer under System Agreement Service Schedule MSS-4 from the Designated Generating Units and Designated Power Purchases; and WHEREAS, the Entergy Operating Committee previously considered and approved the terms of this Agreement; and WHEREAS, upon termination of the System Agreement, the Parties intended to apply the terms and conditions of the Unit Power Sales and Designated Power Purchases Tariff accepted by FERC in Docket No. ER13-1508 (Sales and Purchases Tariff), which was designed to replicate System Agreement Service Schedule MSS-4 as the umbrella tariff for this Agreement; and WHEREAS, on November 30, 2017, Legacy ENO completed an internal restructuring transaction in which substantially all of Legacy ENOs assets and liabilities were succeeded to by a newly-formed successor public utility operating company now known as ENO; and WHEREAS, on November 30, 2017, ENO succeeded to the tariffs and rate schedules of Legacy ENO; THEREFORE, the Parties agree as follows:

1.

Designated Generating Units. Subject to the other terms of this Agreement, Seller agrees to sell and Buyer agrees to purchase that quantity of generating capacity and associated energy from the Designated Generating Units on a life-of-unit basis under the Sales and Purchases Tariff, as described herein, equivalent to the Buyers Allocated Percentage of Sellers CNRO2025-00004 -B Page 2 of 7

3 Unit Capacity of the Designated Generating Units, all as set forth on Attachment A. Buyers Allocated Percentage will remain fixed as specified on Attachment A for the entire term of this Agreement.

2.

Designated Power Purchases. Subject to the other terms of this Agreement, Seller agrees to sell and Buyer agrees to purchase that quantity of capacity and associated energy from the Designated Power Purchases on a term-of-PPA basis under the Sales and Purchases Tariff, as described herein, equivalent to the Buyers Allocated Percentage of Sellers Unit Capacity of the Designated Power Purchases, all as set forth on Attachment A. Buyers Allocated Percentage will remain fixed as specified on Attachment A for the entire term of this Agreement.

3.

Designated Generating Units and Designated Power Purchases. The designated generating units and designated power purchases for purposes of this unit power purchase under the Sales and Purchases Tariff shall be the units set forth on Attachment A.

4.

Pricing. The pricing of the capacity and energy to be sold and purchased pursuant to paragraphs 1 and 2 above shall be as specified in the Sales and Purchases Tariff. Should the trust funds set aside for Buyers share of the responsibility for Waterford Unit 3 decommissioning be found to be insufficient to cover the aforesaid Buyers share of the cost for such decommissioning, Buyer will promptly pay to Seller such deficit. The Buyer will fully pay for the Buyers share of the decommissioning responsibility for Waterford Unit 3 notwithstanding the operational status of Waterford Unit 3 or any force majeure provisions. All proceeds from decommissioning collections under the Sales and Purchases Tariff pursuant to this Agreement will be deposited to the external sinking fund(s) that collect(s) Buyers decommissioning funding.

CNRO2025-00004 -B Page 3 of 7

4

5.

Energy Entitlement. Buyer is entitled to receive on an hourly basis Buyers Allocated Percentage (set forth in Attachment A) of the energy generated by the Designated Generating Units and the Designated Power Purchases.

6.

Term. The term of this Agreement shall be the operating life of the Designated Generating Units and the contractual end dates of the Designated Power Purchases, plus any time required to decommission the Designated Generating Units.

7.

Termination. Neither party shall have the right to terminate the unit power purchase and sale required by this Agreement without the express written consent of the other party.

8.

Condition Precedent. This contract shall be conditioned upon Buyer and Seller receiving all regulatory approvals required for this Agreement.

9.

Notices. Unless specifically stated otherwise herein, any notice to be given hereunder shall be sent by Registered Mail, postage prepaid, to the party to be notified at the address set forth below, and shall be deemed given when so mailed.

To ELL:

Entergy Louisiana, LLC 4809 Jefferson Highway Jefferson, LA 70121 ATTN: Chief Executive Officer To ENO:

Entergy New Orleans, LLC 1600 Perdido Street, Bldg. No. 505 New Orleans, LA 70112 ATTN: Chief Executive Officer

10.

Nonwaiver. The failure of either party to insist upon or enforce, in any instance, strict performance by the other of any of the terms of this Agreement or to exercise any rights herein conferred shall not be considered as a waiver or relinquishment to any extent of its rights to assert or rely upon any such terms or rights on any future occasion.

CNRO2025-00004 -B Page 4 of 7

CNRO2025-00004 -B Page 5 of 7

CNRO2025-00004 -B Page 6 of 7

ATTACHMENT A SALE OF CAPACITY AND ENERGY BY ENTERGY LOUISIANA, LLC TO ENTERGY NEW ORLEANS, LLC This Attachment A is attached to and forms a part of the Agreement, effective as of January 1, 2025, between Entergy New Orleans, LLC (ENO or Buyer) and Entergy Louisiana, LLC (ELL or Seller) pursuant to the Unit Power Sales and Designated Power Purchases Tariff.

During the term of this Agreement, Buyers Allocated Percentage of capacity and associated energy will be determined as follows:

SELLERS BUYERS BUYERS UNIT ALLOCATED ALLOCATED CAPACITY*

CAPACITY*

PERCENTAGE DESIGNATED GENERATING UNITS Waterford Unit 2 410.8 7.6 1.84%

Waterford Unit 3 1,156.4 21.3 1.84%

Waterford Unit 4 33.4 0.6 1.84%

Ninemile Point Unit 4 699.0 12.9 1.84%

Ninemile Point Unit 5 716.9 13.2 1.84%

Ninemile Point Unit 6***

308.0 5.7 1.84%

Little Gypsy Unit 2 410.7 7.6 1.84%

Little Gypsy Unit 3 520.3 9.6 1.84%

Acadia Power Block 2***

363.6 6.7 1.84%

River Bend 30 194.5 3.6 1.84%

Perryville Unit 1***

132.5 2.4 1.84%

Perryville Unit 2***

36.5 0.7 1.84%

Sterlington Unit 7A 59.3 1.1 1.84%

DESIGNATED POWER PURCHASES Oxy-Taft Renewal (July 1, 2018 - May 31, 2028) 480.0 8.8 1.84%

Vidalia (expires December 31, 2031) 105.3 1.9 1.84%

Arkansas Nuclear One - Unit 2 26.7 0.5 1.84%

Arkansas Nuclear One - Unit 1 22.7 0.4 1.84%

White Bluff Unit 1 13.1 0.2 1.84%

White Bluff Unit 2 12.2 0.2 1.84%

Independence Unit 1 7.2 0.1 1.84%

TOTAL**

5,640.0 103.8 1.84%

• Expressed in megawatts. To the extent Sellers Unit Capacity in any Designated Generating Unit or Designated Power Purchase increases or decreases, Buyers Allocated Capacity with respect to such Designated Generating Unit or Designated Power Purchase shall adjust so that it equals the product of Sellers Unit Capacity and Buyers Allocated Percentage. Buyers Allocated Percentage will remain fixed for the entire Term of the Agreement.

• • Total may not add due to rounding.

• • • The starting point for the amount of Sellers Capacity for Ninemile Point Unit 6 (308.0 MW), Perryville Unit 1 (132.5 MW), Perryville Unit 2 (36.5 MW), and Acadia Power Block 2 (363.6 MW) is Legacy ELLs share, as opposed to Legacy EGSLs or the Combined Companys share.

CNRO2025-00004 -B Page 7 of 7

CNRO2025-00004 Minimum Funding Assurance Calculation Worksheets

CNRO2025-00004 Page 1 of 7

CNRO2025-00004 Page 2 of 7

CNRO2025-00004 Page 3 of 7

CNRO2025-00004 Page 4 of 7

CNRO2025-00004 Page 5 of 7

CNRO2025-00004 Page 6 of 7

CNRO2025-00004 Page 7 of 7