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Rate And Regulatory Matters
 12 Months Ended
Dec. 31, 2024
Public Utilities Disclosure [Text Block] RATE AND REGULATORY MATTERS (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Regulatory Assets and Regulatory 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. In addition to the regulatory assets and liabilities that are specifically disclosed on the face of the balance sheets, the tables below provide detail of “Other regulatory assets” and “Other regulatory liabilities” that are included on Entergy’s and the Registrant Subsidiaries’ balance sheets as of December 31, 2024 and 2023 (as noted in footnotes to the tables, a portion of these regulatory assets and regulatory liabilities is classified as held for sale in the balance sheets as of December 31, 2024):

Other Regulatory Assets

Entergy
20242023
 (In Millions)
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
$1,387.6 $1,655.5 
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or shutdown of non-nuclear power plants and solar facilities (Note 9) (a)
1,358.7 1,285.0 
Removal costs (Note 9)
1,107.6 1,010.7 
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators and Note 5 - Securitization Bonds)
547.3 536.9 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
227.1 250.9 
Retail rate deferrals - recovered through formula rates or rate riders as rates are redetermined by retail regulators
195.1 248.6 
Retired electric and gas meters - recovered through retail rates as determined by retail regulators (Note 2 - Retail Rate Proceedings)
135.7 153.8 
Deferred COVID-19 costs - recovered through retail rates as determined by retail regulators (Note 2 - Retail Rate Proceedings)
104.0 118.0 
Unamortized loss on reacquired debt - recovered over term of debt
57.9 63.1 
Advanced metering system surcharge for residential customers - recovered through December 2029
39.7 20.2 
Formula rate plan historical year rate adjustment (Note 2 - Retail Rate Proceedings) (b)
15.5 — 
Pension & postretirement benefits expense deferral - recovered through retail rates (Note 2 - Retail Rate Proceedings and Note 11 - Entergy Texas Reserve)
15.0 32.7 
Rate case depreciation relate back deferral - recovered over a six-month period beginning January 2024 (Note 2 - Retail Rate Proceedings)
— 27.6 
Opportunity sales - (Note 2 - Entergy Arkansas Opportunity Sales Proceeding) (b)
— 131.8 
Other99.7 134.6 
Entergy Total (c)
$5,290.9 $5,669.4 
Entergy Arkansas
 20242023
 (In Millions)
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or shutdown of non-nuclear power plants and solar facilities (Note 9) (a)
$693.0 $639.1 
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
433.3 536.6 
Removal costs (Note 9)
337.9 319.7 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
75.8 84.1 
Deferred COVID-19 costs - recovered over a 10-year period through December 2033
35.1 39.0 
Retired electric meters - recovered over a 15-year period through March 2034
32.8 36.3 
Storm damage costs - recovered through retail rates
29.8 33.1 
Unamortized loss on reacquired debt - recovered over term of debt
18.6 19.9 
Formula rate plan historical year rate adjustment (Note 2 - Retail Rate Proceedings) (b)
15.5 — 
Retail rate deferrals - recovered through rate riders as rates are redetermined annually (b)
13.6 24.9 
ANO Fukushima and Flood Barrier costs - recovered through retail rates through February 2026 (b)
2.1 3.8 
Opportunity sales - (Note 2 - Entergy Arkansas Opportunity Sales Proceeding) (b)
— 131.8 
Other12.6 17.1 
Entergy Arkansas Total$1,700.1 $1,885.4 

Entergy Louisiana
 20242023
 (In Millions)
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or shutdown of non-nuclear power plants (Note 9) (a)
$421.5 $408.7 
Pension & postretirement costs (Note 11 - Qualified Pension Plans and Non-Qualified Pension Plans) (a)
367.7 412.0 
Removal costs (Note 9)
323.2 262.3 
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)
226.6 202.6 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
111.4 123.0 
Retired electric and gas meters - recovered over a 22-year period through July 2041
78.5 83.2 
Deferred COVID-19 costs - recovery period to be determined (Note 2 - Retail Rate Proceedings) (a)
47.8 47.8 
Unamortized loss on reacquired debt - recovered over term of debt
21.7 23.4 
Other48.5 85.9 
Entergy Louisiana Total (c)
$1,646.9 $1,648.9 
Entergy Mississippi
 20242023
(In Millions)
Removal costs (Note 9)
$184.8 $188.0 
Retail rate deferrals - recovered through formula rates or rate riders as rates are redetermined annually
162.5 192.8 
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
112.1 127.6 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
29.1 32.0 
Asset retirement obligation - recovery dependent upon timing of shutdown of non-nuclear power plants and solar facility (Note 9) (a)
9.4 6.8 
Unamortized loss on reacquired debt - recovered over term of debt
9.1 10.0 
Attorney General litigation costs - recovered over a six-year period through March 2026 (b)
6.0 10.9 
Other12.8 11.0 
Entergy Mississippi Total$525.8 $579.1 

Entergy New Orleans
 20242023
 (In Millions)
Removal costs (Note 9)
$62.5 $61.1 
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
22.9 41.4 
Retired electric and gas meters - recovered over a 12-year period through July 2031 (b)
13.5 15.5 
Gas cross-boring costs - recovered through formula rates as rates are redetermined by retail regulators
11.9 10.9 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
10.8 11.8 
Deferred COVID-19 costs - recovered over a five-year period through August 2028 (b)
10.2 13.0 
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators and Note 5 - Entergy New Orleans Securitization Bonds - Hurricane Isaac)
4.0 3.9 
Unamortized loss on reacquired debt - recovered over term of debt
0.5 0.8 
Other20.7 24.0 
Entergy New Orleans Total (c)
$157.0 $182.4 
Entergy Texas
 20242023
 (In Millions)
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators and Note 5 - Entergy Texas Securitization Bonds - Hurricane Laura, Hurricane Delta, and Winter Storm Uri)
$286.5 $297.3 
Removal costs (Note 9)
102.3 77.5 
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
62.9 85.6 
Advanced metering system surcharge for residential customers - recovered through December 2029
39.7 20.2 
Pension & postretirement benefits expense deferral - recovered through retail rates (Note 2 - Retail Rate Proceedings and Note 11 - Entergy Texas Reserve)
15.0 32.7 
Retired electric meters - recovered through retail rates (Note 2 - Retail Rate Proceedings)
10.9 18.8 
Neches and Sabine costs - recovered over a 10-year period through September 2028
9.2 11.6 
Unamortized loss on reacquired debt - recovered over term of debt
7.6 8.3 
Rate case depreciation relate back deferral - recovered over a six-month period beginning January 2024 (Note 2 - Retail Rate Proceedings)
— 27.6 
Other15.6 17.0 
Entergy Texas Total$549.7 $596.6 

System Energy
 20242023
 (In Millions)
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear unit (Note 9) (b)
$224.8 $222.0 
Pension & postretirement costs (Note 11 - Qualified Pension Plans and Other Postretirement Benefits) (a)
104.4 121.6 
Removal costs - recovered through depreciation rates (Note 9)
96.9 102.1 
Unamortized loss on reacquired debt - recovered over term of debt
0.4 0.7 
System Energy Total$426.5 $446.4 

(a)Does not earn a return on investment, but is offset by related liabilities.
(b)Does not earn a return on investment.
(c)Includes $35.4 million at Entergy, $8.9 million at Entergy Louisiana, and $23.7 million at Entergy New Orleans as of December 31, 2024 of regulatory assets related to the respective natural gas distribution businesses classified as held for sale and included within “Non-current assets held for sale” on the respective consolidated balance sheets. See Note 14 to the financial statements for further discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses and the classification as held for sale.
Other Regulatory Liabilities

Entergy
20242023
(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)
$2,262.5 $1,826.2 
Securitization financing savings obligation (Note 3)
371.3 405.2 
Retail rate rider over-recovery - refunded through formula rate or rate riders as rates are redetermined by retail regulators
164.9 142.7 
Credits from resolution of the 2016-2018 IRS audit (Note 3)
163.3 98.0 
Customer rate credits from global stipulated settlement with the LPSC - returned to customers September 2024 through August 2026 (Note 2)
121.7 — 
Refund from System Energy settlement with the LPSC - to be returned to customers January 2025 through August 2027 (Note 2)
75.8 — 
Deferred tax equity partnership earnings (Note 1)
69.9 57.9 
Vidalia purchased power agreement (Note 8)
67.4 82.5 
Refund from System Energy settlement with the City Council - returned to customers over a 25-year period beginning September 2024 (Note 2)
64.7 — 
Shorter-term financing interest earnings (Note 2 - Retail Rate Proceedings) (a)
48.9 36.8 
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and the FERC
44.4 44.4 
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)
40.9 44.3 
Refund from System Energy settlement with the City Council - return to customers to be determined (Note 2)
32.0 — 
Refund from System Energy settlement with the APSC - refunded through a rate rider as rates are re-determined periodically (Note 2)
8.2 93.0 
Complaints against System Energy - potential future refunds (Note 2)
— 177.9 
Other75.2 108.0 
Entergy Total (b)
$3,611.1 $3,116.9 

Entergy Arkansas
 20242023
 (In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)
$761.3 $621.6 
Deferred tax equity partnership earnings (Note 1)
32.4 27.4 
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually
27.9 10.6 
Refund from System Energy settlement with the APSC - refunded through a rate rider as rates are re-determined periodically (Note 2)
8.2 93.0 
Internal restructuring guaranteed customer credits - returned to customers over a six-year period through December 2024
— 6.6 
Other1.4 — 
Entergy Arkansas Total$831.2 $759.2 
Entergy Louisiana
 20242023
 (In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)
$798.4 $644.0 
Securitization financing savings obligation (Note 3)
371.3 405.2 
Customer rate credits from global stipulated settlement with the LPSC - returned to customers September 2024 through August 2026 (Note 2)
121.7 — 
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually
96.3 86.4 
Refund from System Energy settlement with the LPSC - to be returned to customers January 2025 through August 2027 (Note 2)
75.8 — 
Vidalia purchased power agreement (Note 8)
67.4 82.5 
Shorter-term financing interest earnings (Note 2 - Retail Rate Proceedings) (a)
48.9 36.8 
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)
40.9 44.3 
Hurricane Ida insurance proceeds - returned to customers August 2024 to July 2025
26.0 32.3 
Credits from resolution of the 2016-2018 IRS audit - returned to customers September 2024 through August 2025 (Note 3)
25.3 38.0 
Sale-leaseback and depreciation refunds - returned to customers September 2023 through August 2024
— 14.1 
Other21.7 24.1 
Entergy Louisiana Total (b)
$1,693.7 $1,407.7 

Entergy Mississippi
20242023
 (In Millions)
Deferred tax equity partnership earnings (Note 1)
$37.5 $30.5 
Retail rate rider over-recovery - refunded through formula rate or rate riders as rates are redetermined annually
12.2 2.4 
Other postretirement benefits (Note 11 - Entergy Mississippi Other Postretirement Benefits)
7.4 — 
Other2.4 0.8 
Entergy Mississippi Total$59.5 $33.7 
Entergy New Orleans
20242023
 (In Millions)
Credits from resolution of the 2016-2018 IRS audit - to be returned to customers over a 25-year period beginning January 2025 (Note 3)
$138.0 $60.0 
Refund from System Energy settlement with the City Council - returned to customers over a 25-year period beginning September 2024 (Note 2)
64.7 — 
Refund from System Energy settlement with the City Council - return to customers to be determined (Note 2)
32.0 — 
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually
16.3 20.1 
Sale-leaseback and depreciation refunds - returned to customers over a 10-year period beginning September 2023 (Note 2)
5.2 9.8 
Other4.5 0.5 
Entergy New Orleans Total (b)
$260.7 $90.4 

Entergy Texas
 20242023
 (In Millions)
Retail rate rider over-recovery - return to customers to be determined
$12.2 $23.8 
Retail refunds - return to customers to be determined
6.2 6.2 
Rate case settlement relate back - amortized over a six-month period beginning January 2024 (Note 2 - Retail Rate Proceedings)
— 10.3 
Other 0.3 2.7 
Entergy Texas Total$18.7 $43.0 

System Energy
 20242023
 (In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)
$702.8 $560.6 
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and the FERC
44.4 44.4 
Complaints against System Energy - potential future refunds (Note 2)
— 177.9 
System Energy Total$747.2 $782.9 

(a)Offset by related asset.
(b)Includes $1.6 million at Entergy, $1.2 million at Entergy Louisiana, and $0.4 million at Entergy New Orleans as of December 31, 2024 of regulatory liabilities related to the respective natural gas distribution businesses classified as held for sale and included within other non-current liabilities on the respective consolidated balance sheets. See Note 14 to the financial statements for further discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses and the classification as held for sale.
Regulatory activity regarding the Tax Cuts and Jobs Act

See the “Other Tax Matters - Tax Cuts and Jobs Act” section in Note 3 to the financial statements for discussion of the effects of the December 2017 enactment of the Tax Cuts and Jobs Act (Tax Act), including its effects on Entergy’s and the Registrant Subsidiaries’ regulatory asset/liability for income taxes.

Entergy Louisiana

In an electric formula rate plan settlement approved by the LPSC in April 2018, the parties agreed that Entergy Louisiana would return to customers one-half of its eligible unprotected excess deferred income taxes from May 2018 through December 2018 and return to customers the other half from January 2019 through August 2022. In addition, the settlement provided that in order to flow back to customers certain other tax benefits created by the Tax Act, Entergy Louisiana established a regulatory liability effective January 1, 2018 in the amount of $9.1 million per month to reflect these tax benefits already included in retail rates until new base rates under the formula rate plan were established in September 2018, and this regulatory liability was returned to customers over the September 2018 through August 2019 formula rate plan rate-effective period. The LPSC staff and intervenors in the settlement reserved the right to obtain data from Entergy Louisiana to confirm the determination of excess accumulated deferred income taxes resulting from the Tax Act and the analysis thereof as part of the formula rate plan review proceeding for the 2017 test year filing. As discussed below in “Retail Rate Proceedings - Filings with the LPSC (Entergy Louisiana) - Retail Rates - Electric - Formula Rate Plan Global Settlement”, a global settlement resolving the outstanding issues related to the 2017 formula rate plan filing was reached in October 2023 and approved by the LPSC in November 2023.

System Energy

In a filing made with the FERC in March 2018, System Energy proposed revisions to the Unit Power Sales Agreement to reflect the effects of the Tax Act. In the filing System Energy proposed to return identified quantities of unprotected excess accumulated deferred income taxes to its customers by the end of 2018. In May 2018 the FERC accepted System Energy’s proposed tax revisions with an effective date of June 1, 2018, subject to refund and the outcome of settlement and hearing procedures. Settlement discussions were terminated in April 2019, and a hearing was held in March 2020. In December 2022 the FERC issued an order requiring System Energy to compute the amount of excess accumulated deferred income taxes associated with a previously uncertain decommissioning tax position with consideration for the resolution of the tax position by the IRS. In February 2023, System Energy submitted its compliance filing. This matter was ultimately settled as a result of System Energy’s settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” below for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.
Fuel and purchased power cost recovery

The Utility operating companies are allowed to recover fuel and purchased power costs through fuel mechanisms included in electric and gas rates that are recorded as fuel cost recovery revenues.  The difference between revenues collected and the current fuel and purchased power costs is generally recorded as “Deferred fuel costs” on the Utility operating companies’ financial statements.  The table below shows the amount of deferred fuel costs as of December 31, 2024 and 2023 that each Utility operating company expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.

 20242023
 (In Millions)
Entergy Arkansas
($45.2)($88.3)
Entergy Louisiana (a) (b)$163.4 $192.9 
Entergy Mississippi($126.3)($130.6)
Entergy New Orleans (a) (b)$8.0 $10.2 
Entergy Texas($59.3)$139.0 

(a)Includes $168.1 million in both years for Entergy Louisiana and $4.1 million in both years for Entergy New Orleans of fuel, purchased power, and capacity costs, which do not currently earn a return on investment and whose recovery periods are indeterminate but are expected to be recovered over a period greater than twelve months.
(b)Includes $0.7 million at Entergy Louisiana and $4.9 million at Entergy New Orleans as of December 31, 2024 of deferred fuel assets related to the respective natural gas distribution businesses classified as held for sale and included within “Current assets held for sale” on the respective consolidated balance sheets. See Note 14 to the financial statements for further discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses and the classification as held for sale.

Entergy Arkansas

Energy Cost Recovery Rider

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

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

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

In March 2018, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01547 per kWh to $0.01882 per kWh. The Arkansas Attorney General filed a response to Entergy Arkansas’s annual redetermination filing requesting that the APSC suspend the proposed tariff to investigate the amount of the redetermination or, alternatively, to allow recovery subject to refund. Among the reasons the Attorney General cited for suspension were questions pertaining to how Entergy Arkansas forecasted sales and potential implications of the Tax Cuts and Jobs Act. Entergy Arkansas replied to the Attorney General’s filing and stated that, to the extent there are questions pertaining to its load forecasting or the operation of the energy cost recovery rider, those issues exceed the scope of the instant rate redetermination. Entergy Arkansas also stated that potential effects of the Tax Cuts and Jobs Act are appropriately considered in the APSC’s separate proceeding regarding potential implications of the tax law. The APSC general staff filed a reply to the Attorney General’s filing and agreed that Entergy Arkansas’s filing complied with the terms of the energy cost recovery rider. The redetermined rate became effective with the first billing cycle of April 2018. Subsequently in April 2018 the APSC issued an order declining to suspend Entergy Arkansas’s energy cost recovery rider rate and declining to require further investigation at that time of the issues suggested by the Attorney General in the proceeding. Following a period of discovery, the Attorney General filed a supplemental response in October 2018 raising new issues with Entergy Arkansas’s March 2018 rate redetermination and asserting that $45.7 million of the increase should be collected subject to refund pending further investigation. Entergy Arkansas filed to dismiss the Attorney General’s supplemental response, the APSC general staff filed a motion to strike the Attorney General’s filing, and the Attorney General filed a supplemental response disputing Entergy Arkansas and the APSC staff’s filing. Applicable APSC rules and processes authorize its general staff to initiate periodic audits of Entergy Arkansas’s energy cost recovery rider. In late-2018 the APSC general staff notified Entergy Arkansas it initiated an audit of the 2017 fuel costs. The time in which the audit will be complete is uncertain at this time.

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

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

In March 2024, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease in the rate from $0.01883 per kWh to $0.00882 per kWh. Due to a change in law in the State of Arkansas, the annual redetermination included $9 million, recorded as a credit to fuel expense in first quarter 2024, for recovery attributed to net metering costs in 2023. The primary reason for the rate decrease is a large over-recovered balance as a result of lower natural gas prices in 2023. To mitigate the effect of projected increases in natural gas prices in 2024, Entergy Arkansas adjusted the over-recovered balance included in the March 2024 annual redetermination filing by $43.7 million. This adjustment is expected to reduce the rate change that will be reflected in the 2025 energy cost rate redetermination. The redetermined rate of $0.00882 per kWh became effective with the first billing cycle in April 2024 through the normal operation of the tariff.

Entergy Louisiana

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

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

In March 2020 the LPSC staff provided notice of an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2016 through 2019. The LPSC staff issued its audit report in September 2021, and although certain internal record keeping recommendations were made, the LPSC staff did not recommend any disallowances. The next step is for the LPSC to review the report, but there is not a deadline for the review.

In January 2023 the LPSC staff provided notice of an audit of Entergy Louisiana’s purchased gas adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s purchased gas adjustment clause for the period from 2021 through 2022. Discovery is ongoing, and no audit report has been filed.
In January 2023 the LPSC staff provided notice of an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2020 through 2022. Discovery is ongoing, and no audit report has been filed.

Entergy Mississippi

Entergy Mississippi’s rate schedules include an energy cost recovery rider and a power management rider, both of which are adjusted annually to reflect accumulated over- or under-recoveries. Entergy Mississippi recovers fuel and purchased energy costs through its energy cost recovery rider and recovers costs associated with natural gas hedging and capacity payments through its power management rider. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.

In November 2021, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an under-recovery of approximately $80.6 million as of September 30, 2021. In December 2021, at the request of the MPSC, Entergy Mississippi submitted a proposal to mitigate the impact of rising fuel costs on customer bills during 2022. Entergy Mississippi proposed that the deferred fuel balance as of December 31, 2021, which was $121.9 million, be amortized over three years and that the MPSC authorize Entergy Mississippi to apply its weighted-average cost of capital as the carrying cost for the unamortized fuel balance. In January 2022 the MPSC approved the amortization of $100 million of the deferred fuel balance over two years and authorized Entergy Mississippi to apply its weighted-average cost of capital as the carrying cost for the unamortized fuel balance. The MPSC approved the proposed energy cost factor effective for February 2022 bills.

See “Complaints Against System Energy - System Energy Settlement with the MPSC” below for discussion of the settlement agreement filed with the FERC in June 2022. The settlement, which was approved by the FERC in November 2022, provided for a refund of $235 million from System Energy to Entergy Mississippi. In July 2022 the MPSC directed the disbursement of settlement proceeds, ordering Entergy Mississippi to provide a one-time $80 bill credit to each of its approximately 460,000 retail customers to be effective during the September 2022 billing cycle and to apply the remaining proceeds to Entergy Mississippi’s under-recovered deferred fuel balance. In accordance with the MPSC’s directive, Entergy Mississippi provided approximately $36.7 million in customer bill credits as a result of the settlement. In November 2022, Entergy Mississippi applied the remaining settlement proceeds in the amount of approximately $198.3 million to Entergy Mississippi’s under-recovered deferred fuel balance.

Entergy Mississippi had a deferred fuel balance of approximately $291.7 million under the energy cost recovery rider as of July 31, 2022, along with an over-recovery balance of $51.1 million under the power management rider. Without further action, Entergy Mississippi anticipated a year-end deferred fuel balance of approximately $200 million after application of a portion of the System Energy settlement proceeds, as discussed above. In September 2022, Entergy Mississippi filed for interim adjustments under both the energy cost recovery rider and the power management rider. Entergy Mississippi proposed five monthly incremental adjustments to the net energy cost factor designed to collect the under-recovered fuel balance as of July 31, 2022 and to reflect the recovery of a higher natural gas price. Entergy Mississippi also proposed five monthly incremental adjustments to the power management adjustment factor designed to flow through to customers the over-recovered power management rider balance as of July 31, 2022. In October 2022 the MPSC approved modified interim adjustments to Entergy Mississippi’s energy cost recovery rider and power management rider. The MPSC approved dividing the energy cost recovery rider interim adjustment into two components that would allow Entergy Mississippi to (1) recover a natural gas fuel rate that is better aligned with current prices; and (2) recover the estimated under-recovered deferred fuel balance as of September 30, 2022 over a period of 20 months. The MPSC approved six monthly incremental adjustments to the net energy cost factor designed to reflect the recovery of a higher natural gas price. The MPSC also approved six monthly incremental adjustments to the power management adjustment factor designed to flow through to customers the over-recovered power management rider balance. In accordance
with the order of the MPSC, Entergy Mississippi did not file an annual redetermination of the energy cost recovery rider or the power management rider in November 2022.

In June 2023 the MPSC approved the joint stipulation agreement between Entergy Mississippi and the Mississippi Public Utilities Staff for Entergy Mississippi’s 2023 formula rate plan filing. The stipulation directed Entergy Mississippi to make a compliance filing to revise its power management cost adjustment factor, to revise its grid modernization cost adjustment factor, and to include a revision to reduce the net energy cost factor to a level necessary to reflect an average natural gas price of $4.50 per MMBtu. The MPSC approved the compliance filing in June 2023, effective for July 2023 bills. See “Retail Rate Proceedings - Filings with the MPSC (Entergy Mississippi) - Retail Rates - 2023 Formula Rate Plan Filing” below for further discussion of the 2023 formula rate plan filing and the joint stipulation agreement.

In November 2023 Entergy Mississippi filed its annual redeterminations of the energy cost factor and the power management cost adjustment factor. The calculation of the annual factor for the energy cost recovery rider included a projected over-recovery balance of approximately $142 million at the end of January 2024. The calculation of the annual factor for the power management rider included a projected under-recovery of $47 million at the end of January 2024. In January 2024 the MPSC approved the proposed energy cost factor and the proposed power management cost factor effective for February 2024 bills.

In June 2024 the MPSC approved the joint stipulation agreement between Entergy Mississippi and the Mississippi Public Utilities Staff for Entergy Mississippi’s 2024 formula rate plan filing. The 2024 formula rate plan filing included the conclusion of the modified interim adjustments to Entergy Mississippi’s energy cost recovery rider and power management rider, which were approved in October 2022 and allowed Entergy Mississippi to recover certain under-collected fuel balances, effective for July 2024 bills. The stipulation provided for Entergy Mississippi to reduce its net energy cost factor. See “Retail Rate Proceedings - Filings with the MPSC (Entergy Mississippi) - Retail Rates - 2024 Formula Rate Plan Filing” below for further discussion of the 2024 formula rate plan filing and the joint stipulation agreement.

In November 2024, Entergy Mississippi filed its annual redeterminations of the energy cost factor and the power management cost adjustment factor. The calculation of the annual factor for the energy cost recovery rider included a projected over-recovery balance of approximately $144.6 million as of September 2024. The calculation of the annual factor for the power management rider included a projected under-recovery of $60.1 million as of September 2024. In January 2025 the MPSC approved a revised energy cost factor, effective for February 2025 bills, that did not reflect the fuel savings associated with Entergy Mississippi’s incremental increase in its share of capacity and energy in connection with Entergy Mississippi’s assumption of Entergy Louisiana’s entitlements to Grand Gulf capacity and energy, which was subject to the MPSC’s review at such time. In February 2025 the MPSC approved Entergy Mississippi’s notice of intent for Entergy Mississippi’s assumption of Entergy Louisiana’s entitlements to Grand Gulf capacity and energy, with associated fuel savings to be reflected in Entergy Mississippi’s energy cost recovery rider, effective for March 2025 bills. Additionally, in February 2025 the MPSC approved the proposed power management cost adjustment factor, effective for March 2025 bills.

Entergy New Orleans

Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.

Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.
Entergy Texas

Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, not recovered in base rates.  Historically, semi-annual revisions of the fixed fuel factor have been made in March and September based on the market price of natural gas and changes in fuel mix.  The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. In 2023 the Texas legislature modified the Texas Utilities Code to provide that material over- and under-recovered fuel balances are to be refunded or surcharged through interim fuel adjustments and that fuel reconciliations must be filed at least once every two years. Entergy Texas expects the PUCT to undertake a rulemaking to effectuate the new legislation in 2025.

In May 2022, Entergy Texas filed an application with the PUCT to implement an interim fuel surcharge to collect the cumulative under-recovery of approximately $51.7 million, including interest, of fuel and purchased power costs incurred from May 1, 2020 through December 31, 2021. The under-recovery balance was primarily attributable to the impacts of Winter Storm Uri, including historically high natural gas prices, partially offset by settlements received by Entergy Texas from MISO related to Hurricane Laura. Entergy Texas proposed that the interim fuel surcharge be assessed over a period of six months beginning with the first billing cycle after the PUCT issues a final order, but no later than the first billing cycle of September 2022. Also in May 2022, the PUCT referred the proceeding to the State Office of Administrative Hearings. In July 2022, Entergy Texas filed on behalf of the parties an unopposed settlement resolving all issues in the proceeding. In addition, Entergy Texas filed on behalf of the parties a motion to admit evidence, to approve interim rates as requested in the initial application, and to remand the proceeding to the PUCT to consider the unopposed settlement. In August 2022 the ALJ with the State Office of Administrative Hearings issued an order granting Entergy Texas’s motion, approving interim rates effective with the first billing cycle of September 2022, and remanding the case to the PUCT for final approval. The interim fuel surcharge was approved by the PUCT in January 2023.

In September 2022, Entergy Texas filed an application with the PUCT to reconcile its fuel and purchased power costs for the period from April 2019 through March 2022. During the reconciliation period, Entergy Texas incurred approximately $1.7 billion in eligible fuel and purchased power expenses, net of certain revenues credited to such expenses and other adjustments. As of the end of the reconciliation period, Entergy Texas’s cumulative under-recovery balance was approximately $103.1 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning April 2022, pending future surcharges or refunds as approved by the PUCT. In November 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In July 2023, Entergy Texas filed an unopposed settlement, supporting testimony, and an agreed motion to admit evidence and remand the proceeding to the PUCT. Pursuant to the unopposed settlement, Entergy Texas would receive no disallowance of fuel costs incurred over the three-year reconciliation period and retain $9.3 million in margins from off-system sales made during the reconciliation period, resulting in a cumulative under-recovery balance of approximately $99.7 million, including interest, as of the end of the reconciliation period. In July 2023 the ALJ with the State Office of Administrative Hearings granted the motion to admit evidence and remanded the proceeding to the PUCT for consideration of the unopposed settlement. The PUCT approved the settlement in September 2023.

In September 2024, Entergy Texas filed an application with the PUCT to reconcile its fuel and purchased power costs for the period from April 2022 through March 2024. During the reconciliation period, Entergy Texas incurred approximately $1.6 billion in eligible fuel and purchased power expenses to generate and purchase electricity to serve its customers, net of certain revenues credited to such expenses and other adjustments. Entergy Texas’s cumulative under-recovery balance for the reconciliation period was approximately $30 million, including interest, which Entergy Texas requested authority to carry over as part of the cumulative fuel balance for the subsequent reconciliation period beginning April 2024. In November 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 procedural schedule, with a hearing on the merits scheduled for May 2025. A PUCT decision is expected in third quarter 2025.
In December 2024, Entergy Texas filed an application with the PUCT to implement an interim fuel refund of $45.5 million, including interest. Entergy Texas proposed that the interim fuel refund be implemented over a three-month period beginning with the first billing cycle in February 2025 for residential and other small customers and through a one-time credit, or surcharge depending on historical usage for the respective customer, for certain transmission voltage level and seasonal agricultural customers in February 2025. Also in December 2024 the PUCT referred the proceeding to the State Office of Administrative Hearings. In January 2025 the ALJ with the State Office of Administrative Hearings issued an order approving the interim fuel refund consistent with Entergy Texas’s application and, because no hearing was requested in the proceeding, dismissing the case from the State Office of Administrative Hearings and the PUCT.
Retail Rate Proceedings

Filings with the APSC (Entergy Arkansas)

Retail Rates

2022 Formula Rate Plan Filing

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

2023 Formula Rate Plan Filing

In July 2023, Entergy Arkansas filed with the APSC its 2023 formula rate plan filing to set its formula rate for the 2024 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2024 and a netting adjustment for the historical year 2022. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2024 projected year was 8.11% resulting in a revenue deficiency of $80.5 million. The earned rate of return on common equity for the 2022 historical year was 7.29% resulting in a $49.8 million netting adjustment. The total proposed revenue change for the 2024 projected year and 2022 historical year netting adjustment was $130.3 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $88.6 million. The APSC general staff and intervenors filed their errors and objections in October 2023, proposing certain adjustments, including the APSC general staff’s update to annual filing year revenues which lowers the constraint to $87.7 million. Entergy Arkansas filed its rebuttal in October 2023. In October 2023, Entergy
Arkansas filed with the APSC a settlement agreement reached with other parties resolving all issues in the proceeding, none of which affected Entergy Arkansas’s requested recovery up to the constraint of $87.7 million. The settlement agreement provided for amortization of the approximately $39 million regulatory asset for costs associated with the COVID-19 pandemic over a 10-year period as well as recovery of $34.9 million related to the resolution of the 2016 and 2017 IRS audits from previous tax positions that are no longer uncertain, partially offset by $24.7 million in excess accumulated deferred income taxes from reductions in state income tax rates, each before consideration of their respective tax gross-up. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit and the State of Arkansas corporate income tax rate changes. In December 2023 the APSC approved the settlement agreement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2024.

2024 Formula Rate Plan Filing

In July 2024, Entergy Arkansas filed with the APSC its 2024 formula rate plan filing to set its formula rate for the 2025 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the 2025 projected year and a netting adjustment for the 2023 historical year. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2025 projected year was 8.43% resulting in a revenue deficiency of $69.5 million. The earned rate of return on common equity for the 2023 historical year was 7.48% resulting in a $33.1 million netting adjustment. The total proposed revenue change for the 2025 projected year and 2023 historical year netting adjustment is $102.6 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $82.6 million. The APSC general staff and intervenors filed their errors and objections in October 2024, proposing certain adjustments, including the APSC general staff’s update to annual filing year revenues that increases the constraint to $83.5 million. Entergy Arkansas filed its rebuttal in October 2024, and later in October 2024 the parties submitted a joint issues list and stipulations setting forth the disputed issues and the noncontested issues. In December 2024 the APSC approved the parties’ stipulations without modification, approved Entergy Arkansas’s adjustment with respect to storm costs, directed Entergy Arkansas to adjust its projected year distribution reliability capital closings, and deferred the recoverability of Entergy Arkansas’s opportunity sales legal fees until the next general rate case. Also in December 2024 the APSC approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2025. As a result of the proceeding, the total revenue change was $82.7 million, including a $63.7 million increase for the 2025 projected year and a $31.4 million netting adjustment for the 2023 historical year. In fourth quarter 2024, Entergy Arkansas recorded a regulatory asset of $15.5 million to reflect the amount of the 2023 historical year netting adjustment that it expects to collect from its customers during the 2025 rate effective period. Pursuant to the terms of the parties’ stipulations, Entergy Arkansas made a filing with the APSC in January 2025 to refund customers $30.1 million in excess accumulated deferred income taxes resulting from the reduction in the State of Arkansas’s income tax rate from 4.8% to 4.3% in 2024. Entergy Arkansas will make this refund over a 24-month period effective with the first billing cycle of February 2025.

Grand Gulf Credit Rider

In June 2024, Entergy Arkansas filed with the APSC a tariff to provide retail customers a credit resulting from the terms of the settlement agreement between Entergy Arkansas, System Energy, additional named Entergy parties, and the APSC pertaining to System Energy’s billings for wholesale sales of energy and capacity from the Grand Gulf nuclear plant. See “Complaints Against System Energy - System Energy Settlement with the APSC” below for discussion of the settlement. In July 2024 the APSC approved the tariff, under which Entergy Arkansas will refund to retail customers a total of $100.6 million. To date, Entergy Arkansas has refunded $92.3 million of the total through one-time bill credits during the August 2024 billing cycle and is finalizing plans for the refund of the remaining regulatory liability balance.
Filings with the LPSC (Entergy Louisiana)

Retail Rates - Electric

2020 Formula Rate Plan Filing

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

In November 2023 the LPSC approved a global settlement which resolved all outstanding issues related to the 2017, 2018, and 2019 formula rate plan filings and resolved certain issues with respect to the 2020 and 2021 formula rate plan filings. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” below for further discussion.

2021 Formula Rate Plan Filing

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

In November 2023 the LPSC approved a global settlement which resolved all outstanding issues related to the 2017, 2018, and 2019 formula rate plan filings and resolved certain issues with respect to the 2020 and 2021
formula rate plan filings. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” below for further discussion.

2022 Formula Rate Plan Filing

In May 2023, Entergy Louisiana filed its formula rate plan evaluation report for its 2022 calendar year operations. The 2022 test year evaluation report produced an earned return on common equity of 8.33%, requiring an approximately $70.7 million increase to base rider revenue. Due to a cap for the 2021 and 2022 test years, however, base rider formula rate plan revenues were only increased by approximately $4.9 million, resulting in a revenue deficiency of approximately $65.9 million and providing for prospective return on common equity opportunity of approximately 8.38%. Other changes in formula rate plan revenue driven by increases in capacity costs, primarily legacy capacity costs, additions eligible for recovery through the transmission recovery mechanism and distribution recovery mechanism, and higher sales during the test period were offset by reductions in net MISO costs as well as credits for FERC-ordered refunds. Also included in the 2022 test year distribution recovery mechanism revenue requirement was a $6 million credit relating to the distribution recovery mechanism performance accountability standards and requirements. In total, the net increase in formula rate plan revenues, including base formula rate plan revenues inside the formula rate plan bandwidth and subject to the cap, as well as other formula rate plan revenues outside of the bandwidth, was $85.2 million. In August 2023 the LPSC staff filed a list of objections/reservations, including outstanding issues from the test years 2017-2021 formula rate plan filings, the calculation of certain refunds from System Energy, and certain calculations relating to the tax reform adjustment mechanism. Subject to LPSC review, the resulting net increase in formula rate plan revenues of $85.2 million became effective for bills rendered during the first billing cycle of September 2023, subject to refund. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” below for further discussion.

2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request

In August 2023, Entergy Louisiana filed an application for approval of a regulatory blueprint necessary for it to strengthen the electric grid for the State of Louisiana, which contained a dual-path request to update rates through either: (1) extension of Entergy Louisiana’s current formula rate plan (with certain modifications) for three years (the Rate Mitigation Proposal), which is Entergy Louisiana’s recommended path; or (2) implementation of rates resulting from a cost-of-service study (the Rate Case path). The application complied with Entergy Louisiana’s previous formula rate plan extension order requiring that for Entergy Louisiana to obtain another extension of its formula rate plan that included a rate reset, Entergy Louisiana would need to submit a full cost-of-service rate case. Entergy Louisiana’s filing supported the need to extend Entergy Louisiana’s formula rate plan with credit supportive mechanisms needed to facilitate investment in the distribution, transmission, and generation functions.

In July 2024, Entergy Louisiana reached an agreement in principle with the LPSC staff and the intervenors in the proceeding and filed with the LPSC a joint motion to suspend the procedural schedule to allow for all parties to finalize a stipulated settlement agreement.

In August 2024, Entergy Louisiana and the LPSC staff jointly filed a global stipulated settlement agreement for consideration by the LPSC with key terms as follows:

•continuation of the formula rate plan for 2024-2026 (test years 2023-2025);
•a base formula rate plan revenue increase of $120 million for test year 2023, effective for rates beginning September 2024;
•a $140 million cumulative cap on base formula rate plan revenue increases, if needed, for test years 2024 and 2025, excluding outside the bandwidth items;
•$184 million of customer rate credits to be given over two years, including increasing customer sharing of income tax benefits resulting from the 2016-2018 IRS audit, to resolve any remaining disputed issues stemming from formula rate plan test years prior to test year 2023, including but not limited to the investigation into Entergy Services costs billed to Entergy Louisiana. As discussed in Note 3 to the financial statements, a $38 million regulatory liability was recorded in 2023 in connection with the 2016-2018 IRS audit;
•$75.5 million of customer rate credits, as provided for in the System Energy global settlement, to be credited over three years subject to and conditioned upon FERC approval of the System Energy global settlement, which was approved in November 2024. See “Complaints Against System Energy – System Energy Settlement with the LPSC” below for further details of the System Energy global settlement;
•$5.8 million of customer rate credits provided for in the Entergy Louisiana formula rate plan global settlement agreement approved by the LPSC in November 2023 credited over one year. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement;
•an increase in the allowed midpoint return on common equity from 9.5% to 9.7%, with a bandwidth of 40 basis points above and below the midpoint, for the extended term of the formula rate plan, except that for test year 2023 in which the authorized return on common equity shall have no bearing on the change in base formula rate plan revenue described above and, for test year 2024, any earnings above the authorized return on common equity shall be returned to customers through a credit;
•an increase in nuclear depreciation rates by $15 million in each of the 2023, 2024, and 2025 test years outside of the formula rate plan bandwidth calculation; and
•for the transmission recovery mechanism and the distribution recovery mechanism, no change to the existing floors, but the caps for both would be $350 million for test year 2023, $375 million for test year 2024, and $400 million for test year 2025. Transmission projects filed with the LPSC will be exempt from the transmission recovery mechanism cap.

The global stipulated settlement agreement was unanimously approved by the LPSC in August 2024 and an order was issued by the LPSC in September 2024 reflecting the approval of the settlement.

Based on the July 2024 agreement in principle, in second quarter 2024 Entergy Louisiana recorded expenses of $151 million ($112 million net-of-tax) primarily consisting of regulatory charges to reflect the effects of the agreement in principle.

Formula Rate Plan Global Settlement

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

2023 Formula Rate Plan Filing

In August 2024, pursuant to the global stipulated settlement agreement, Entergy Louisiana filed its formula rate plan evaluation report for its 2023 calendar year operations. Consistent with the global stipulated settlement agreement, the filing reflected a 9.7% allowed return on common equity with a bandwidth of 40 basis points above and below the midpoint. For the 2023 test year, however, the bandwidth provisions of the formula rate plan were
temporarily suspended and, pursuant to the terms of the global stipulated settlement agreement, Entergy Louisiana implemented the September 2024 formula rate plan rate adjustments effective with the first billing cycle of September 2024. Those adjustments included a $120 million increase in base rider formula rate plan revenue and a $101.8 million one-time incremental net decrease consistent with the terms of the global stipulated settlement. The formula rate plan rate adjustments reflected in the evaluation report also include a redetermination of the transmission recovery mechanism, the distribution recovery mechanism, the additional capacity mechanism, the tax adjustment mechanism, the MISO cost recovery mechanism, and other one-time adjustments. In January 2025, Entergy Louisiana and the LPSC filed a joint report indicating that no disputed issues remained in the proceeding and requesting that the LPSC issue an order accepting Entergy Louisiana’s evaluation report and, ultimately, resolving this matter. Entergy Louisiana expects a decision on the joint report in first quarter 2025.

Investigation of Costs Billed by Entergy Services

In November 2018 the LPSC issued a notice of proceeding initiating an investigation into costs incurred by Entergy Services that are included in the retail rates of Entergy Louisiana. As stated in the notice of proceeding, the LPSC observed an increase in capital construction-related costs incurred by Entergy Services. Discovery was issued and included efforts to seek highly detailed information on a broad range of matters unrelated to the scope of the audit. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” above for further discussion.

COVID-19 Orders

In April 2020 the LPSC issued an order authorizing utilities to record as a regulatory asset expenses incurred from the suspension of disconnections and collection of late fees imposed by LPSC orders associated with the COVID-19 pandemic. In April 2023, Entergy Louisiana filed an application proposing to utilize approximately $1.6 billion in certain low interest debt to generate earnings to apply toward the reduction of the COVID-19 regulatory asset, as well as to conduct additional outside right-of-way vegetation management activities and fund the minor storm reserve account. In that filing, Entergy Louisiana proposed to delay repayment of certain shorter-term first mortgage bonds that were issued to finance storm restoration costs until the costs could be securitized, and to invest the funds that otherwise would be used to repay those bonds in the money pool to take advantage of the spread between prevailing interest rates on investments in the money pool and the interest rates on the bonds. The LPSC approved Entergy Louisiana’s requested relief in June 2023. In November 2024, Entergy Louisiana submitted a filing to the LPSC requesting that the LPSC review Entergy Louisiana’s computation of the COVID-19 regulatory asset as well as Entergy Louisiana’s proposal to offset the regulatory asset against the interest earned on the short-term debt funds, resulting in no increased costs to customers. At the time of the filing, Entergy Louisiana had a regulatory asset of $47.8 million for costs associated with the COVID-19 pandemic. As of December 31, 2024, Entergy Louisiana had a regulatory liability of $48.9 million for the deferred earnings related to the approximately $1.6 billion in low interest debt, which had been fully repaid by August 2024. In granting Entergy Louisiana’s requested relief in June 2023, the LPSC ordered that any amount of earnings exceeding the amount of the COVID-19 regulatory asset be transferred to Entergy Louisiana’s storm reserve escrow account.

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 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.

Filings with the MPSC (Entergy Mississippi)

Retail Rates

2022 Formula Rate Plan Filing

In March 2022, Entergy Mississippi submitted its formula rate plan 2022 test year filing and 2021 look-back filing showing Entergy Mississippi’s earned return for the historical 2021 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2022 calendar year to be below the formula rate plan bandwidth. The 2022 test year filing showed a $69 million rate increase was necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.70% return on rate base, within the formula rate plan bandwidth. The change in formula rate plan revenues, however, was capped at 4% of retail revenues, which equated to a revenue change of $48.6 million. The 2021 look-back filing compared actual 2021 results to the approved benchmark return on rate base and reflected the need for a $34.5 million interim increase in formula rate plan revenues. In fourth quarter 2021, Entergy Mississippi recorded a regulatory asset of $19 million to reflect the then-current estimate in connection with the look-back feature of the formula rate plan. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $24.3 million interim rate increase, reflecting a cap equal to 2% of 2021 retail revenues, effective in April 2022. With the implementation of the interim formula rate plan rates, Entergy Mississippi began recovery of the bad debt expense deferral resulting from the COVID-19 pandemic over a three-year period.

In June 2022, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed the 2022 test year filing that resulted in a total rate increase of $48.6 million. Pursuant to the joint stipulation, Entergy Mississippi’s 2021 look-back filing reflected an earned return on rate base of 5.99% in calendar year 2021, which was below the look-back bandwidth, resulting in a $34.3 million increase in the formula rate plan revenues on an interim basis through June 2023. In July 2022 the MPSC approved the joint stipulation with rates effective in August 2022. In July 2022, Entergy Mississippi recorded regulatory credits of $22.6 million to reflect the effects of the joint stipulation.
In July 2022 the MPSC directed Entergy Mississippi to flow $14.1 million of the power management rider over-recovery balance to customers beginning in August 2022 through December 2022 to mitigate the bill impact of the increase in formula rate plan revenues.

2023 Formula Rate Plan Filing

In March 2023, Entergy Mississippi submitted its formula rate plan 2023 test year filing and 2022 look-back filing showing Entergy Mississippi’s earned return on rate base for the historical 2022 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2023 calendar year to be below the formula rate plan bandwidth. The 2023 test year filing showed a $39.8 million rate increase was necessary to reset Entergy Mississippi’s earned return on rate base to the specified point of adjustment of 6.67%, within the formula rate plan bandwidth. The 2022 look-back filing compared actual 2022 results to the approved benchmark return on rate base and reflected the need for a $19.8 million temporary increase in formula rate plan revenues, including the refund of a $1.3 million over-recovery resulting from the demand-side management costs true-up for 2022. In fourth quarter 2022, Entergy Mississippi recorded a regulatory asset of $18.2 million in connection with the look-back feature of the formula rate plan to reflect that the 2022 estimated earned return was below the formula rate plan bandwidth. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $27.9 million interim rate increase, reflecting a cap equal to 2% of 2022 retail revenues, effective in April 2023.

In May 2023, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed a 2023 test year filing resulting in a total revenue increase of $26.5 million for 2023. Pursuant to the joint stipulation, Entergy Mississippi’s 2022 look-back filing reflected an earned return on rate base of 6.10% in calendar year 2022, which was below the look-back bandwidth, resulting in a $19.0 million increase in the formula rate plan revenues on an interim basis through June 2024. Entergy Mississippi recorded a regulatory credit of $0.8 million in June 2023 to reflect the increase in the look-back regulatory asset. In addition, certain long-term service agreement and conductor handling costs were authorized for realignment from the formula rate plan to the annual power management and grid modernization riders effective January 2023, resulting in regulatory credits recorded in June 2023 of $4.1 million and $4.3 million, respectively. Also, the amortization of Entergy Mississippi’s COVID-19 bad debt expense deferral was suspended for calendar year 2023, but resumed in July 2024. In June 2023 the MPSC approved the joint stipulation with rates effective in July 2023.

2024 Formula Rate Plan Filing

In March 2024, Entergy Mississippi submitted its formula rate plan 2024 test year filing and 2023 look-back filing showing Entergy Mississippi’s earned return on rate base for the historical 2023 calendar year to be within the formula rate plan bandwidth and projected earned return for the 2024 calendar year to be below the formula rate plan bandwidth. The 2024 test year filing showed a $63.4 million rate increase was necessary to reset Entergy Mississippi’s earned return on rate base to the specified point of adjustment of 7.10%, within the formula rate plan bandwidth. The 2023 look-back filing compared actual 2023 results to the approved benchmark return on rate base and reflected no change in formula rate plan revenues. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $32.6 million interim rate increase, reflecting a cap equal to 2% of 2023 retail revenues, effective April 2024.

In December 2014 the MPSC ordered Entergy Mississippi to file an updated depreciation study at least once every four years. Pursuant to this order and Entergy Mississippi’s filing cycle, Entergy Mississippi would have filed an updated depreciation report with its formula rate plan filing in 2023. However, in July 2022 the MPSC directed Entergy Mississippi to file its next depreciation study in connection with its 2024 formula rate plan filing notwithstanding the MPSC’s prior order. Accordingly, Entergy Mississippi filed a depreciation study in February 2024. The study showed a need for an increase in annual depreciation expense of $55.2 million. The calculated increase in annual depreciation expense was excluded from Entergy Mississippi’s 2024 formula rate plan revenue increase request because the MPSC had not yet approved the proposed depreciation rates.
In June 2024, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed the 2024 test year filing, with the exception of immaterial adjustments to certain operation and maintenance expenses. After performance adjustments, the formula rate plan reflected an earned return on rate base of 6.08% for calendar year 2024, which resulted in a total revenue increase of $64.6 million for 2024. The joint stipulation also recommended approval of a revised customer charge of $31.82 per month for residential customers and $53.10 per month for general service customers. Pursuant to the stipulation, Entergy Mississippi’s 2023 look-back filing reflected an earned return on rate base of 6.81%, resulting in an increase of $0.3 million in the formula rate plan revenues for 2023. Finally, the stipulation recommended approval of Entergy Mississippi’s proposed depreciation rates with those rates to be implemented upon request and approval at a later date. In June 2024 the MPSC approved the joint stipulation with rates effective in July 2024. The approval also included a reduction to the energy cost factor, resulting in a net bill decrease for a typical residential customer using 1,000 kWh per month. Also in June 2024, Entergy Mississippi recorded regulatory credits of $7.3 million to reflect the difference between interim rates placed in effect in April 2024 and the rates reflected in the joint stipulation.

In May 2024, Entergy Mississippi received approval from the MPSC for formula rate plan revisions that were necessary for Entergy Mississippi to comply with state legislation passed in January 2024. The legislation allows Entergy Mississippi to make interim rate adjustments 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 filed the first of its annual interim facilities rate adjustment reports in May 2024 to recover approximately $8.7 million of these costs over a six-month period with rates effective beginning in July 2024. Entergy Mississippi filed its second annual interim facilities rate adjustment report in December 2024 to recover approximately $46.7 million of these costs over a 12-month period with rates effective beginning in January 2025.

Grand Gulf Capacity Filing

In September 2024, Entergy Mississippi filed a notice of intent with the MPSC to implement revisions to its unit power cost recovery rider that would allow Entergy Mississippi to recover the first year of costs associated with the transfer of Entergy Louisiana’s entitlements to Grand Gulf capacity and energy, which consists of Energy Louisiana’s interest in and purchases of Grand Gulf capacity and energy under the revised rider schedule, effective by January 1, 2025. This notice filing related to the divestiture of Entergy Louisiana’s 14% share of Grand Gulf capacity and energy under the Unit Power Sales Agreement and 2.43% share of capacity and energy from Entergy Arkansas under the MSS-4 replacement tariff. This divestiture is being effectuated initially through Entergy Mississippi’s purchases from Entergy Louisiana pursuant to a PPA governed by the MSS-4 replacement tariff, a tariff governing the sales of energy and capacity among the Utility operating companies as described in the System Energy global settlement with the LPSC and Entergy Louisiana. The MSS-4 replacement PPA to effectuate this divestiture was approved by the FERC in November 2024. In February 2025 the MPSC approved Entergy Mississippi’s notice of intent, finding that it was just and reasonable for Entergy Mississippi to obtain Entergy Louisiana’s entitlements to Grand Gulf capacity and energy and that Entergy Mississippi should be allowed to recover the costs associated with the transfer of such entitlements to Grand Gulf capacity and energy, as described above. The MPSC approved the MSS-4 replacement PPA, effective as of January 1, 2025. See “Complaints Against System Energy – System Energy Settlement with the LPSC” below for further details of the System Energy global settlement with the LPSC and Note 8 to the financial statements for discussion of the Unit Power Sales Agreement.

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.

Filings with the City Council (Entergy New Orleans)

Retail Rates

2022 Formula Rate Plan Filing

In April 2022, Entergy New Orleans submitted to the City Council its formula rate plan 2021 test year filing. The 2021 test year evaluation report, subsequently updated in a July 2022 filing, produced an earned return on equity of 6.88% compared to the authorized return on equity of 9.35%. Entergy New Orleans sought approval of a $42.1 million rate increase based on the formula set by the City Council in the 2018 rate case. The formula resulted in an increase in authorized electric revenues of $34.1 million and an increase in authorized gas revenues of $3.3 million. Entergy New Orleans also sought to commence collecting $4.7 million in electric revenues that were previously approved by the City Council for collection through the formula rate plan. In July 2022 the City Council’s advisors issued a report seeking a reduction to Entergy New Orleans’s proposed increase of approximately $17.1 million in total for electric and gas revenues. Effective with the first billing cycle of September 2022, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council including adjustments filed in the City Council’s advisors’ report, per the approved process for formula rate plan implementation. The total formula rate plan increase implemented was $24.7 million, which includes an increase of $18.2 million in electric revenues, $4.7 million in previously approved electric revenues, and an increase of $1.8 million in gas revenues. Additionally, credits of $13.9 million funded by certain regulatory liabilities currently held by Entergy New Orleans for customers were issued over an eight-month period beginning September 2022.

2023 Formula Rate Plan Filing

In April 2023, Entergy New Orleans submitted to the City Council its formula rate plan 2022 test year filing. The 2022 test year evaluation report produced an electric earned return on equity of 7.34% and a gas earned return on equity of 3.52% compared to the authorized return on equity for each of 9.35%. Entergy New Orleans sought approval of a $25.6 million rate increase based on the formula set by the City Council in the 2018 rate case. The formula would result in an increase in authorized electric revenues of $17.4 million and an increase in authorized gas revenues of $8.2 million. Entergy New Orleans also sought to commence collecting $3.4 million in electric revenues that were previously approved by the City Council for collection through the formula rate plan. In July 2023, Entergy New Orleans filed a report to decrease its requested formula rate plan revenues by approximately $0.5 million to account for minor errors discovered after the filing. The City Council advisors issued a report seeking a reduction in the requested formula rate plan revenues of approximately $8.3 million, combined for electric and gas, due to alleged errors. The City Council advisors proposed additional rate mitigation in the amount of $12 million through offsets to the formula rate plan rate increase by certain regulatory liabilities. In September 2023 the City Council approved an agreement to settle the 2023 formula rate plan filing. Effective with the first billing cycle of September 2023, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council, per the approved process for formula rate plan implementation. The agreement provides for a total increase in electric revenues of $10.5 million and a total increase in gas revenues of
$6.9 million. The agreement also provides for a minor storm accrual of $0.5 million per year and the distribution of $8.9 million of currently held customer credits to implement the City Council advisors’ mitigation recommendations.

Request for Extension and Modification of Formula Rate Plan

In September 2023, Entergy New Orleans filed a motion seeking City Council approval of a three-year extension of Entergy New Orleans’s electric and gas formula rate plans. In October 2023 the City Council granted Entergy New Orleans’s request for an extension, subject to minor modifications which included a 55% equity ratio for rate setting purposes.

2024 Formula Rate Plan Filing

In April 2024, Entergy New Orleans submitted to the City Council its formula rate plan 2023 test year filing. Without the requested rate change in 2024, the 2023 test year evaluation report produced an electric earned return on equity of 8.66% and a gas earned return on equity of 5.87% compared to the authorized return on equity for each of 9.35%. Entergy New Orleans sought approval of a $12.6 million rate increase based on the formula set by the City Council in the 2018 rate case and approved again by the City Council in 2023. The formula would result in an increase in authorized electric revenues of $7.0 million and an increase in authorized gas revenues of $5.6 million. Following City Council review, the City Council’s advisors issued a report in July 2024 seeking a reduction in Entergy New Orleans’s requested formula rate plan revenues in an aggregate amount of approximately $1.6 million for electric and gas together due to alleged errors. Effective with the first billing cycle of September 2024, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council, per the approved process for formula rate plan implementation. The total formula rate plan increase implemented was $11.2 million, which includes an increase of $5.8 million in electric revenues and an increase of $5.4 million in gas revenues.

Filings with the PUCT and Texas Cities (Entergy Texas)

Retail Rates

2022 Base Rate Case

In July 2022, Entergy Texas filed a base rate case with the PUCT seeking a net increase in base rates of approximately $131.4 million. The base rate case was based on a 12-month test year ending December 31, 2021. Key drivers of the requested increase were changes in depreciation rates as the result of a depreciation study and an increase in the return on equity. In addition, Entergy Texas included capital additions placed into service for the period of January 1, 2018 through December 31, 2021, including those additions reflected in the then-effective distribution and transmission cost recovery factor riders and the generation cost recovery rider, all of which were reset to zero in June 2023 as a result of this proceeding. In July 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In October 2022 intervenors filed direct testimony challenging and supporting various aspects of Entergy Texas’s rate case application. The key issues addressed included the appropriate return on equity, generation plant deactivations, depreciation rates, and proposed tariffs related to electric vehicles. In November 2022 the PUCT staff filed direct testimony addressing a similar set of issues and recommending a reduction of $50.7 million to Entergy Texas’s overall cost of service associated with the requested net increase in base rates of approximately $131.4 million. Entergy Texas filed rebuttal testimony in November 2022.

In May 2023, Entergy Texas filed on behalf of the parties an unopposed settlement resolving all issues in the proceeding, except for issues related to electric vehicle charging infrastructure which were eventually severed to a separate proceeding and resolved in October 2024, and Entergy Texas filed an agreed motion for interim rates, subject to refund or surcharge to the extent that the interim rates differ from the final approved rates. The unopposed settlement reflected a net base rate increase to be effective and relate back to December 2022 of
$54 million, exclusive of, and incremental to, the costs being realigned from the distribution and transmission cost recovery factor riders and the generation cost recovery rider and $4.8 million of rate case expenses to be recovered through a rider over a period of 36 months. The net base rate increase of $54 million includes updated depreciation rates and a total annual revenue requirement of $14.5 million for the accrual of a self-insured storm reserve and the recovery of the regulatory assets for the pension and postretirement benefits expense deferral, costs associated with the COVID-19 pandemic, and retired non-advanced metering system electric meters. In May 2023 the ALJ with the State Office of Administrative Hearings granted the motion for interim rates, which became effective in June 2023. Additionally, the ALJ remanded the proceeding to the PUCT to consider the settlement. In August 2023 the PUCT issued an order approving the unopposed settlement. Concurrently, Entergy Texas recorded the reversal of $21.9 million of regulatory liabilities to reflect the recognition of certain receipts by Entergy Texas under affiliated PPAs that have been resolved.

Following the PUCT’s approval of the unopposed settlement in August 2023, Entergy Texas recorded a regulatory liability of $10.3 million, which reflected the net effects of higher depreciation and amortizations for the relate back period, partially offset by the relate back of base rate revenues that would have been collected had the approved rates been in effect for the period from December 2022 through June 2023, the date the new base rates were implemented on an interim basis. In October 2023, Entergy Texas filed a relate back surcharge rider to collect over six months beginning in January 2024 an additional approximately $24.6 million, which was the revenue requirement associated with the relate back of rates from December 2022 through June 2023, including carrying costs, as authorized by the PUCT’s August 2023 order. In November 2023, Entergy Texas filed an amended relate back surcharge rider to collect approximately $24.1 million based on a revised carrying cost rate. The amended relate back surcharge rider was approved by the PUCT in December 2023. The higher depreciation and amortizations for the relate back period were also recognized over the six months beginning in January 2024, resulting in no effect on net income from the collection of the relate back surcharge rider.

Distribution Cost Recovery Factor (DCRF) Rider

In June 2024, Entergy Texas filed with the PUCT a request to set a new DCRF rider. The new rider was designed to collect from Entergy Texas’s retail customers approximately $40.3 million annually based on its capital invested in distribution between January 1, 2022 and March 31, 2024. In September 2024 the PUCT approved the DCRF rider, consistent with Entergy Texas’s as-filed request, and rates became effective with the first billing cycle in October 2024.

In September 2024, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $48.9 million annually, or $8.6 million in incremental annual revenues beyond Entergy Texas’s then-effective DCRF rider based on its capital invested in distribution between April 1, 2024 and June 30, 2024. In December 2024, Entergy Texas filed an errata to revise its DCRF application for minor corrections, which decreased the requested annual revenue requirement to $48.5 million. The amended request represented an incremental increase of $8.2 million in annual revenues beyond Entergy Texas’s then-effective DCRF rider. Also in December 2024 the PUCT approved the DCRF rider, consistent with Entergy Texas’s filed errata, and rates became effective on December 20, 2024.

Transmission Cost Recovery Factor (TCRF) Rider

In December 2018, Entergy Texas filed with the PUCT a request to set a new TCRF rider. The new TCRF rider was designed to collect approximately $2.7 million annually from Entergy Texas’s retail customers based on its capital invested in transmission between January 1, 2018 and September 30, 2018. In April 2019 parties filed testimony proposing a load growth adjustment, which would fully offset Entergy Texas’s proposed TCRF revenue requirement. In July 2019 the PUCT granted Entergy Texas’s application as filed to begin recovery of the requested $2.7 million annual revenue requirement, rejecting opposing parties’ proposed adjustment; however, the PUCT found that the question of prudence of the actual investment costs should be determined in Entergy Texas’s next rate case similar to the procedure used for the costs recovered through the DCRF rider. In October 2019 the PUCT
issued an order on a motion for rehearing, clarifying and affirming its prior order granting Entergy Texas’s application as filed. Also in October 2019 a second motion for rehearing was filed, and Entergy Texas filed a response in opposition to the motion. The second motion for rehearing was overruled by operation of law. In December 2019, Texas Industrial Energy Consumers filed an appeal to the PUCT order in district court alleging that the PUCT erred in declining to apply a load growth adjustment.

In October 2021, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $66.1 million annually, or $15.1 million in incremental annual revenues beyond Entergy Texas’s then-effective TCRF rider based on its capital invested in transmission between September 1, 2020 and July 31, 2021 and changes in approved transmission charges. In January 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In February 2022 the parties filed an unopposed settlement recommending that Entergy Texas be allowed to collect its full requested TCRF revenue requirement with interim rates effective March 2022. In February 2022 the ALJ granted the motion for interim rates, admitted evidence, and remanded the case to the PUCT for consideration of a final order at a future open meeting. In June 2022 the PUCT issued an order approving the settlement.

In October 2024, Entergy Texas filed with the PUCT a request to amend its TCRF rider, which was previously reset to zero in June 2023 as a result of the 2022 base rate case. The proposed rider is designed to collect from Entergy Texas’s retail customers approximately $9.7 million annually based on its capital invested in transmission between January 1, 2022 and June 30, 2024 and changes in other transmission charges. In December 2024 the PUCT staff filed a recommendation that the PUCT approve Entergy Texas’s as-filed application. In February 2025 the PUCT staff issued a proposed order that, if approved by the PUCT, would approve Entergy Texas’s TCRF rider as filed.

Generation Cost Recovery Rider

In October 2020, Entergy Texas filed an application to establish a generation cost recovery rider to begin recovering a return of and on its generation capital investment in the Montgomery County Power Station. Entergy Texas filed an unopposed settlement agreement in December 2020, and the PUCT approved the generation cost recovery rider settlement rates on an interim basis in January 2021. In March 2021, Entergy Texas filed to update its generation cost recovery rider, and an unopposed settlement agreement filed by Entergy Texas on behalf of the parties in October 2021 was approved by the PUCT in January 2022. In February 2022, Entergy Texas filed a relate-back rider to collect over five months an additional approximately $5 million, which was the difference between the interim revenue requirement approved in January 2021 and the revenue requirement approved in January 2022 reflecting Entergy Texas’s full generation capital investment and ownership in Montgomery County Power Station on January 1, 2021, plus carrying costs from January 2021 through January 2022 when the updated revenue requirement took effect. The PUCT approved the relate-back rider consistent with Entergy Texas’s as-filed request, and rates became effective over a five-month period, in August 2022.

In December 2020, Entergy Texas also filed an application to amend its generation cost recovery rider to reflect its acquisition of the Hardin County Peaking Facility, which closed in June 2021. Because Hardin was to be acquired in the future, the initial generation cost recovery rider rates proposed in the application represented no change from the generation cost recovery rider rates established in Entergy Texas’s previous generation cost recovery rider proceeding. In July 2021 the PUCT issued an order approving the application. In August 2021, Entergy Texas filed an update application to recover its actual investment in the acquisition of the Hardin County Peaking Facility, and in January 2022, Entergy Texas filed an update to its application to align the requested revenue requirement with the terms of the generation cost recovery rider settlement approved by the PUCT in January 2022. In April 2022, Entergy Texas filed on behalf of the parties a unanimous settlement agreement that would adjust its generation cost recovery rider to recover an annual revenue requirement of approximately $92.8 million, which was $4.5 million in incremental annual revenue above the revenue requirement approved in January 2022 described above and related to Entergy Texas’s investment in the Montgomery County Power Station. The PUCT approved the settlement agreement and rates became effective in August 2022. In September 2022,
Entergy Texas filed a relate-back rider designed to collect over three months an additional approximately $5.7 million, which is the revenue requirement, plus carrying costs, associated with Entergy Texas’s acquisition of Hardin County Peaking Facility from June 2021 through August 2022 when the updated revenue requirement took effect. In April 2023 the PUCT approved Entergy Texas’s as-filed request with rates effective over three months beginning in May 2023.
Entergy Arkansas Opportunity Sales Proceeding

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

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

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

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

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

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

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

In October 2018 the FERC issued an order addressing the ALJ’s July 2017 initial decision. The FERC reversed the ALJ’s decision to cap the reduction in Entergy Arkansas’s payment to account for the increased bandwidth payments that Entergy Arkansas made to the other operating companies. The FERC also reversed the ALJ’s decision that Grand Gulf sales from January through September 2000 should be included in the calculation of Entergy Arkansas’s payment. The FERC affirmed on other grounds the ALJ’s rejection of the LPSC’s claim that certain joint account sales should be accounted for as part of the calculation of Entergy Arkansas’s payment. In November 2018 the LPSC requested rehearing of the FERC’s October 2018 decision. In December 2019 the FERC denied the LPSC’s request for rehearing. In January 2020 the LPSC appealed the December 2019 decision to the D.C. Circuit.
In December 2018, Entergy made a compliance filing in response to the FERC’s October 2018 order. The compliance filing provided a final calculation of Entergy Arkansas’s payments to the other Utility operating companies, including interest. No protests were filed in response to the December 2018 compliance filing. Refunds and interest in the following amounts were paid by Entergy Arkansas to the other operating companies in December 2018:
 Total refunds including interest
Payment/(Receipt)
 (In Millions)
PrincipalInterestTotal
Entergy Arkansas$68$67$135
Entergy Louisiana($30)($29)($59)
Entergy Mississippi($18)($18)($36)
Entergy New Orleans($3)($4)($7)
Entergy Texas($17)($16)($33)

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

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

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

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

In July 2020 the APSC issued a decision finding that Entergy Arkansas’s application is not in the public interest. The order also directed Entergy Arkansas to refund to its retail customers within 30 days of the order the FERC-determined over-collection of $13.7 million, plus interest, associated with a recalculated bandwidth remedy. In addition to these primary findings, the order also denied the Attorney General’s request for Entergy Arkansas to prepare a compliance filing detailing all of the retail impacts from the opportunity sales and denied a request by the Arkansas Electric Energy Consumers to recalculate all costs using the revised responsibility ratio. Entergy Arkansas filed a motion for temporary stay of the 30-day requirement to allow Entergy Arkansas a reasonable opportunity to seek rehearing of the APSC order, but in July 2020 the APSC denied Entergy Arkansas’s request for a stay and directed Entergy Arkansas to refund to its retail customers the component of the total FERC-determined opportunity sales payment that was associated with increased bandwidth remedy payments of $13.7 million, plus interest. The refunds were issued in the August 2020 billing cycle. While the APSC denied Entergy Arkansas’s stay request, Entergy Arkansas believes its actions were prudent and, therefore, the costs, including the $13.7 million, plus interest, are recoverable. In July 2020, Entergy Arkansas requested rehearing of the APSC order, which rehearing was denied by the APSC in August 2020. In September 2020, Entergy Arkansas filed a complaint in the U.S. District Court for the Eastern District of Arkansas challenging the APSC’s order denying Entergy Arkansas’s request to recover the costs of these payments. In October 2020 the APSC filed a motion to dismiss Entergy Arkansas’s complaint, to which Entergy Arkansas responded. Also in December 2020, Entergy Arkansas and the APSC held a pre-trial conference, and filed a report with the court in January 2021. The court held a hearing in February 2021 regarding issues addressed in the pre-trial conference report, and in June 2021 the court stayed all discovery until it rules on pending motions, after which the court will issue an amended schedule if necessary. In March 2022 the court denied the APSC’s motion to dismiss, and, in April 2022, issued a scheduling order including a trial date in February 2023. In June 2022, Entergy Arkansas filed a motion asserting that it is entitled to summary judgment because Entergy Arkansas’s position that the APSC’s order is pre-empted by the filed rate doctrine and violates the Dormant Commerce Clause is premised on facts that are not subject to genuine dispute. In July 2022, Arkansas Electric Energy Consumers, Inc., an industrial customer association, filed a motion to intervene and to hold Entergy Arkansas’s motion for summary judgment in abeyance pending a ruling on the motion to intervene. Entergy Arkansas filed a consolidated opposition to both motions. In August 2022 the APSC filed a motion for summary judgment arguing that there is no genuine issue as to any material fact and the APSC is entitled to judgment as a matter of law. In September 2022, Entergy Arkansas filed an opposition to the motion. In October 2022 the APSC filed a motion asking the court to hold further proceedings in abeyance pending a decision on the motions for summary judgment filed by Entergy Arkansas and the APSC. Also in October 2022, Entergy Arkansas filed an opposition to the motion, and the APSC filed a reply in support of its motion for summary judgment. In January 2023 the judge assigned to the case, on her own motion, identified facts that may present a conflict and recused herself; a new judge was assigned to the case, but he also recused due to a conflict. The case again was reassigned to a new judge. In January 2023 the court denied all pending motions (including those described above) except for a motion by the APSC to exclude certain testimony and further ruled that the matter would proceed to trial. In January 2023, Arkansas Electric Energy Consumers, Inc. filed a notice of appeal of the court’s order denying its motion to intervene to the United States Court of Appeals for the Eighth Circuit and a motion with the district court to stay the proceedings pending the appeal, which was denied. In February 2023, Arkansas Electric Energy Consumers, Inc. filed a motion with the United States Court of Appeals for the Eighth Circuit to stay the proceedings pending the appeal, which also was denied. The trial was held in February 2023. Following the trial, Entergy Arkansas filed a motion with the United States Court of Appeals for the Eighth Circuit to expedite the appeal filed by Arkansas Electric Energy Consumers, Inc. The United States Court of Appeals for
the Eighth Circuit granted Entergy Arkansas’s request, and oral arguments were held in June 2023. In August 2023 the United States Court of Appeals for the Eighth Circuit affirmed the order of the court denying Arkansas Electric Energy Consumers, Inc.’s motion to intervene.

In March 2024 the U.S. District Court for the Eastern District of Arkansas issued a judgment in favor of the APSC and against Entergy Arkansas. In March 2024 Entergy Arkansas filed a notice of appeal and a motion to expedite oral arguments with the United States Court of Appeals for the Eighth Circuit and the court granted the motion to expedite. Briefing to the United States Court of Appeals for the Eighth Circuit concluded in July 2024 and oral arguments concluded in September 2024. As a result of the adverse decision by the U.S. District Court for the Eastern District of Arkansas, Entergy Arkansas concluded that it could no longer support the recognition of its $131.8 million regulatory asset reflecting the previously-expected recovery of a portion of the costs at issue in the opportunity sales proceeding and recorded a $131.8 million ($99.1 million net-of-tax) charge to earnings in first quarter 2024. In December 2024 the United States Court of Appeals for the Eighth Circuit affirmed the decision of the U.S. District Court for the Eastern District of Arkansas, and Entergy Arkansas filed a petition for rehearing en banc. In January 2025 the United States Court of Appeals for the Eighth Circuit denied Entergy Arkansas’s petition. Entergy Arkansas is evaluating a petition for certiorari with the United States Supreme Court.
MSS-4 Replacement Tariff – Net Operating Loss Carryforward Proceeding

In January 2021, pursuant to section 205 of the Federal Power Act, Entergy Services filed an amendment to the MSS-4 replacement tariff, a tariff governing the sales of energy and capacity among the Utility operating companies, in order to provide for the inclusion of specified accumulated deferred income taxes, including net operating loss carryforward accumulated deferred income taxes (NOLC ADIT), in the rate for sales of energy among the Utility operating companies on a prospective basis. In March 2021, the FERC accepted the filing, subject to refund and hearing procedures.

In October 2021 the LPSC filed a complaint with the FERC alleging that Entergy Services improperly excluded NOLC ADIT from MSS-4 replacement tariff rates in the period before March 20, 2021. The LPSC argued that sales from Entergy Louisiana to Entergy Texas and Entergy New Orleans were charged at rates lower than they otherwise should have been, and it accordingly seeks surcharges for the period prior to March 20, 2021. The FERC set the complaint for hearing procedures and subsequently the hearing for this complaint proceeding was consolidated with the hearing procedures for Entergy Services’ January 2021 NOLC ADIT filing.

Testimony was filed by parties in 2023, and the hearing before a FERC ALJ was concluded in February 2024. In June 2024, the FERC ALJ issued an initial decision addressing three major issues: (1) whether Entergy Services’ proposed prospective inclusion and allocation of NOLC ADIT in MSS-4 replacement tariff rates using a modified with-and-without methodology is just and reasonable; (2) whether Entergy Services correctly calculated excess and deficient accumulated deferred income taxes in accordance with the terms of a prior settlement; and (3) whether NOLC ADIT should have been included in MSS-4 replacement tariff rates prior to the effective date of the January 2021 MSS-4 replacement tariff filing.

With respect to issues (1) and (2), the presiding ALJ concluded that Entergy Services’ proposed methodology for allocating and including NOLC ADIT in MSS-4 replacement tariff rates was just and reasonable and that Entergy Services correctly performed the excess and deficient accumulated deferred income taxes calculations. With respect to issue (3), however, the presiding ALJ agreed with the LPSC that NOLC ADIT should have been included in MSS-4 replacement tariff rates since September 1, 2016, and as a result, the presiding ALJ ordered that Entergy Louisiana and Entergy Arkansas recalculate bills for the period of September 1, 2016 through November 11, 2023 with surcharges expected to be due to those operating companies from the purchasing operating companies, Entergy New Orleans, Entergy Texas, and Entergy Louisiana (for some Entergy Arkansas sales). The presiding ALJ also ordered Entergy Services to pay the interest owed to Entergy Louisiana on these surcharges.
The surcharge methodology that the presiding ALJ recommended in connection with issue (3) was not supported by any participant in the hearing. As part of their exceptions to the initial decision, all parties to the proceeding opposed the use of the ALJ’s methodology, except for the FERC trial staff, which took no position. During the hearing, the LPSC and the FERC trial staff advocated that the alleged tariff violation should be remedied by the application of Entergy Services’ January 2021 proposed methodology. All other parties, including the PUCT, the City Council, and Entergy Services, opposed any surcharges for the period prior to the March 20, 2021 effective date of the January 2021 filing.

Entergy Services disputes the presiding ALJ's rulings on issue (3) and filed exceptions to these rulings in July 2024. The ALJ's initial decision is not binding on the FERC and is an interim step in the hearing process. No refunds will be owed in connection with this proceeding unless and until the FERC requires them in a final order.
Complaints Against System Energy

System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf.  System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. System Energy and the Unit Power Sales Agreement have been the subject of several litigation proceedings at the FERC, including challenges with respect to System Energy’s authorized return on equity and capital structure, renewal of its sale-leaseback arrangement, treatment of uncertain tax positions, a broader investigation of rates under the Unit Power Sales Agreement, and two prudence complaints, one challenging the extended power uprate completed at Grand Gulf in 2012 and the operation and management of Grand Gulf, particularly in the 2016-2020 time period, and the second challenging the operation and management of Grand Gulf in the 2021-2022 time period. Settlements that resolve all significant aspects of these complaints have been reached with the MPSC, the APSC, the City Council, and the LPSC, and these settlements have been approved by the FERC. Following are discussions of the proceedings.

Return on Equity and Capital Structure Complaints

In January 2017 the APSC and the MPSC filed a complaint with the FERC against System Energy. The complaint sought a reduction in the return on equity component of the Unit Power Sales Agreement pursuant to which System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. Entergy Arkansas also sells some of its Grand Gulf capacity and energy to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under separate agreements. The return on equity under the Unit Power Sales Agreement at the time of the complaint was 10.94%, which was established in a rate proceeding that became final in July 2001.

The APSC and the MPSC complaint alleged that the return on equity was unjust and unreasonable because capital market and other considerations indicated that it was excessive. The complaint requested proceedings to investigate the return on equity and establish a lower return on equity, and also requested that the FERC establish January 23, 2017 as a refund effective date. The complaint included a return on equity analysis that purported to establish that the range of reasonable return on equity for System Energy was between 8.37% and 8.67%. System Energy answered the complaint in February 2017 and disputed that a return on equity of 8.37% to 8.67% was just and reasonable. The LPSC and the City Council intervened in the proceeding expressing support for the complaint. In September 2017 the FERC established a refund effective date of January 23, 2017 and directed the parties to engage in settlement proceedings before an ALJ. The parties were unable to settle the return on equity issue and a FERC hearing judge was assigned in July 2018. The 15-month refund period in connection with the APSC/MPSC complaint expired on April 23, 2018.

In April 2018 the LPSC filed a complaint with the FERC against System Energy seeking an additional 15-month refund period.  The LPSC complaint requested similar relief from the FERC with respect to System Energy’s
return on equity and also requested the FERC to investigate System Energy’s capital structure.  The APSC, the MPSC, and the City Council intervened in the proceeding, filed an answer expressing support for the complaint, and asked the FERC to consolidate this proceeding with the proceeding initiated by the complaint of the APSC and the MPSC in January 2017. System Energy answered the LPSC complaint in May 2018 and also filed a motion to dismiss the complaint. In August 2018 the FERC issued an order dismissing the LPSC’s request to investigate System Energy’s capital structure and setting for hearing the return on equity complaint, with a refund effective date of April 27, 2018. The 15-month refund period in connection with the LPSC return on equity complaint expired on July 26, 2019.

The portion of the LPSC’s complaint dealing with return on equity was subsequently consolidated with the APSC and the MPSC complaint for hearing. The parties also addressed an order (issued in a separate FERC proceeding involving New England transmission owners) that proposed modifying the FERC’s standard methodology for determining return on equity. In September 2018 the LPSC filed an amended complaint raising the same capital structure claim the FERC had earlier dismissed. The FERC initiated a new proceeding for the amended capital structure complaint, and System Energy answered the complaint in October 2018. In January 2019 the FERC set the amended complaint for settlement and hearing proceedings. Settlement proceedings in the capital structure proceeding commenced in February 2019, but were terminated in June 2019, and the amended capital structure complaint was consolidated with the ongoing return on equity proceeding. The 15-month refund period in connection with the capital structure complaint was from September 24, 2018 to December 23, 2019.

Several rounds of testimony were filed by the parties in these proceedings between January 2019 and August 2020. Some of these rounds of testimony were precipitated by developments in an unrelated proceeding in which the FERC issued orders addressing the methodology for determining the return on equity applicable to transmission owners in MISO (Opinion Nos. 569 and 569-A). The final positions of the parties, after the submission of all pre-filed testimony, were as follows. With regard to the return on equity complaints for the first refund period, based on their respective interpretations and applications of the Opinion No. 569-A methodology, the LPSC argued for an authorized return on equity for System Energy of 7.97%; the MPSC and the APSC argued for an authorized return on equity of 9.24%; and the FERC trial staff argued for an authorized return on equity of 9.49%. For the second refund period and on a prospective basis, based on their respective interpretations and applications of the Opinion No. 569-A methodology, the LPSC argued for an authorized return on equity for System Energy of 7.78%; the MPSC and the APSC argued that an authorized return on equity of 9.15% may be appropriate if the second complaint was not dismissed; and the FERC trial staff argued for an authorized return on equity of 9.09% if the second complaint was not dismissed. The LPSC also continued to support as its primary recommendation, based on an alternative analysis to the Opinion No. 569-A methodology, an authorized return on equity for System Energy as low as 7.56% for the first complaint refund period and as low as 7.18% for the second complaint refund period and prospectively. The MPSC and the APSC also continued to support as their primary recommendation, based on an alternative analysis to the Opinion No. 569-A methodology, an authorized return on equity for System Energy as low as 8.26% for the first complaint refund period and as low as 8.32% for the second complaint refund period and prospectively. System Energy argued that strict application of the Opinion No. 569-A methodology produces results inconsistent with investor requirements and does not provide a sound basis on which to evaluate System Energy’s authorized return on equity. Therefore, as its primary recommendation, System Energy argued for the use of a methodology that incorporates four separate financial models and, based on application of this recommended methodology, an authorized return on equity of 10.12% for the first refund period, which also fell within the presumptively just and reasonable range calculated for the second refund period and prospectively. Under the Opinion No. 569-A methodology, System Energy calculated an authorized return on equity of 9.44% for the first refund period, which also fell within the presumptively just and reasonable range calculated for the second refund period and prospectively.

With regard to the capital structure, the LPSC’s primary recommendation was that the FERC establish a hypothetical capital structure for System Energy for ratemaking purposes, according to which System Energy’s common equity ratio would be set to Entergy Corporation’s equity ratio of 37% equity and 63% debt. The APSC and the MPSC recommended that 35.98% be set as the common equity ratio for System Energy. The FERC trial
staff argued that the average capital structure of the proxy group used to develop System Energy’s return on equity should be used to establish the capital structure. Using this approach, the FERC trial staff calculated the average capital structure for its proposed proxy group of 46.74% common equity and 53.26% debt. System Energy disputed all of these recommendations and argued that the use of its actual capital structure was just and reasonable.

After conducting a hearing, in March 2021 the FERC ALJ issued an initial decision. With regard to System Energy’s authorized return on equity, the ALJ determined that the existing return on equity of 10.94% was no longer just and reasonable, and that the replacement authorized return on equity, based on application of the Opinion No. 569-A methodology, should be 9.32%. The ALJ further determined that System Energy should pay refunds for a fifteen-month refund period (January 2017-April 2018) based on the difference between the current return on equity and the replacement authorized return on equity. The ALJ determined that the April 2018 complaint concerning the authorized return on equity should be dismissed, and that no refunds for a second fifteen-month refund period should be due. With regard to System Energy’s capital structure, the ALJ determined that System Energy’s actual equity ratio was excessive and that the just and reasonable equity ratio was 48.15% equity, based on the average equity ratio of the proxy group used to evaluate the return on equity for the second complaint. The ALJ further determined that System Energy should pay refunds for a fifteen-month refund period (September 2018-December 2019) based on the difference between the actual equity ratio and the 48.15% equity ratio.

In April 2021, System Energy filed its brief on exceptions, in which it challenged the initial decision’s findings on both the return on equity and capital structure issues. Also in April 2021 the LPSC, the APSC, the MPSC, the City Council, and the FERC trial staff filed briefs on exceptions. Reply briefs opposing exceptions were filed in May 2021 by System Energy, the FERC trial staff, the LPSC, the APSC, the MPSC, and the City Council.

As discussed below in “System Energy Settlement with the MPSC,” “System Energy Settlement with the APSC,” “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the MPSC, the APSC, the City Council, and the LPSC have settled their claims related to these proceedings. As part of the settlements with their respective retail regulators, effective July 2022 for Entergy Mississippi, November 2023 for Entergy Arkansas, June 2024 for Entergy New Orleans, and September 2024 for Entergy Louisiana, bills issued under the Unit Power Sales Agreement reflect a return on equity of 9.65% and a capital structure not to exceed 52% equity.

In August 2022 the D.C. Circuit issued an order addressing appeals of FERC’s Opinion No. 569 and 569-A, which established the methodology applied in the ALJ’s initial decision in the proceeding against System Energy discussed above. The appellate order addressed the methodology for determining the return on equity applicable to transmission owners in MISO. The D.C. Circuit found the FERC’s use of the Risk Premium model as part of the methodology to be arbitrary and capricious, and remanded the case back to the FERC. In October 2024, after System Energy had reached settlements with each of the retail regulators involved in the return on equity and capital structure proceeding discussed above, the FERC issued a remand order in the MISO transmission owners’ return on equity case, concluding that the record supported the methodology that it originally directed in Opinion No. 569 utilizing an equal weighting of the two-step discounted cash flow model and capital asset pricing model. As a result, it determined that the just and reasonable return on equity for the MISO transmission owners is 9.98%. In light of the System Energy settlements detailed below, the FERC’s changes to its return on equity methodology in the decision on the MISO transmission owners’ return on equity will not have any immediate effect on System Energy’s return on equity because System Energy’s return on equity has been set at 9.65% through the global settlement through the end of June 2026.

Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue

In May 2018 the LPSC filed a complaint against System Energy and Entergy Services related to System Energy’s renewal of a sale-leaseback transaction originally entered into in December 1988 for an 11.5% undivided interest in Grand Gulf Unit 1. The complaint alleged that System Energy violated the filed rate and the FERC’s ratemaking and accounting requirements when it included in Unit Power Sales Agreement billings the cost of
capital additions associated with the sale-leaseback interest, and that System Energy was double-recovering costs by including both the lease payments and the capital additions in Unit Power Sales Agreement billings. The complaint also claimed that System Energy was imprudent in entering into the sale-leaseback renewal because the Utility operating companies that purchase Grand Gulf’s output from System Energy could have obtained cheaper capacity and energy in the MISO markets. The complaint further alleged that System Energy violated various other reporting and accounting requirements and should have sought prior FERC approval of the lease renewal. The complaint sought various forms of relief from the FERC, including refunds for capital addition costs for all years in which they were recorded in allegedly non-formula accounts or, alternatively, the disallowance of the return on equity for the capital additions in those years plus interest; a disallowance and refund of the lease costs of the sale-leaseback renewal on grounds of imprudence; an investigation into System Energy’s treatment of a DOE litigation payment; and the imposition of certain forward-looking procedural protections, including audit rights for retail regulators of the Unit Power Sales Agreement formula rates. The APSC, the MPSC, and the City Council intervened in the proceeding.

In June 2018, System Energy and Entergy Services filed a motion to dismiss and an answer to the LPSC complaint denying that System Energy’s treatment of the sale-leaseback renewal and capital additions violated the terms of the filed rate or any other FERC ratemaking, accounting, or legal requirements or otherwise constituted double recovery. The response also argued that the complaint was inconsistent with a FERC-approved settlement to which the LPSC is a party and that explicitly authorized System Energy to recover its lease payments. Finally, the response argued that both the capital additions and the sale-leaseback renewal were prudent investments and the LPSC complaint failed to justify any disallowance or refunds. The response also offered to submit formula rate protocols for the Unit Power Sales Agreement similar to the procedures used for reviewing transmission rates under the MISO tariff. In September 2018 the FERC issued an order setting the complaint for hearing and settlement proceedings and establishing a refund effective date of May 18, 2018.

In February 2019 the presiding ALJ ruled that the hearing ordered by the FERC includes the issue of whether specific subcategories of accumulated deferred income tax should be included in, or excluded from, System Energy’s formula rate. Testimony was filed by the LPSC, the MPSC, the APSC, the City Council, the FERC trial staff, and System Energy between March 2019 and October 2019. The final positions of the parties, after all pre-filed testimony was submitted, were as follows. The LPSC sought refunds that included the renewal lease payments (approximately $17.2 million per year since July 2015), rate base reductions for accumulated deferred income tax associated with uncertain tax positions (with a corresponding refund of approximately $512 million), and the cost of capital additions associated with the sale-leaseback interest, as well as interest on those amounts. The LPSC also argued that adjustments to depreciation rates should require retroactive depreciation expense refunds but only prospective rate base adjustments. The APSC, the MPSC, and the City Council generally agreed with the LPSC’s positions. The FERC trial staff argued for refunds for rate base reductions for liabilities associated with uncertain tax positions, and also argued that System Energy recovered $32 million more than it should have in depreciation expense for capital additions. System Energy filed testimony asking the FERC to reject all of the LPSC’s claims for refunds and opposing the FERC trial staff’s position regarding the uncertain tax position issue. System Energy also argued that the FERC trial staff’s position regarding depreciation rates for capital additions was not unreasonable, but any change in depreciation expense is only one element of a Unit Power Sales Agreement re-billing calculation. Adjustments to depreciation expense in any re-billing under the Unit Power Sales Agreement formula rate would also involve changes to accumulated depreciation, accumulated deferred income taxes, and other formula elements as needed.

After holding a hearing in November 2019, in April 2020 the FERC ALJ issued the initial decision. Among other things, the ALJ determined that refunds were due on three main issues. First, with regard to the lease renewal payments, the ALJ determined that System Energy was recovering an unjust acquisition premium through the lease renewal payments, and that System Energy’s recovery from customers through rates should be limited to the cost of service based on the remaining net book value of the leased assets, which was approximately $70 million. The ALJ found that the remedy for this issue should be the refund of lease payments (approximately $17.2 million per year since July 2015) with interest determined at the FERC quarterly interest rate, which would be offset by the addition
of the net book value of the leased assets in the cost of service. The ALJ did not calculate a value for the refund expected as a result of this remedy. In addition, System Energy would no longer recover the lease payments in rates prospectively. Second, with regard to the liabilities associated with uncertain tax positions, the ALJ determined that the liabilities are accumulated deferred income taxes and that System Energy’s rate base should have been reduced for those liabilities. The ALJ also found that System Energy should include liabilities associated with uncertain tax positions as a rate base reduction going forward. Third, with regard to the depreciation expense adjustments, the ALJ found that System Energy should correct for the error in re-billings retroactively and prospectively, but that System Energy should not be permitted to recover interest on any retroactive return on enhanced rate base resulting from such corrections.

In June 2020, System Energy, the LPSC, and the FERC trial staff filed briefs on exceptions, challenging several of the initial decision’s findings. System Energy’s brief on exceptions challenged the initial decision’s limitations on recovery of the lease renewal payments, its proposed rate base refund for the liabilities associated with uncertain tax positions, and its proposal to asymmetrically treat interest on bill corrections for depreciation expense adjustments. The LPSC’s and the FERC trial staff’s briefs on exceptions each challenged the initial decision’s allowance for recovery of the cost of service associated with the lease renewal based on the remaining net book value of the leased assets, its calculation of the remaining net book value of the leased assets, and the amount of the initial decision’s proposed rate base refund for the liabilities associated with uncertain tax positions. The LPSC’s brief on exceptions also challenged the initial decision’s proposal that depreciation expense adjustments include retroactive adjustments to rate base and its finding that section 203 of the Federal Power Act did not apply to the lease renewal. The FERC trial staff’s brief on exceptions also challenged the initial decision’s finding that the FERC need not institute a formal investigation into System Energy’s tariff. In October 2020, System Energy, the LPSC, the MPSC, the APSC, and the City Council filed briefs opposing exceptions. System Energy opposed the exceptions filed by the LPSC and the FERC trial staff. The LPSC, the MPSC, the APSC, the City Council, and the FERC trial staff opposed the exceptions filed by System Energy. Also in October 2020 the MPSC, the APSC, and the City Council filed briefs adopting the exceptions of the LPSC and the FERC trial staff.

In addition, in September 2020, the IRS issued a Notice of Proposed Adjustment (NOPA) and Entergy executed it. The NOPA memorialized the IRS’s decision to adjust the 2015 consolidated federal income tax return of Entergy Corporation and certain of its subsidiaries, including System Energy, with regard to the uncertain decommissioning tax position. Pursuant to the audit resolution documented in the NOPA, the IRS allowed System Energy’s inclusion of $102 million of future nuclear decommissioning costs in System Energy’s cost of goods sold for the 2015 tax year, roughly 10% of the requested deduction, but disallowed the balance of the position. In September 2020, System Energy filed a motion to lodge the NOPA into the record in the FERC proceeding. In October 2020 the LPSC, the APSC, the MPSC, the City Council, and the FERC trial staff filed oppositions to System Energy’s motion. As a result of the NOPA issued by the IRS in September 2020, System Energy filed, in October 2020, a new Federal Power Act section 205 filing at FERC to establish an ongoing rate base credit for the accumulated deferred income taxes resulting from the decommissioning uncertain tax position. On a prospective basis beginning with the October 2020 bill, System Energy proposed to include the accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position as a credit to rate base under the Unit Power Sales Agreement. In November 2020 the LPSC, the APSC, the MPSC, and the City Council filed a protest to the filing, and System Energy responded.

In November 2020 the IRS issued a Revenue Agent’s Report (RAR) for the 2014/2015 tax year and in December 2020 Entergy executed it. The RAR contained the same adjustment to the uncertain nuclear decommissioning tax position as that which the IRS had announced in the NOPA. In December 2020, System Energy filed a motion to lodge the RAR into the record in the FERC proceeding addressing the uncertain tax position rate base issue. In January 2021 the LPSC, the APSC, the MPSC, and the City Council filed a protest to the motion.

As a result of the RAR, in December 2020, System Energy filed amendments to its new Federal Power Act section 205 filings to establish an ongoing rate base credit for the accumulated deferred income taxes resulting from
the decommissioning uncertain tax position and to credit excess accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position. The amendments both proposed the inclusion of the RAR as support for the filings. In December 2020 the LPSC, the APSC, and the City Council filed protests to the amendments. In February 2021 the FERC issued an order accepting System Energy’s Federal Power Act section 205 filings subject to refund, setting them for hearing, and holding the hearing in abeyance.

In December 2020, System Energy filed a new Federal Power Act section 205 filing to provide a one-time, historical credit of $25.2 million for the accumulated deferred income taxes that would have been created by the decommissioning uncertain tax position if the IRS’s decision had been known in 2016. In January 2021 the LPSC, APSC, MPSC, and City Council filed a protest to the filing. In February 2021 the FERC issued an order accepting System Energy’s Federal Power Act section 205 filing subject to refund, setting it for hearing, and holding the hearing in abeyance. System Energy provided the one-time credit during the first quarter 2021.

In December 2022 the FERC issued an order on the ALJ’s initial decision, which affirmed it in part and modified it in part. The FERC’s order directed System Energy to calculate refunds on three issues, and to provide a compliance report detailing the calculations. The FERC’s order also disallowed the future recovery of sale-leaseback renewal costs, which is estimated at approximately $11.5 million annually for purchases from Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans through July 2036. The three refund issues were rental expenses related to the renewal of the sale-leaseback arrangements; refunds, if any, for the revenue requirement impact of including accumulated deferred income taxes resulting from the decommissioning uncertain tax positions from 2004 through the present; and refunds for the net effect of correcting the depreciation inputs for capital additions attributable to the portion of plant subject to the sale-leaseback.

As a result of the FERC order’s directives regarding the recovery of the sale-leaseback transaction, in December 2022 System Energy reduced the Grand Gulf sale-leaseback regulatory liability by $56 million, reduced the related accumulated deferred income tax asset by $94 million, and reduced the Grand Gulf sale-leaseback accumulated deferred income tax regulatory liability by $25 million, resulting in an increase in income tax expense of $13 million. In addition, the FERC determined that System Energy recognized excess depreciation expense related to property subject to the sale-leaseback. As a result, in December 2022, System Energy recorded a reduction in depreciation expense and the related accumulated depreciation of $33 million.

In January 2023, System Energy filed its compliance report with the FERC. With respect to the sale-leaseback renewal costs, System Energy calculated a refund of $89.8 million, which represented all of the sale-leaseback renewal rental costs that System Energy recovered in rates, with interest. With respect to the decommissioning uncertain tax position issue, System Energy calculated that no additional refunds were owed because it had already provided a one-time historical credit (for the period January 2016 through September 2020) of $25.2 million based on the accumulated deferred income taxes that resulted from the IRS’s partial acceptance of the decommissioning tax position, and because it has been providing an ongoing rate base credit for the accumulated deferred income taxes that resulted from the IRS’s partial acceptance of the decommissioning tax position since October 2020. With respect to the depreciation refund, System Energy calculated a refund of $13.7 million, which is the net total of a refund to customers for excess depreciation expense previously collected, plus interest, offset by the additional return on rate base that System Energy previously did not collect, without interest. See “System Energy Settlement with the MPSC” below for discussion of the regulatory charge and corresponding regulatory liability recorded in June 2022 related to these proceedings. In January 2023, System Energy paid the refunds of $103.5 million, which included refunds of $41.7 million to Entergy Arkansas, $27.8 million to Entergy Louisiana, and $34 million to Entergy New Orleans.

In February 2023 the LPSC, the APSC, and the City Council filed protests to System Energy’s January 2023 compliance report, in which they challenged System Energy’s calculation of the refunds associated with the decommissioning tax position but did not protest the other components of the compliance report. Each of them argued that System Energy should have paid additional refunds for the decommissioning tax position issue, and the City Council estimated the total additional refunds owed to customers of Entergy Louisiana, Entergy New Orleans,
and Entergy Arkansas for that issue as $493 million, including interest (and without factoring in the $25.2 million refund that System Energy already paid in 2021).

In January 2023, System Energy filed a request for rehearing of the FERC’s determinations in the December 2022 order on sale-leaseback refund issues and future lease cost disallowances, the FERC’s prospective policy on uncertain tax positions, and the proper accounting of System Energy’s accumulated deferred income taxes adjustment for the Tax Cuts and Jobs Act of 2017; and a motion for confirmation of its interpretation of the December 2022 order’s remedy concerning the decommissioning tax position. In January 2023 the retail regulators filed a motion for confirmation of their interpretation of the refund requirement in the December 2022 FERC order and a provisional request for rehearing. In February 2023 the FERC issued a notice that the rehearing requests were denied by operation of law. In March 2023, System Energy filed in the United States Court of Appeals for the Fifth Circuit a petition for review of the December 2022 order. In March 2023, System Energy also filed an unopposed motion to stay the proceeding in the Fifth Circuit pending the FERC’s disposition of the pending motions, and the court granted the motion to stay.

In February 2023, System Energy submitted a tariff compliance filing with the FERC to clarify that, consistent with the releases provided in the MPSC settlement, Entergy Mississippi will continue to be charged for its allocation of the sale-leaseback renewal costs under the Unit Power Sales Agreement. See “System Energy Settlement with the MPSC” below for discussion of the settlement. In March 2023 the MPSC filed a protest to System Energy’s tariff compliance filing. The MPSC argues that the settlement did not specifically address post-settlement sale-leaseback renewal costs and that the sale-leaseback renewal costs may not be recovered under the Unit Power Sales Agreement. Entergy Mississippi’s allocated sale-leaseback renewal costs are estimated at $5.7 million annually for the remaining term of the sale-leaseback renewal.

In August 2023 the FERC issued an order addressing arguments raised on rehearing and partially setting aside the prior order (rehearing order). The rehearing order addressed rehearing requests that were filed in January 2023 separately by System Energy and the LPSC, the APSC, and the City Council.

In the rehearing order, the FERC directed System Energy to recalculate refunds for two issues: (1) refunds of rental expenses related to the renewal of the sale-leaseback arrangements and (2) refunds for the net effect of correcting the depreciation inputs for capital additions associated with the sale-leaseback. With regard to the sale-leaseback renewal rental expenses, the rehearing order allowed System Energy to recover an implied return of and on the depreciated cost of the portion of the plant subject to the sale-leaseback as of the expiration of the initial lease term. With regard to the depreciation input issue, the rehearing order allowed System Energy to offset refunds so that System Energy may collect interest on the rate base recalculations that were part of the overall depreciation rate recalculations. The rehearing order further directed System Energy to submit within 60 days of the date of the rehearing order an additional compliance filing to revise the total refunds for these two issues. As discussed above, System Energy’s January 2023 compliance filing calculated $103.5 million in total refunds, and the refunds were paid in January 2023. In October 2023, System Energy filed its compliance report with the FERC as directed in the August 2023 rehearing order. The October 2023 compliance report reflected recalculated refunds totaling $35.7 million for the two issues resulting in $67.8 million in refunds that could be recouped by System Energy. As discussed below in “System Energy Settlement with the APSC,” System Energy reached a settlement in principle with the APSC to resolve several pending cases under the FERC’s jurisdiction, including this one, pursuant to which it agreed not to recoup the $27.3 million calculated for Entergy Arkansas in the compliance filing. As a result of the FERC’s rulings on the sale-leaseback and depreciation input issues in the August 2023 rehearing order, in third quarter 2023, System Energy recorded a regulatory asset and corresponding regulatory credit of $40 million to reflect the portion of the January 2023 refunds to be recouped from Entergy Louisiana and Entergy New Orleans. Consistent with the compliance filing, in October 2023, Entergy Louisiana and Entergy New Orleans paid recoupment amounts of $18.2 million and $22.3 million, respectively, to System Energy.
On the third refund issue identified in the rehearing requests, concerning the decommissioning uncertain tax positions, the rehearing order denied all rehearing requests, re-affirmed the remedy contained in the December 2022 order, and did not direct System Energy to recalculate refunds or to submit an additional compliance filing.

In September 2023, System Energy filed a protective appeal of the rehearing order with the United States Court of Appeals for the Fifth Circuit. The appeal was consolidated with System Energy’s prior appeal of the December 2022 order.

In September 2023 the LPSC filed with the FERC a request for rehearing and clarification of the rehearing order. The LPSC requested that the FERC reverse its determination in the rehearing order that System Energy may collect an implied return of and on the depreciated cost of the portion of the plant subject to the sale-leaseback, as of the expiration of the initial lease term, as well as its determination in the rehearing order that System Energy may offset the refunds for the depreciation rate input issue and collect interest on the rate base recalculations that were part of the overall depreciation rate recalculations. In addition, the LPSC requested that the FERC either confirm the LPSC’s interpretation of the refund associated with the decommissioning uncertain tax positions or explain why it is not doing so. In October 2023 the FERC issued a notice that the rehearing request was deemed denied by operation of law. In November 2023 the FERC issued a further notice stating that it would not issue any further order addressing the rehearing request. Also in November 2023 the LPSC filed with the United States Court of Appeals for the Fifth Circuit a petition for review of the FERC’s August 2023 rehearing order and denials of the September 2023 rehearing request.

In December 2023 the United States Court of Appeals for the Fifth Circuit lifted the abeyance on the consolidated System Energy appeals and it also consolidated the LPSC’s appeal with the System Energy appeals. Briefing of the appeals occurred between March 2024 and July 2024. In September 2024 the parties filed a joint motion to continue and stay oral argument, previously scheduled for October 2024, pending the FERC’s decision whether to approve the settlement between System Energy and the LPSC, and the United States Court of Appeals for the Fifth Circuit granted the motion. In November 2024, after the FERC issued the order approving the settlement between System Energy and the LPSC, System Energy, the LPSC, the APSC, and the FERC filed a joint stipulation to dismiss the pending appeals, which the United States Court of Appeals for the Fifth Circuit granted.

As discussed below in “System Energy Settlement with the MPSC,” “System Energy Settlement with the APSC,” “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the MPSC, the APSC, the City Council, and the LPSC have settled their claims related to this proceeding.

LPSC Additional Complaints

In May 2020 the LPSC authorized its staff to file additional complaints at the FERC related to the rates charged by System Energy for Grand Gulf energy and capacity supplied to Entergy Louisiana under the Unit Power Sales Agreement. The LPSC directive noted that the initial decision issued by the presiding ALJ in the Grand Gulf sale-leaseback complaint proceeding did not address, for procedural reasons, certain rate issues raised by the LPSC and declined to order further investigation of rates charged by System Energy.

Unit Power Sales Agreement Complaint

The first of the additional complaints was filed by the LPSC, the APSC, the MPSC, and the City Council in September 2020. The first complaint raised two sets of rate allegations: violations of the filed rate and a corresponding request for refunds for prior periods; and elements of the Unit Power Sales Agreement are unjust and unreasonable and a corresponding request for refunds for the 15-month refund period and changes to the Unit Power Sales Agreement prospectively. Several of the filed rate allegations overlapped with the previous complaints. The filed rate allegations not previously raised were that System Energy: failed to provide a rate base credit to customers for the “time value” of sale-leaseback lease payments collected from customers in advance of the time those payments were due to the owner-lessors; improperly included certain sale-leaseback transaction costs in rate base as
prepayments; improperly included nuclear refueling outage costs in rate base; wrongly included categories of accumulated deferred income taxes as increases to rate base; charged customers based on a higher equity ratio than would be appropriate due to excessive retained earnings; and did not correctly reflect money pool investments and imprudently invested cash into the money pool. The elements of the Unit Power Sales Agreement that the complaint alleged were unjust and unreasonable include: the current cash working capital allowance of zero, uncapped recovery of incentive and executive compensation, lack of an equity re-opener, and recovery of lobbying and private airplane travel expenses. The complaint also requested a rate investigation into the Unit Power Sales Agreement and System Energy’s billing practices pursuant to section 206 of the Federal Power Act, including any issue relevant to the Unit Power Sales Agreement and its inputs. System Energy filed its answer opposing the complaint in November 2020. In its answer, System Energy argued that all of the claims raised in the complaint should be dismissed and agreed that bill adjustment with respect to two discrete issues were justified. System Energy argued that dismissal was warranted because all claims fell into one or more of the following categories: the claims had been raised and were being litigated in another proceeding; the claims did not present a prima facie case and did not satisfy the threshold burden to establish a complaint proceeding; the claims were premised on a theory or request relief that is incompatible with federal law or FERC policy; the claims request relief that is inconsistent with the filed rate; the claims were barred or waived by the legal doctrine of laches; and/or the claims had been fully addressed and do not warrant further litigation. In December 2020, System Energy filed a bill adjustment report indicating that $3.4 million had been credited to customers in connection with the two discrete issues concerning the inclusion of certain accumulated deferred income taxes balances in rates.

In May 2021 the FERC issued an order addressing the complaint, establishing a refund effective date of September 21, 2020, establishing hearing procedures, and holding those procedures in abeyance pending the FERC’s review of the initial decision in the Grand Gulf sale-leaseback renewal complaint discussed above. System Energy agreed that the hearing should be held in abeyance but sought rehearing of FERC’s decision as related to matters set for hearing that were beyond the scope of FERC’s jurisdiction or authority. The complainants sought rehearing of FERC’s decision to hold the hearing in abeyance and filed a motion to proceed, which motion System Energy opposed. In June 2021, System Energy’s request for rehearing was denied by operation of law, and System Energy filed an appeal of FERC’s orders in the Court of Appeals for the Fifth Circuit. In November 2021 the Fifth Circuit dismissed the appeal as premature.

In August 2021 the FERC issued an order addressing System Energy’s and the complainants’ rehearing requests. The FERC dismissed part of the complaint seeking an equity re-opener, maintained the abeyance for issues related to the proceeding addressing the sale-leaseback renewal and uncertain tax positions, lifted the abeyance for issues unrelated to that proceeding, and clarified the scope of the hearing.

In November 2021 the LPSC, the APSC, and the City Council filed direct testimony and requested the FERC to order refunds for prior periods and prospective amendments to the Unit Power Sales Agreement. The LPSC’s refund claims included, among other things, allegations that: (1) System Energy should not have included certain sale-leaseback transaction costs in prepayments; (2) System Energy should have credited rate base to reflect the time value of money associated with the advance collection of lease payments; (3) System Energy incorrectly included refueling outage costs that were recorded in account 174 in rate base; and (4) System Energy should have excluded several accumulated deferred income tax balances in account 190 from rate base. The LPSC also sought a retroactive adjustment to retained earnings and capital structure in conjunction with the implementation of its proposed refunds. In addition, the LPSC sought amendments to the Unit Power Sales Agreement going forward to address below-the-line costs, incentive compensation, the working capital allowance, litigation expenses, and the 2019 termination of the capital funds agreement. The APSC argued that: (1) System Energy should have included borrowings from the Entergy system money pool in its determination of short-term debt in its cost of capital; and (2) System Energy should credit customers with System Energy’s allocation of earnings on money pool investments. The City Council alleged that System Energy has maintained excess cash on hand in the money pool and that retention of excess cash was imprudent. Based on this allegation, the City Council’s witness recommended a refund of approximately $98.8 million for the period 2004-September 2021 or other alternative relief. The City Council
further recommended that the FERC impose a hypothetical equity ratio such as 48.15% equity to capital on a prospective basis.

In January 2022, System Energy filed answering testimony arguing that the FERC should not order refunds for prior periods or any prospective amendments to the Unit Power Sales Agreement. In response to the LPSC’s refund claims, System Energy argued, among other things, that: (1) the inclusion of sale-leaseback transaction costs in prepayments was correct; (2) that the filed rate doctrine bars the request for a retroactive credit to rate base for the time value of money associated with the advance collection of lease payments; (3) that an accounting misclassification for deferred refueling outage costs had been corrected, caused no harm to customers, and requires no refunds; and (4) that its accounting and ratemaking treatment of specified accumulated deferred income tax balances in account 190 had been correct. System Energy further responded that no retroactive adjustment to retained earnings or capital structure should be ordered because there was no general policy requiring such a remedy, and there was no showing that the retained earnings element of the capital structure was incorrectly implemented. Further, System Energy presented evidence that all of the costs that were being challenged were long known to the retail regulators and were approved by them for inclusion in retail rates, and the attempt to retroactively challenge these costs, some of which had been included in rates for decades, was unjust and unreasonable. In response to the LPSC’s proposed going-forward adjustments, System Energy presented evidence to show that none of the proposed adjustments were needed. On the issue of below-the-line expenses, during discovery procedures System Energy identified a historical allocation error in certain months and agreed to provide a bill credit to customers to correct the error. In response to the APSC’s claims, System Energy argued that the Unit Power Sales Agreement did not include System Energy’s borrowings from the Entergy system money pool or earnings on deposits to the Entergy system money pool in the determination of the cost of capital; and accordingly, no refunds were appropriate on those issues. In response to the City Council’s claims, System Energy argued that it has reasonably managed its cash and that the City Council’s theory of cash management was defective because it failed to adequately consider the relevant cash needs of System Energy and it made faulty presumptions about the operation of the Entergy system money pool. System Energy further pointed out that the issue of its capital structure was already subject to pending FERC litigation.

In March 2022 the FERC trial staff filed direct and answering testimony in response to the LPSC, the APSC, and the City Council’s direct testimony. In its testimony, the FERC trial staff recommended refunds for two primary reasons: (1) it concluded that System Energy should have excluded specified accumulated deferred income tax balances in account 190 associated with rate refunds; and (2) it concluded that System Energy should have excluded specified accumulated deferred income tax balances in account 190 associated with a deemed contract satisfaction and reissuance that occurred in 2005. The FERC trial staff recommended refunds of $84.1 million, exclusive of any tax gross-up or FERC interest. In addition, the FERC trial staff recommended the following prospective modifications to the Unit Power Sales Agreement: (1) inclusion of a rate base credit to recognize the time value of money associated with the advance collection of lease payments; (2) exclusion of executive incentive compensation costs for members of the Office of the Chief Executive and long-term performance unit costs where awards are based solely or primarily on financial metrics; and (3) exclusion of unvested, accrued amounts for stock options, performance units, and restricted stock awards. With respect to issues that ultimately concerned the reasonableness of System Energy’s rate of return, the FERC trial staff stated that it was unnecessary to consider such issues in the proceeding, in light of the pending case concerning System Energy’s return on equity and capital structure. On all other material issues raised by the LPSC, the APSC, and the City Council, the FERC trial staff recommended either no refunds or no modification to the Unit Power Sales Agreement.

In April 2022, System Energy filed cross-answering testimony in response to the FERC trial staff’s recommendations of refunds for the accumulated deferred income taxes issues and proposed modifications to the Unit Power Sales Agreement for the executive incentive compensation issues. In June 2022 the FERC trial staff submitted revised answering testimony, in which it recommended additional refunds associated with the accumulated deferred income tax balances in account 190 associated with a deemed contract satisfaction and reissuance that occurred in 2005. Based on the testimony revisions, the FERC trial staff’s recommended refunds total $106.6 million, exclusive of any tax gross-up or FERC awarded interest. Also in June 2022, System Energy
filed revised and supplemental cross-answering testimony to respond to the FERC trial staff’s testimony and oppose its revised recommendation.

In May 2022 the LPSC, the APSC, and the City Council filed rebuttal testimony. The LPSC’s testimony asserted new claims, including that: (1) certain of the sale-leaseback transaction costs may have been imprudently incurred; (2) accumulated deferred income taxes associated with sale-leaseback transaction costs should have been included in rate base; (3) accumulated deferred income taxes associated with federal investment tax credits should have been excluded from rate base; (4) monthly net operating loss accumulated deferred income taxes should have been excluded from rate base; and (5) several categories of proposed rate changes, including executive incentive compensation, air travel, industry dues, and legal costs, also warranted historical refunds. The LPSC’s rebuttal testimony argued that refunds for the alleged tariff violations and other claims must be calculated by rerunning the Unit Power Sales Agreement formula rate; however, it included estimates of refunds associated with some, but not all, of its claims, totaling $286 million without interest. The City Council’s rebuttal testimony also proposed a new, alternate theory and claim for relief regarding System Energy’s participation in the Entergy system money pool, under which it calculates estimated refunds of approximately $51.7 million. The APSC’s rebuttal testimony agreed with the LPSC’s direct testimony that retained earnings should be adjusted in a comprehensive refund calculation. The testimony quantified the estimated impacts of three issues: (1) a $1.5 million reduction in the revenue requirement under the Unit Power Sales Agreement if System Energy’s borrowings from the money pool were included in short-term debt; (2) a $1.9 million reduction in the revenue requirement if System Energy’s allocated share of money pool earnings were credited through the Unit Power Sales Agreement; and (3) a $1.9 million reduction in the revenue requirement for every $50 million of refunds ordered in a given year, without interest. In total, excluding the settled issues noted below, the claims sought more than $700 million in refunds and interest, based on charges to all Unit Power Sales Agreement purchasers including Entergy Mississippi. The hearing before a FERC ALJ occurred between September and December 2022.

In November 2022, System Energy filed a partial settlement agreement with the APSC, the City Council, and the LPSC that resolved the following issues raised in the Unit Power Sales Agreement complaint: advance collection of lease payments, aircraft costs, executive incentive compensation, money pool borrowings, advertising expenses, deferred nuclear refueling outage costs, industry association dues, and termination of the capital funds agreement. The settlement provided that System Energy would provide a black box refund of $18 million (inclusive of interest), plus additional refund amounts with interest to be calculated for certain issues to be distributed to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans as the Utility operating companies other than Entergy Mississippi purchasing under the Unit Power Sales Agreement. The settlement further provided that if the APSC, the City Council, or the LPSC agreed to the global settlement System Energy entered into with the MPSC (discussed below), and such global settlement included a black box refund amount, then the black box refund for this settlement agreement would not be incremental or in addition to the global black box refund amount. The settlement agreement addressed other matters as well, including adjustments to rate base beginning in October 2022, exclusion of certain other costs, and inclusion of money pool borrowings, if any, in short-term debt within the cost of capital calculation used in the Unit Power Sales Agreement. In April 2023 the FERC approved the settlement agreement. The refund provided for in the settlement agreement was included in the May 2023 service month bills under the Unit Power Sales Agreement.

In May 2023 the presiding ALJ issued an initial decision finding that System Energy should have excluded multiple identified categories of accumulated deferred income taxes from rate base when calculating Unit Power Sales Agreement bills. The initial decision also found that the Unit Power Sales Agreement should be modified such that a cash working capital allowance of negative $36.4 million is applied prospectively. On the other non-settled issues for which the complainants sought refunds or changes to the Unit Power Sales Agreement, the initial decision ruled against the complainants.

System Energy disagreed with the ALJ’s findings concerning the accumulated deferred income taxes issues and cash working capital. In July 2023, System Energy filed a brief on exceptions to the initial decision’s accumulated deferred income taxes findings. Also in July 2023, the APSC, the LPSC, the City Council, and the
FERC trial staff filed separate briefs on exceptions. In August 2023 all parties filed separate briefs opposing exceptions.

As discussed below in “System Energy Settlement with the MPSC,” “System Energy Settlement with the APSC,” and “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the MPSC, the APSC, and the City Council, and the LPSC have settled their claims related to this proceeding.

Grand Gulf Prudence Complaints

The second of the additional complaints was filed at the FERC in March 2021 by the LPSC, the APSC, and the City Council against System Energy, Entergy Services, Entergy Operations, and Entergy Corporation. The second complaint contained two primary allegations. First, it alleged that, based on the plant’s capacity factor and alleged safety performance, System Energy and the other respondents imprudently operated Grand Gulf during the period 2016-2020, and it sought refunds of at least $360 million in alleged replacement energy costs, in addition to other costs, including those that could only be identified upon further investigation. Second, it alleged that the performance and/or management of the 2012 extended power uprate of Grand Gulf was imprudent, and it sought refunds of all costs of the 2012 uprate that were determined to result from imprudent planning or management of the project. In addition to the requested refunds, the complaint asked that the FERC modify the Unit Power Sales Agreement to provide for full cost recovery only if certain performance indicators were met and to require pre-authorization of capital improvement projects in excess of $125 million before related costs could be passed through to customers in rates. In April 2021, System Energy and the other respondents filed their motion to dismiss and answer to the complaint. System Energy requested that the FERC dismiss the claims within the complaint. With respect to the claim concerning operations, System Energy argued that the complaint did not meet its legal burden because, among other reasons, it failed to allege any specific imprudent conduct. With respect to the claim concerning the uprate, System Energy argued that the complaint failed because, among other reasons, the complainants’ own conduct prevented them from raising a serious doubt as to the prudence of the uprate. System Energy also requested that the FERC dismiss other elements of the complaint, including the proposed modifications to the Unit Power Sales Agreement, because they were not warranted. In February 2023 the FERC issued an order denying rehearing and thereby affirming its order setting the complaint for settlement and hearing procedures. In July 2023 the FERC chief ALJ terminated settlement procedures and appointed a presiding ALJ to oversee hearing procedures. In September 2023 a procedural schedule for hearing procedures was established. Also in September 2023 the LPSC authorized its staff to file an additional complaint concerning the prudence of System Energy’s operation and management of Grand Gulf in the year 2022. In October 2023 the LPSC, the APSC, and the City Council filed what they styled as an amended and supplemental complaint with the FERC against System Energy, Entergy Services, and Entergy Operations. In November 2023, System Energy answered the amended and supplemental complaint. Pursuant to the procedural schedule, the complainants’ testimony in the original complaint proceeding was filed in December 2023. System Energy’s answering testimony was filed in May 2024, and the FERC trial staff’s direct and answering testimony was filed in June 2024.

As discussed below in “System Energy Settlement with the APSC,” “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the APSC, the City Council, and the LPSC have settled all of their claims related to this proceeding.

System Energy Settlement with the MPSC

In June 2022, System Energy, Entergy Mississippi, and additional named Entergy parties involved in thirteen docketed proceedings before the FERC filed with the FERC a partial settlement agreement and offer of settlement. The settlement memorialized the Entergy parties’ agreement with the MPSC to globally resolve all actual and potential claims between the Entergy parties and the MPSC associated with those FERC proceedings and with System Energy’s past implementation of the Unit Power Sales Agreement. The Unit Power Sales Agreement is a FERC-jurisdictional formula rate tariff for sales of energy and capacity from System Energy’s owned and
leased share of Grand Gulf to Entergy Mississippi, Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans. Entergy Mississippi purchases the greatest single amount, nearly 40% of System Energy’s share of Grand Gulf, after its additional purchases from affiliates are considered.

The settlement provided for a black box refund of $235 million from System Energy to Entergy Mississippi. In addition, beginning with the July 2022 service month, the settlement provided for Entergy Mississippi’s bills from System Energy to be adjusted to reflect: an authorized rate of return on equity of 9.65%, a capital structure not to exceed 52% equity, a rate base reduction for the advance collection of sale-leaseback rental costs, and the exclusion of certain long-term incentive plan performance unit costs from rates. The settlement was approved by the MPSC in June 2022 and the FERC in November 2022.

System Energy had previously recorded a provision and associated liability of $37 million for elements of the applicable litigation. In June 2022, System Energy recorded a regulatory charge of $551 million ($413 million net-of-tax), increasing the regulatory liability to $588 million, which consisted of $235 million for the settlement with the MPSC and $353 million for potential future refunds to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans. System Energy paid the black box refund of $235 million to Entergy Mississippi in November 2022.

System Energy Settlement with the APSC

In October 2023, System Energy, Entergy Arkansas, and additional named Entergy parties involved in multiple docketed proceedings pending before the FERC reached a settlement in principle with the APSC to globally resolve all of their actual and potential claims in those dockets and with System Energy’s past implementation of the Unit Power Sales Agreement. The settlement also covered the amended and supplemental complaint, discussed above in “Grand Gulf Prudence Complaint,” filed at the FERC in October 2023. System Energy, Entergy Arkansas, additional Entergy parties, and the APSC filed the settlement agreement and supporting materials with the FERC in November 2023.

The terms of the settlement with the APSC aligned with the $588 million global black box settlement reached between System Energy and the MPSC in June 2022 and provided for Entergy Arkansas to receive a black box refund of $142 million from System Energy, inclusive of $49.5 million already received by Entergy Arkansas from System Energy. In addition, beginning with the November 2023 service month, the settlement provided for Entergy Arkansas’s bills from System Energy to be adjusted to reflect an authorized rate of return on equity of 9.65% and a capital structure not to exceed 52% equity. In March 2024 the FERC approved the settlement, and System Energy paid the remaining black box refund of $93 million to Entergy Arkansas in 2024.

System Energy Settlement with the City Council

In April 2024, System Energy, Entergy New Orleans, and additional named Entergy parties involved in multiple docketed proceedings pending before the FERC reached a settlement in principle with the City Council to globally resolve all of their actual and potential claims in those dockets and with System Energy’s past implementation of the Unit Power Sales Agreement. The settlement also covered the amended and supplemental complaint, discussed in “Grand Gulf Prudence Complaints” above, filed by the LPSC, the APSC, and the City Council at the FERC in October 2023. In May 2024, System Energy, Entergy New Orleans, additional named Entergy parties, and the City Council filed the settlement agreement and supporting materials with the FERC.

The terms of the settlement with the City Council aligned with the $588 million global black box settlement amount reflected in the prior settlements reached between System Energy and the MPSC in June 2022 and between System Energy and the APSC in November 2023. The settlement provided for Entergy New Orleans to receive a black box refund of $116 million from System Energy, inclusive of approximately $18 million already received by Entergy New Orleans from System Energy. In addition, beginning with the June 2024 service month, the settlement provided for Entergy New Orleans’s bills from System Energy to be adjusted to reflect an authorized rate of return on equity of 9.65% and a capital structure not to exceed 52% equity. In August 2024 the FERC approved the
settlement, and System Energy paid the remaining black box refund of $98 million to Entergy New Orleans in October 2024.

System Energy Settlement with the LPSC

In July 2024, System Energy and the LPSC staff reached a settlement in principle to globally resolve all of the LPSC’s actual and potential claims in multiple docketed proceedings pending before the FERC (including all docketed proceedings resolved by the MPSC, the APSC, and the City Council settlements) and with System Energy’s past implementation of the Unit Power Sales Agreement. The settlement also covered the amended and supplemental complaint, discussed above in “Grand Gulf Prudence Complaints,” filed by the LPSC, the APSC, and the City Council at the FERC in October 2023. In August 2024 the LPSC approved the settlement. In September 2024 the settling parties filed the settlement for approval by the FERC.

The terms of the settlement with the LPSC staff aligned with the $588 million global black box settlement amount reflected in the prior settlements reached between System Energy and the MPSC in June 2022, between System Energy and the APSC in November 2023, and between System Energy and the City Council in April 2024. The settlement in principle provided for Entergy Louisiana to receive a black box refund of $95 million from System Energy, inclusive of approximately $15 million already received by Entergy Louisiana from System Energy. In addition, beginning with the September 2024 service month, the settlement provided for Entergy Louisiana’s bills from System Energy to be adjusted to reflect an authorized rate of return on equity of 9.65% and a capital structure not to exceed 52% equity. In November 2024 the FERC approved the settlement, and System Energy paid the remaining black box refund of $80 million to Entergy Louisiana in December 2024.

The settlement also included an agreement that, subject to the receipt of necessary regulatory approvals, Entergy Louisiana will divest to Entergy Mississippi all of its interest in Grand Gulf capacity and energy under the Unit Power Sales Agreement and its purchases from Entergy Arkansas under the MSS-4 replacement tariff. In October 2024 Entergy Louisiana and Entergy Mississippi filed with the FERC a PPA under which Entergy Mississippi would purchase Entergy Louisiana’s purchases of Grand Gulf capacity and energy. The PPA is governed by the MSS-4 replacement tariff, a tariff governing the sales of energy and capacity among the Utility operating companies. The requisite approvals for the PPA were issued by the FERC in November 2024 and the MPSC in February 2025. The divestiture is effective as of January 1, 2025.

System Energy Regulatory Liability for Pending Complaints

Prior to June 2022, System Energy recorded a provision and associated liability of $37 million for elements of the complaints against System Energy. In June 2022, as discussed in “System Energy Settlement with the MPSC” above, System Energy recorded a regulatory charge of $551 million ($413 million net-of-tax), increasing System Energy’s regulatory liability to $588 million, which consisted of $235 million for the settlement with the MPSC and $353 million for potential future refunds to Entergy Arkansas, Entergy New Orleans, and Entergy Louisiana. System Energy paid the black box refund of $235 million to Entergy Mississippi in November 2022. As discussed above in “Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue,” in January 2023 System Energy paid refunds of $103.5 million as a result of the FERC’s order in December 2022 in that proceeding and recouped $40.5 million of the $103.5 million from Entergy Louisiana and Entergy New Orleans in October 2023. In addition, as discussed above in “Unit Power Sales Agreement Complaint,” a black box refund of $18 million was made by System Energy in 2023 in connection with a partial settlement in that proceeding. Based on analysis of the then-pending complaints against System Energy and potential future settlement negotiations with the LPSC and the City Council, in third quarter 2023, System Energy recorded a regulatory charge of $40 million to increase System Energy’s regulatory liability related to complaints against System Energy. In December 2023 the $93 million black box refund to Entergy Arkansas was reclassified from the regulatory liability to accounts payable - associated companies on System Energy’s balance sheet. System Energy paid the remaining black box refunds of $93 million to Entergy Arkansas, $98 million to Entergy New Orleans, and $80 million to Entergy Louisiana in 2024.
Unit Power Sales Agreement

System Energy Formula Rate Annual Protocols Formal Challenge Concerning 2020 Calendar Year Bills

System Energy’s Unit Power Sales Agreement includes formula rate protocols that provide for the disclosure of cost inputs, an opportunity for informal discovery procedures, and a challenge process. In February 2022, pursuant to the protocols procedures, the LPSC, the APSC, the MPSC, the City Council, and the Mississippi Public Utilities Staff filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2020. This formal challenge was ultimately settled as a result of System Energy’s global settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” above for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.

System Energy Formula Rate Annual Protocols Formal Challenge Concerning 2021 Calendar Year Bills

In March 2023, pursuant to the protocols procedures discussed above, the LPSC, the APSC, and the City Council filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2021. This formal challenge was ultimately settled as a result of System Energy’s global settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” above for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.

System Energy Formula Rate Annual Protocols Formal Challenge Concerning 2022 Calendar Year Bills

In February 2024, pursuant to the protocols procedures, the LPSC and the City Council filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2022. This formal challenge was ultimately settled as a result of System Energy’s global settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” above for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.

Depreciation Amendment Proceeding

In December 2021, System Energy submitted to the FERC proposed amendments to the Unit Power Sales Agreement to adopt updated rates for use in calculating Grand Gulf plant depreciation and amortization expenses. The proposed amendments would result in higher charges to the Utility operating companies that buy capacity and energy from System Energy under the Unit Power Sales Agreement. In February 2022 the FERC accepted System Energy’s proposed increased depreciation rates with an effective date of March 1, 2022, subject to refund pending the outcome of the settlement and/or hearing procedures. In June 2023 System Energy filed with the FERC an unopposed offer of settlement that it had negotiated with intervenors to the proceeding. In August 2023 the FERC approved the settlement, which resolves the proceeding. In third quarter 2023, System Energy recorded a reduction in depreciation expense of $41 million representing the cumulative difference in depreciation expense resulting from the depreciation rates used from March 2022 through June 2023 and the depreciation rates included in the settlement filing approved by the FERC. In October 2023, System Energy filed a refund report with the FERC. The refund provided for in the refund report was included in the September 2023 service month bills under the Unit Power Sales Agreement. No comments or protests to the refund report were filed.

Pension Costs Amendment Proceeding

In October 2021, System Energy submitted to the FERC proposed amendments to the Unit Power Sales Agreement to include in rate base the prepaid and accrued pension costs associated with System Energy’s qualified pension plans. Based on data ending in 2020, the increased annual revenue requirement associated with the filing is approximately $8.9 million. In March 2022 the FERC accepted System Energy’s proposed amendments with an
effective date of December 1, 2021, subject to refund pending the outcome of the settlement and/or hearing procedures. In August 2023 the FERC chief ALJ terminated settlement procedures and designated a presiding ALJ to oversee hearing procedures. Testimony was filed by the parties from October 2023 through April 2024, and the hearing concluded in June 2024.

In September 2024 the presiding ALJ issued an initial decision recommending that the FERC approve inclusion of a line item in rate base for prepaid and accrued pension costs; however, the presiding ALJ did not agree with System Energy’s proposed methodology to calculate the value of the prepaid and accrued pension cost input. Instead, the presiding ALJ recommended limiting System Energy’s recovery to the prepaid and accrued pension costs that were incurred beginning in 2015 and later.

System Energy disputes the presiding ALJ's determination concerning the methodology used to calculate the prepaid and accrued pension input, and System Energy filed exceptions to these rulings in October 2024. In October 2024, the LPSC, the APSC, and the FERC trial staff filed separate briefs on exceptions; these parties generally argue that the presiding ALJ should have rejected System Energy’s filing entirely, rather than limit System Energy’s recovery of the prepaid and accrued pension costs. Later in October 2024, System Energy, the LPSC, the APSC, and the FERC trial staff filed separate briefs opposing exceptions.

If the ALJ’s determination is affirmed by the FERC, System Energy estimates refunds, including interest through December 31, 2024, of approximately $16 million to $21 million would be owed. The ALJ's initial decision is not binding on the FERC and is an interim step in the hearing process. No refunds will be owed in connection with this proceeding and no changes to System Energy’s pension cost recovery methodology will be implemented unless and until the FERC requires them in a final order. This proceeding is not covered by the global settlements described above.
Storm Cost Recovery Filings with Retail Regulators

Entergy Louisiana

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.

In December 2024, and subsequently amended in an errata filed in February 2025, Entergy Louisiana submitted an application to the LPSC seeking a determination that approximately $183.6 million in storm restoration costs associated with Hurricane Francine were reasonable and necessary and, therefore, eligible for recovery from customers, as well as approval to recover approximately $3.6 million in certain carrying costs from customers. The $183.6 million includes approximately $152.8 million in distribution capital costs and approximately $29.8 million in non-capital costs; the balance consists of transmission and generation capital costs. Entergy Louisiana proposes in its application to recover its distribution-related capital costs of $152.8 million through the distribution recovery mechanism of its formula rate plan. Entergy Louisiana has further requested the LPSC to authorize recovery of these distribution-related capital expenses through an interim rate adjustment, subject to true-up and refund, that would begin with the first billing cycle of March 2025. Entergy Louisiana also requested to recover, from its storm reserve escrow account, $33.5 million, which consists of non-capital costs and certain carrying costs. Entergy Louisiana has also proposed to recover the transmission and generation capital costs through separate ratemaking proceedings. In February 2025, Entergy Louisiana withdrew the $33.5 million from its storm reserve escrow account. The period for intervention has expired, and a status conference for the purpose of establishing a procedural schedule has been set for March 2025.
Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida

In August 2020 and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of Entergy Louisiana’s service area. The storms resulted in widespread outages, significant damage to distribution and transmission infrastructure, and the loss of sales during the outages. Additionally, as a result of Hurricane Laura’s extensive damage to the grid infrastructure serving the impacted area, large portions of the underlying transmission system required nearly a complete rebuild.

In October 2020, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments in connection with the issuance of shorter-term mortgage bonds to provide interim financing for restoration costs associated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta. Subsequently, Entergy Louisiana and the LPSC staff filed a joint motion seeking approval to exclude from the derivation of Entergy Louisiana’s capital structure and cost rate of debt for ratemaking purposes, including the allowance for funds used during construction, shorter-term debt up to $1.1 billion issued by Entergy Louisiana to fund costs associated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta costs on an interim basis. In November 2020 the LPSC issued an order approving the joint motion, and Entergy Louisiana issued $1.1 billion of 0.62% Series mortgage bonds due November 2023. Also in November 2020, Entergy Louisiana withdrew $257 million from its funded storm reserves.

In February 2021 two winter storms (collectively, Winter Storm Uri) brought freezing rain and ice to Louisiana. Ice accumulation sagged or downed trees, limbs, and power lines, causing damage to Entergy Louisiana’s transmission and distribution systems. The additional weight of ice caused trees and limbs to fall into power lines and other electric equipment. When the ice melted, it affected vegetation and electrical equipment, causing additional outages. Entergy Louisiana recovered the incremental fuel costs associated with Winter Storm Uri over a five-month period from April 2021 through August 2021.

In April 2021, Entergy Louisiana filed an application with the LPSC relating to Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri restoration costs and in July 2021, Entergy Louisiana made a supplemental filing updating the total restoration costs. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by these storms were estimated to be approximately $2.06 billion, including approximately $1.68 billion in capital costs and approximately $380 million in non-capital costs. Including carrying costs through January 2022, Entergy Louisiana sought an LPSC determination that $2.11 billion was prudently incurred and, therefore, was eligible for recovery from customers. Additionally, Entergy Louisiana requested that the LPSC determine that re-establishment of a storm escrow account to the previously authorized amount of $290 million was appropriate. In July 2021, Entergy Louisiana supplemented the application with a request regarding the financing and recovery of the recoverable storm restoration costs. Specifically, Entergy Louisiana requested approval to securitize its restoration costs pursuant to Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021.

In August 2021, Hurricane Ida caused extensive damage to Entergy Louisiana’s distribution and, to a lesser extent, transmission systems resulting in widespread power outages. In September 2021, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments in connection with the issuance of approximately $1 billion of shorter-term mortgage bonds to provide interim financing for restoration costs associated with Hurricane Ida, which bonds were issued in October 2021. Also in September 2021, Entergy Louisiana sought approval for the creation and funding of a $1 billion restricted escrow account for Hurricane Ida related restoration costs, subject to a subsequent prudence review.

After filing of testimony by the LPSC staff and intervenors, which generally supported or did not oppose Entergy Louisiana’s requests in regard to Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida, the parties negotiated and executed an uncontested stipulated settlement which was filed with the LPSC in February 2022. The settlement agreement contained the following key terms: $2.1 billion of restoration costs from Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri were prudently incurred and
eligible for recovery; carrying costs of $51 million were recoverable; a $290 million cash storm reserve should be re-established; a $1 billion reserve should be established to partially pay for Hurricane Ida restoration costs; and Entergy Louisiana was authorized to finance $3.186 billion utilizing the securitization process authorized by Act 55, as supplemented by Act 293. The LPSC issued an order approving the settlement in March 2022. As a result of the financing order, Entergy Louisiana reclassified $1.942 billion from utility plant to other regulatory assets.

In May 2022 the securitization financing closed, resulting in the issuance of $3.194 billion principal amount of bonds by Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA), a political subdivision of the State of Louisiana. The securitization was authorized pursuant to the Louisiana Utilities Restoration Corporation Act, Part VIII of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana legislature approved in 2021. The LCDA loaned the proceeds to the LURC. Pursuant to Act 293, the LURC contributed the net bond proceeds to a State legislatively authorized and LURC-sponsored trust, Restoration Law Trust I (the storm trust I).

Pursuant to Act 293, the net proceeds of the bonds were used by the storm trust I to purchase 31,635,718.7221 Class A preferred, non-voting membership interest units (the preferred membership interests) issued by Entergy Finance Company. Entergy Finance Company is required to make annual distributions (dividends) commencing on December 15, 2022 on the preferred membership interests issued to the storm trust I. These annual dividends received by the storm trust I will be distributed to Entergy Louisiana and the LURC, as beneficiaries of the storm trust I. Specifically, 1% of the annual dividends received by the storm trust I will be distributed to the LURC, for the benefit of customers, and 99% will be distributed to Entergy Louisiana, net of storm trust expenses. The preferred membership interests have a stated annual cumulative cash dividend rate of 7% and a liquidation price of $100 per unit. The terms of the preferred membership interests include certain financial covenants to which Entergy Finance Company is subject. Semi-annual redemptions of the preferred membership interests, subject to certain conditions, are expected to occur over the next 15 years.

Entergy and Entergy Louisiana do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA. The bonds are secured by system restoration property, which is the right granted by law to the LURC to collect a system restoration charge from customers. The system restoration charge is adjusted at least semi-annually to ensure that it is sufficient to service the bonds. Entergy Louisiana collects the system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee. Entergy Louisiana began collecting the system restoration charge effective with the first billing cycle of June 2022 and the system restoration charge is expected to remain in place for up to 15 years. Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as a billing and collection agent for the LCDA and the LURC. In the remote possibility that the system restoration charge, as well as any funds in the excess subaccount and funds in the debt service reserve account, are insufficient to service the bonds resulting in a payment default, the storm trust I is required to liquidate Entergy Finance Company preferred membership interests in an amount equal to what would be required to cure the default. The estimated value of this indirect guarantee is immaterial.

From the proceeds from the issuance of the preferred membership interests, Entergy Finance Company distributed $1.4 billion to its parent, Entergy Holdings Company, LLC, a company wholly-owned and consolidated by Entergy. Subsequently, Entergy Holdings Company liquidated, distributing the $1.4 billion it received from Entergy Finance Company to Entergy Louisiana as holder of 6,843,780.24 units of Class A, 4,126,940.15 units of Class B, and 2,935,152.69 units of Class C preferred membership interests. Entergy Louisiana had acquired these preferred membership interests with proceeds from previous securitizations of storm restoration costs. Entergy Finance Company loaned the remaining $1.7 billion from the preferred membership interests proceeds to Entergy which used the cash to redeem $650 million of 4.00% Series senior notes due July 2022 and indirectly contributed $1 billion to Entergy Louisiana as a capital contribution.

Entergy Louisiana used the $1 billion capital contribution to fund its Hurricane Ida escrow account and subsequently withdrew the $1 billion from the escrow account. With a portion of the $1 billion withdrawn from the
escrow account and the $1.4 billion from the Entergy Holdings Company liquidation, Entergy Louisiana deposited $290 million in a restricted escrow account as a storm damage reserve for future storms, used $1.2 billion to repay its unsecured term loan due June 2023, and used $435 million to redeem a portion of its 0.62% Series mortgage bonds due November 2023.

As discussed in Note 3 to the financial statements, the securitization resulted in recognition of a reduction of income tax expense of approximately $290 million by Entergy Louisiana. Entergy’s recognition of reduced income tax expense was partially offset by other tax charges resulting in a net reduction of income tax expense of $283 million. In recognition of obligations described in an LPSC ancillary order issued as part of the securitization regulatory proceeding, Entergy Louisiana recorded a $224 million ($165 million net-of-tax) regulatory charge and a corresponding regulatory liability to reflect its obligation to provide credits to its customers.

As discussed in Note 6 and Note 17 to the financial statements, Entergy Louisiana consolidates the storm trust I as a variable interest entity and the LURC’s 1% beneficial interest is presented as noncontrolling interest in the financial statements. In second quarter 2022, Entergy Louisiana recorded a charge of $31.6 million in other income to reflect the LURC’s beneficial interest in the storm trust I.

In April 2022, Entergy Louisiana filed an application with the LPSC relating to Hurricane Ida restoration costs. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by Hurricane Ida were estimated to be approximately $2.54 billion, including approximately $1.96 billion in capital costs and approximately $586 million in non-capital costs. Including carrying costs of $57 million through December 2022, Entergy Louisiana was seeking an LPSC determination that $2.60 billion was prudently incurred and, therefore, eligible for recovery from customers. As part of this filing, Entergy Louisiana also was seeking an LPSC determination that an additional $32 million in costs associated with the restoration of Entergy Louisiana’s electric facilities damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta as well as Winter Storm Uri was prudently incurred. This amount was exclusive of the requested $3 million in carrying costs through December 2022. In total, Entergy Louisiana was requesting an LPSC determination that $2.64 billion was prudently incurred and, therefore, eligible for recovery from customers. As discussed above, in March 2022 the LPSC approved financing of a $1 billion storm escrow account from which funds were withdrawn to finance costs associated with Hurricane Ida restoration. In June 2022, Entergy Louisiana supplemented the application with a request regarding the financing and recovery of the recoverable storm restoration costs. Specifically, Entergy Louisiana requested approval to securitize its restoration costs pursuant to Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021. In October 2022 the LPSC staff recommended a finding that the requested storm restoration costs of $2.64 billion, including associated carrying costs of $59.1 million, were prudently incurred and eligible for recovery from customers. The LPSC staff further recommended approval of Entergy Louisiana’s plans to securitize these costs, net of the $1 billion in funds withdrawn from the storm escrow account described above. The parties negotiated and executed an uncontested stipulated settlement which was filed with the LPSC in December 2022. The settlement agreement contains the following key terms: $2.57 billion of restoration costs from Hurricane Ida, Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri were prudently incurred and eligible for recovery; carrying costs of $59.2 million were recoverable; and Entergy Louisiana was authorized to finance $1.657 billion utilizing the securitization process authorized by Act 55, as supplemented by Act 293. A procedural motion to consider the uncontested settlement at the December 2022 LPSC meeting did not pass and the settlement was not voted on. In January 2023 an ALJ with the LPSC conducted a settlement hearing to receive the uncontested settlement and supporting testimony into evidence and issued a report of proceedings, which allows the LPSC to consider the uncontested settlement without the procedural motion that did not pass in December. In January 2023 the LPSC approved the stipulated settlement subject to certain modifications. These modifications include the recognition of accumulated deferred income tax benefits related to damaged assets and system restoration costs as a reduction of the amount authorized to be financed utilizing the securitization process authorized by Act 55, as supplemented by Act 293, from $1.657 billion to $1.491 billion. These modifications did not affect the LPSC’s conclusion that all system restoration costs sought by Entergy Louisiana were reasonable and prudent. In February 2023 the Louisiana Bond Commission voted to authorize the LCDA to issue the bonds authorized in the LPSC’s financing order.
In March 2023 the Hurricane Ida securitization financing closed, resulting in the issuance of approximately $1.491 billion principal amount of bonds by the LCDA and a remaining regulatory asset of $180 million to be recovered through the exclusion of the accumulated deferred income taxes related to damaged assets and system restoration costs from the determination of future rates. The securitization was authorized pursuant to the Louisiana Utilities Restoration Corporation Act, Part VIII of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021. The LCDA loaned the proceeds to the LURC. Pursuant to Act 293, the LURC contributed the net bond proceeds to a State legislatively authorized and LURC-sponsored trust, Restoration Law Trust II (the storm trust II).

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

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

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

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

As discussed in Note 6 and Note 17 to the financial statements, Entergy Louisiana consolidates the storm trust II as a variable interest entity and the LURC’s 1% beneficial interest is presented as noncontrolling interest in
the financial statements. In first quarter 2023, Entergy Louisiana recorded a charge of $14.6 million in other income to reflect the LURC’s beneficial interest in the storm trust II.

Hurricane Isaac

In August 2012, Hurricane Isaac caused extensive damage to Entergy Louisiana’s service area.  In June 2014 the LPSC authorized Entergy Louisiana to utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs.  Entergy Louisiana committed to pass on to customers a minimum of $30.8 million of customer benefits through annual customer credits of approximately $6.2 million for five years. Approvals for the Act 55 financings were obtained from the LURC and the Louisiana State Bond Commission.

In August 2014 the LCDA issued $314.85 million in bonds under Louisiana Act 55.  From the $309 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $16 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $293 million directly to Entergy Louisiana.  Entergy Louisiana used the $293 million received from the LURC to acquire 2,935,152.69 Class C preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 7.5% annual distribution rate. Distributions were payable quarterly commencing on September 15, 2014, and the membership interests had a liquidation price of $100 per unit. The preferred membership interests were callable at the option of Entergy Holdings Company after ten years under the terms of the LLC agreement. The terms of the membership interests included certain financial covenants to which Entergy Holdings Company was subject, including the requirement to maintain a net worth of at least $1.75 billion. As discussed above in “Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida”, in May 2022, Entergy Holdings Company liquidated and distributed cash to Entergy Louisiana as holder of the 2,935,152.69 units of Class C preferred membership interests.

Entergy and Entergy Louisiana do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA and there is no recourse against Entergy or Entergy Louisiana in the event of a bond default.  To service the bonds, Entergy Louisiana collects a system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee.  Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as the billing and collection agent for the state.

Hurricane Gustav and Hurricane Ike

In September 2008, Hurricane Gustav and Hurricane Ike caused catastrophic damage to Entergy Louisiana’s service territory.  In December 2009, Entergy Louisiana entered into a stipulation agreement with the LPSC staff regarding its storm costs.  In March and April 2010, Entergy Louisiana and other parties to the proceeding filed with the LPSC an uncontested stipulated settlement that included Entergy Louisiana’s proposal to utilize Act 55 financing, which included a commitment to pass on to customers a minimum of $43.3 million of customer benefits through a prospective annual rate reduction of $8.7 million for five years.  In April 2010 the LPSC approved the settlement and subsequently issued financing orders and a ratemaking order intended to facilitate the implementation of the Act 55 financings.  In June 2010 the Louisiana State Bond Commission approved the Act 55 financing. The settlement agreement allowed for an adjustment to the credits if there was a change in the applicable federal or state income tax rate. As a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, and the lowering of the federal corporate income tax rate from 35% to 21%, the Louisiana Act 55 financing savings obligation regulatory liability related to Hurricane Gustav and Hurricane Ike was reduced by $2.7 million, with a corresponding increase to Other regulatory credits on the income statement. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.

In July 2010 the LCDA issued two series of bonds totaling $713.0 million under Act 55.  From the $702.7 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $290 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $412.7 million directly to Entergy Louisiana.  From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana
used $412.7 million to acquire 4,126,940.15 Class B preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 9% annual distribution rate. Distributions were payable quarterly commencing on September 15, 2010, and the membership interests had a liquidation price of $100 per unit. The preferred membership interests were callable at the option of Entergy Holdings Company after ten years under the terms of the LLC agreement.  The terms of the membership interests included certain financial covenants to which Entergy Holdings Company was subject, including the requirement to maintain a net worth of at least $1 billion. As discussed above in “Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida”, in May 2022, Entergy Holdings Company liquidated and distributed cash to Entergy Louisiana as holder of the 4,126,940.15 units of Class B preferred membership interests.

The bonds were repaid in 2022. Entergy and Entergy Louisiana did not report the bonds issued by the LCDA on their balance sheets because the bonds were the obligation of the LCDA, and there was no recourse against Entergy or Entergy Louisiana in the event of a bond default.  To service the bonds, Entergy Louisiana collected a system restoration charge on behalf of the LURC and remitted the collections to the bond indenture trustee.  Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as the billing and collection agent for the state.

Hurricane Katrina and Hurricane Rita

In August and September 2005, Hurricanes Katrina and Rita caused catastrophic damage to Entergy Louisiana’s service territory. In March 2008, Entergy Louisiana and the LURC filed at the LPSC an application requesting that the LPSC grant a financing order authorizing the financing of Entergy Louisiana storm costs, storm reserves, and issuance costs pursuant to Louisiana Act 55.  Entergy Louisiana also filed an application requesting LPSC approval for ancillary issues including the mechanism to flow charges and savings to customers via a storm cost offset rider.  In April 2008 the Louisiana Public Facilities Authority (LPFA), which is the issuer of the bonds pursuant to the Act 55 financing, approved requests for the Act 55 financing.  Also in April 2008, Entergy Louisiana and the LPSC staff filed with the LPSC an uncontested stipulated settlement that included Entergy Louisiana’s proposal under the Act 55 financing, which included a commitment to pass on to customers a minimum of $40 million of customer benefits through a prospective annual rate reduction of $8 million for five years.  The LPSC subsequently approved the settlement and issued two financing orders and one ratemaking order intended to facilitate implementation of the Act 55 financing.  In May 2008 the Louisiana State Bond Commission granted final approval of the Act 55 financing. The settlement agreement allowed for an adjustment to the credits if there was a change in the applicable federal or state income tax rate. As a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, and the lowering of the federal corporate income tax rate from 35% to 21%, the Louisiana Act 55 financing savings obligation regulatory liability related to Hurricanes Katrina and Rita was reduced by $22.3 million, with a corresponding increase to Other regulatory credits on the income statement. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.

In July 2008 the LPFA issued $687.7 million in bonds under the aforementioned Act 55.  From the $679 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $152 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $527 million directly to Entergy Louisiana.  From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $545 million, including $17.8 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 5,449,861.85 Class A preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 10% annual distribution rate.  In August 2008 the LPFA issued $278.4 million in bonds under the aforementioned Act 55.  From the $274.7 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $87 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $187.7 million directly to Entergy Louisiana.  From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $189.4 million, including $1.7 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 1,893,918.39 Class A preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 10% annual distribution rate.  Distributions were payable quarterly commencing on September 15, 2008 and had a
liquidation price of $100 per unit.  The preferred membership interests were callable at the option of Entergy Holdings Company after ten years under the terms of the LLC agreement.  The terms of the membership interests included certain financial covenants to which Entergy Holdings Company was subject, including the requirement to maintain a net worth of at least $1 billion.  In February 2012, Entergy Louisiana sold 500,000 of its Class A preferred membership units in Entergy Holdings Company to a third party. Those preferred membership units were subsequently repurchased by Entergy Holdings Company in March 2019. As discussed above in “Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida”, in May 2022, Entergy Holdings Company liquidated and distributed cash to Entergy Louisiana as holder of the remaining 6,843,780.24 units of Class A preferred membership interests.

The bonds were repaid in 2018. Entergy and Entergy Louisiana did not report the bonds issued by the LPFA on their balance sheets because the bonds were the obligation of the LPFA, and there was no recourse against Entergy or Entergy Louisiana in the event of a bond default.  To service the bonds, Entergy Louisiana collected a system restoration charge on behalf of the LURC and remitted the collections to the bond indenture trustee.  Entergy and Entergy Louisiana did not report the collections as revenue because Entergy Louisiana was merely acting as the billing and collection agent for the state.

Entergy Mississippi

Prior to June 2024, Entergy Mississippi had approval from the MPSC to collect a storm damage provision of $1.75 million per month. If Entergy Mississippi’s accumulated storm damage provision balance exceeded $15 million, the collection of the storm damage provision ceased until such time that the accumulated storm damage provision became less than $10 million. Entergy Mississippi’s storm damage provision balance had been less than $10 million since May 2019, and Entergy Mississippi had been billing the monthly storm damage provision since July 2019.

In December 2023, Entergy Mississippi filed a Notice of Storm Escrow Disbursement and Request for Interim Relief notifying the MPSC that Entergy Mississippi had requested disbursement of approximately $34.5 million of storm escrow funds from its restricted storm escrow account. The filing also requested authorization from the MPSC, on a temporary basis, that the $34.5 million of storm escrow funds be credited to Entergy Mississippi’s storm damage provision, pending the MPSC’s review of Entergy Mississippi’s storm-related costs, and that Entergy Mississippi continue to bill its monthly storm damage provision without suspension in the event the storm damage provision balance exceeded $15 million, in anticipation of a subsequent filing by Entergy Mississippi in this proceeding. The storm damage provision exceeded $15 million upon receipt of the storm escrow funds. Because the MPSC had not entered an order on Entergy Mississippi’s filing on the requested relief to continue billing this provision, Entergy Mississippi suspended billing the monthly storm damage provision effective with February 2024 bills.

In March 2024, Entergy Mississippi made a combined dual filing which included a notice of intent to make routine change in rates and schedules and a motion for determination relating to the above-described notice of storm escrow disbursement. The notice of intent proposed a new storm damage mitigation and restoration rider to supersede both the then-current storm damage rate schedule and the vegetation management rider schedule, in which the collection of both expenses would be combined. The proposal requested that the MPSC authorize Entergy Mississippi to collect approximately $5.2 million per month for vegetation management and a storm damage provision. Furthermore, if Entergy Mississippi’s accumulated vegetation management and storm damage provision balance were to exceed $70 million, collection under the storm damage mitigation and restoration rider would cease until such time that the accumulated vegetation management and storm damage provision would become less than $60 million.

The Mississippi Public Utilities Staff reviewed the storm-related costs submitted by Entergy Mississippi and found them prudent. In June 2024 the MPSC considered and unanimously granted the relief sought by Entergy Mississippi, including authorization to credit any remaining funds in the storm escrow account to Entergy
Mississippi’s storm damage provision and to close the storm escrow account and approving the new storm damage mitigation and restoration rider. Entergy Mississippi’s storm escrow account was liquidated in July 2024, and the new combined storm damage mitigation and restoration rider became effective with the July 2024 billing cycle. Additionally, Entergy Mississippi made a compliance filing to cease billing under the existing vegetation management rider schedule as of the same billing cycle.

Entergy New Orleans

Hurricane Ida

In August 2021, Hurricane Ida caused significant damage to Entergy New Orleans’s service area, including Entergy’s electrical grid. The storm resulted in widespread power outages, including the loss of 100% of Entergy New Orleans’s load and damage to distribution and transmission infrastructure, including the loss of connectivity to the eastern interconnection. In September 2021, Entergy New Orleans withdrew $39 million from its funded storm reserves. In June 2022, Entergy New Orleans filed an application with the City Council requesting approval and certification that storm restoration costs associated with Hurricane Ida of approximately $170 million, which included $11 million in estimated costs, were reasonable, necessary, and prudently incurred to enable Entergy New Orleans to restore electric service to its customers and to repair Entergy New Orleans’s electric utility infrastructure. In addition, estimated carrying costs through December 2022 related to Hurricane Ida restoration costs were $9 million. Also, Entergy New Orleans requested approval that the $39 million withdrawal from its funded storm reserve in September 2021 and $7 million in excess storm reserve escrow withdrawals related to Hurricane Zeta in October 2020 and prior miscellaneous storms were properly applied to Hurricane Ida storm restoration costs, the application of which reduced the amount to be recovered from Entergy New Orleans customers by $46 million.

Additionally, in February 2022, Entergy New Orleans and the LURC filed with the City Council a securitization application requesting that the City Council review Entergy New Orleans’s storm reserve and increase the storm reserve funding level to $150 million, to be funded through securitization. In August 2022 the City Council’s advisors recommended that the City Council authorize a single securitization bond issuance to fund Entergy New Orleans’s storm recovery reserves to an amount sufficient to: (1) allow recovery of all of Entergy New Orleans’s unrecovered storm recovery costs following Hurricane Ida, subject to City Council review and certification; (2) provide initial funding of storm recovery reserves for future storms to a level of $75 million; and (3) fund the storm recovery bonds’ upfront financing costs. In September 2022, Entergy New Orleans and the City Council’s advisors entered into an agreement in principle, which was approved by the City Council along with a financing order in October 2022, which authorized Entergy New Orleans and the LURC to proceed with a single securitization bond issuance of approximately $206 million (subject to further adjustment and review pursuant to the Final Issuance Advice Letter process set forth in the financing order), with $125 million of that total to be used for interim recovery, subject to City Council review and certification, to be allocated to unrecovered Hurricane Ida storm recovery costs; $75 million of that total to provide for a storm recovery reserve for future storms; and the remainder to fund the recovery of the storm recovery bonds’ upfront financing costs.

In December 2022, Entergy New Orleans and the LURC filed with the City Council the Final Issuance Advice Letter for a securitization bond issuance in the amount of $209.3 million, the final structuring, terms, and pricing of which were approved by the City Council in accordance with the financing order. Also in December 2022 the LCDA issued $209.3 million in bonds pursuant to the Louisiana Electric Utility Storm Recovery Securitization Act, Part V-B of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana Regular Session of 2021. The LCDA loaned $201.8 million of bond proceeds, net of certain debt service and issuance costs, to the LURC. The LURC used the proceeds to purchase from Entergy New Orleans the storm recovery property, which is the right to collect storm recovery charges sufficient to pay the storm recovery bonds and associated financing costs, and Entergy New Orleans deposited $200 million in a restricted storm reserve escrow account as a storm damage reserve for Entergy New Orleans and received directly $1.8 million in estimated upfront financing costs. Subsequently, Entergy New Orleans withdrew $125 million from the newly securitized
storm reserve to cover Hurricane Ida storm recovery costs, subject to a final determination from the City Council regarding the prudency of the storm recovery costs.

Entergy and Entergy New Orleans do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA, and there is no recourse against Entergy or Entergy New Orleans in the event of a bond default. To service the bonds, Entergy New Orleans collects a storm recovery charge on behalf of the LURC and remits the collections to the bond indenture trustee. Entergy and Entergy New Orleans do not report the collections as revenue because Entergy New Orleans is merely acting as the billing and collection agent for the LURC.

In August 2023 the City Council advisors issued a report recommending that the City Council find that Entergy New Orleans prudently incurred approximately $164.1 million in storm restoration costs and $7.5 million in carrying charges and that such costs have already been properly recovered by Entergy New Orleans through withdrawals from the storm reserve escrow account. The City Council advisors also recommended that the City Council find that approximately $1.2 million in storm restoration costs had already been recovered through Entergy New Orleans’s base rates and that approximately $0.9 million in unused credits be applied against future storm costs. In August 2023 the City Council hearing officer certified the evidentiary record. In December 2023 the City Council approved a resolution adopting the advisors’ report and recommendations.

Entergy Texas

Hurricane Laura, Hurricane Delta, and Winter Storm Uri

In August 2020 and October 2020, Hurricane Laura and Hurricane Delta caused extensive damage to Entergy Texas’s service area. In February 2021, Winter Storm Uri also caused damage to Entergy Texas’s service area. The storms resulted in widespread power outages, significant damage primarily to distribution and transmission infrastructure, and the loss of sales during the power outages. In April 2021, Entergy Texas filed an application with the PUCT requesting a determination that approximately $250 million of system restoration costs associated with Hurricane Laura, Hurricane Delta, and Winter Storm Uri, including approximately $200 million in capital costs and approximately $50 million in non-capital costs, were reasonable and necessary to enable Entergy Texas to restore electric service to its customers and Entergy Texas’s electric utility infrastructure. The filing also included the projected balance of approximately $13 million of a regulatory asset containing previously approved system restoration costs related to Hurricane Harvey. In September 2021 the parties filed an unopposed settlement agreement, pursuant to which Entergy Texas removed from the amount to be securitized approximately $4.3 million that will instead be charged to its storm reserve, $5 million related to no particular issue, of which Entergy Texas would be permitted to seek recovery in a future proceeding, and approximately $300 thousand related to attestation costs. In December 2021 the PUCT issued an order approving the unopposed settlement and determining system restoration costs of $243 million related to Hurricane Laura, Hurricane Delta, and Winter Storm Uri and the $13 million projected remaining balance of the Hurricane Harvey system restoration costs were eligible for securitization. The order also determines that Entergy Texas can recover carrying costs on the system restoration costs related to Hurricane Laura, Hurricane Delta, and Winter Storm Uri.

In July 2021, Entergy Texas filed with the PUCT an application for a financing order to approve the securitization of the system restoration costs that are the subject of the April 2021 application. In November 2021 the parties filed an unopposed settlement agreement supporting the issuance of a financing order consistent with Entergy Texas’s application and with minor adjustments to certain upfront and ongoing costs to be incurred to facilitate the issuance and serving of system restoration bonds. In January 2022 the PUCT issued a financing order consistent with the unopposed settlement. As a result of the financing order, Entergy Texas reclassified $153 million from utility plant to other regulatory assets.

In April 2022, Entergy Texas Restoration Funding II, LLC, a company wholly-owned and consolidated by Entergy Texas, issued $290.85 million of senior secured system restoration bonds (securitization bonds). With the
proceeds, Entergy Texas Restoration Funding II purchased from Entergy Texas the transition property, which is the right to recover from customers through a system restoration charge amounts sufficient to service the securitization bonds. Entergy Texas began cost recovery through the system restoration charge effective with the first billing cycle of May 2022 and the system restoration charge is expected to remain in place up to 15 years. See Note 5 to the financial statements for a discussion of the April 2022 issuance of the securitization bonds.
Entergy Arkansas [Member]  
Public Utilities Disclosure [Text Block] RATE AND REGULATORY MATTERS (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Regulatory Assets and Regulatory 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. In addition to the regulatory assets and liabilities that are specifically disclosed on the face of the balance sheets, the tables below provide detail of “Other regulatory assets” and “Other regulatory liabilities” that are included on Entergy’s and the Registrant Subsidiaries’ balance sheets as of December 31, 2024 and 2023 (as noted in footnotes to the tables, a portion of these regulatory assets and regulatory liabilities is classified as held for sale in the balance sheets as of December 31, 2024):

Other Regulatory Assets

Entergy
20242023
 (In Millions)
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
$1,387.6 $1,655.5 
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or shutdown of non-nuclear power plants and solar facilities (Note 9) (a)
1,358.7 1,285.0 
Removal costs (Note 9)
1,107.6 1,010.7 
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators and Note 5 - Securitization Bonds)
547.3 536.9 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
227.1 250.9 
Retail rate deferrals - recovered through formula rates or rate riders as rates are redetermined by retail regulators
195.1 248.6 
Retired electric and gas meters - recovered through retail rates as determined by retail regulators (Note 2 - Retail Rate Proceedings)
135.7 153.8 
Deferred COVID-19 costs - recovered through retail rates as determined by retail regulators (Note 2 - Retail Rate Proceedings)
104.0 118.0 
Unamortized loss on reacquired debt - recovered over term of debt
57.9 63.1 
Advanced metering system surcharge for residential customers - recovered through December 2029
39.7 20.2 
Formula rate plan historical year rate adjustment (Note 2 - Retail Rate Proceedings) (b)
15.5 — 
Pension & postretirement benefits expense deferral - recovered through retail rates (Note 2 - Retail Rate Proceedings and Note 11 - Entergy Texas Reserve)
15.0 32.7 
Rate case depreciation relate back deferral - recovered over a six-month period beginning January 2024 (Note 2 - Retail Rate Proceedings)
— 27.6 
Opportunity sales - (Note 2 - Entergy Arkansas Opportunity Sales Proceeding) (b)
— 131.8 
Other99.7 134.6 
Entergy Total (c)
$5,290.9 $5,669.4 
Entergy Arkansas
 20242023
 (In Millions)
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or shutdown of non-nuclear power plants and solar facilities (Note 9) (a)
$693.0 $639.1 
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
433.3 536.6 
Removal costs (Note 9)
337.9 319.7 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
75.8 84.1 
Deferred COVID-19 costs - recovered over a 10-year period through December 2033
35.1 39.0 
Retired electric meters - recovered over a 15-year period through March 2034
32.8 36.3 
Storm damage costs - recovered through retail rates
29.8 33.1 
Unamortized loss on reacquired debt - recovered over term of debt
18.6 19.9 
Formula rate plan historical year rate adjustment (Note 2 - Retail Rate Proceedings) (b)
15.5 — 
Retail rate deferrals - recovered through rate riders as rates are redetermined annually (b)
13.6 24.9 
ANO Fukushima and Flood Barrier costs - recovered through retail rates through February 2026 (b)
2.1 3.8 
Opportunity sales - (Note 2 - Entergy Arkansas Opportunity Sales Proceeding) (b)
— 131.8 
Other12.6 17.1 
Entergy Arkansas Total$1,700.1 $1,885.4 

Entergy Louisiana
 20242023
 (In Millions)
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or shutdown of non-nuclear power plants (Note 9) (a)
$421.5 $408.7 
Pension & postretirement costs (Note 11 - Qualified Pension Plans and Non-Qualified Pension Plans) (a)
367.7 412.0 
Removal costs (Note 9)
323.2 262.3 
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)
226.6 202.6 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
111.4 123.0 
Retired electric and gas meters - recovered over a 22-year period through July 2041
78.5 83.2 
Deferred COVID-19 costs - recovery period to be determined (Note 2 - Retail Rate Proceedings) (a)
47.8 47.8 
Unamortized loss on reacquired debt - recovered over term of debt
21.7 23.4 
Other48.5 85.9 
Entergy Louisiana Total (c)
$1,646.9 $1,648.9 
Entergy Mississippi
 20242023
(In Millions)
Removal costs (Note 9)
$184.8 $188.0 
Retail rate deferrals - recovered through formula rates or rate riders as rates are redetermined annually
162.5 192.8 
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
112.1 127.6 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
29.1 32.0 
Asset retirement obligation - recovery dependent upon timing of shutdown of non-nuclear power plants and solar facility (Note 9) (a)
9.4 6.8 
Unamortized loss on reacquired debt - recovered over term of debt
9.1 10.0 
Attorney General litigation costs - recovered over a six-year period through March 2026 (b)
6.0 10.9 
Other12.8 11.0 
Entergy Mississippi Total$525.8 $579.1 

Entergy New Orleans
 20242023
 (In Millions)
Removal costs (Note 9)
$62.5 $61.1 
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
22.9 41.4 
Retired electric and gas meters - recovered over a 12-year period through July 2031 (b)
13.5 15.5 
Gas cross-boring costs - recovered through formula rates as rates are redetermined by retail regulators
11.9 10.9 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
10.8 11.8 
Deferred COVID-19 costs - recovered over a five-year period through August 2028 (b)
10.2 13.0 
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators and Note 5 - Entergy New Orleans Securitization Bonds - Hurricane Isaac)
4.0 3.9 
Unamortized loss on reacquired debt - recovered over term of debt
0.5 0.8 
Other20.7 24.0 
Entergy New Orleans Total (c)
$157.0 $182.4 
Entergy Texas
 20242023
 (In Millions)
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators and Note 5 - Entergy Texas Securitization Bonds - Hurricane Laura, Hurricane Delta, and Winter Storm Uri)
$286.5 $297.3 
Removal costs (Note 9)
102.3 77.5 
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
62.9 85.6 
Advanced metering system surcharge for residential customers - recovered through December 2029
39.7 20.2 
Pension & postretirement benefits expense deferral - recovered through retail rates (Note 2 - Retail Rate Proceedings and Note 11 - Entergy Texas Reserve)
15.0 32.7 
Retired electric meters - recovered through retail rates (Note 2 - Retail Rate Proceedings)
10.9 18.8 
Neches and Sabine costs - recovered over a 10-year period through September 2028
9.2 11.6 
Unamortized loss on reacquired debt - recovered over term of debt
7.6 8.3 
Rate case depreciation relate back deferral - recovered over a six-month period beginning January 2024 (Note 2 - Retail Rate Proceedings)
— 27.6 
Other15.6 17.0 
Entergy Texas Total$549.7 $596.6 

System Energy
 20242023
 (In Millions)
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear unit (Note 9) (b)
$224.8 $222.0 
Pension & postretirement costs (Note 11 - Qualified Pension Plans and Other Postretirement Benefits) (a)
104.4 121.6 
Removal costs - recovered through depreciation rates (Note 9)
96.9 102.1 
Unamortized loss on reacquired debt - recovered over term of debt
0.4 0.7 
System Energy Total$426.5 $446.4 

(a)Does not earn a return on investment, but is offset by related liabilities.
(b)Does not earn a return on investment.
(c)Includes $35.4 million at Entergy, $8.9 million at Entergy Louisiana, and $23.7 million at Entergy New Orleans as of December 31, 2024 of regulatory assets related to the respective natural gas distribution businesses classified as held for sale and included within “Non-current assets held for sale” on the respective consolidated balance sheets. See Note 14 to the financial statements for further discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses and the classification as held for sale.
Other Regulatory Liabilities

Entergy
20242023
(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)
$2,262.5 $1,826.2 
Securitization financing savings obligation (Note 3)
371.3 405.2 
Retail rate rider over-recovery - refunded through formula rate or rate riders as rates are redetermined by retail regulators
164.9 142.7 
Credits from resolution of the 2016-2018 IRS audit (Note 3)
163.3 98.0 
Customer rate credits from global stipulated settlement with the LPSC - returned to customers September 2024 through August 2026 (Note 2)
121.7 — 
Refund from System Energy settlement with the LPSC - to be returned to customers January 2025 through August 2027 (Note 2)
75.8 — 
Deferred tax equity partnership earnings (Note 1)
69.9 57.9 
Vidalia purchased power agreement (Note 8)
67.4 82.5 
Refund from System Energy settlement with the City Council - returned to customers over a 25-year period beginning September 2024 (Note 2)
64.7 — 
Shorter-term financing interest earnings (Note 2 - Retail Rate Proceedings) (a)
48.9 36.8 
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and the FERC
44.4 44.4 
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)
40.9 44.3 
Refund from System Energy settlement with the City Council - return to customers to be determined (Note 2)
32.0 — 
Refund from System Energy settlement with the APSC - refunded through a rate rider as rates are re-determined periodically (Note 2)
8.2 93.0 
Complaints against System Energy - potential future refunds (Note 2)
— 177.9 
Other75.2 108.0 
Entergy Total (b)
$3,611.1 $3,116.9 

Entergy Arkansas
 20242023
 (In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)
$761.3 $621.6 
Deferred tax equity partnership earnings (Note 1)
32.4 27.4 
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually
27.9 10.6 
Refund from System Energy settlement with the APSC - refunded through a rate rider as rates are re-determined periodically (Note 2)
8.2 93.0 
Internal restructuring guaranteed customer credits - returned to customers over a six-year period through December 2024
— 6.6 
Other1.4 — 
Entergy Arkansas Total$831.2 $759.2 
Entergy Louisiana
 20242023
 (In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)
$798.4 $644.0 
Securitization financing savings obligation (Note 3)
371.3 405.2 
Customer rate credits from global stipulated settlement with the LPSC - returned to customers September 2024 through August 2026 (Note 2)
121.7 — 
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually
96.3 86.4 
Refund from System Energy settlement with the LPSC - to be returned to customers January 2025 through August 2027 (Note 2)
75.8 — 
Vidalia purchased power agreement (Note 8)
67.4 82.5 
Shorter-term financing interest earnings (Note 2 - Retail Rate Proceedings) (a)
48.9 36.8 
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)
40.9 44.3 
Hurricane Ida insurance proceeds - returned to customers August 2024 to July 2025
26.0 32.3 
Credits from resolution of the 2016-2018 IRS audit - returned to customers September 2024 through August 2025 (Note 3)
25.3 38.0 
Sale-leaseback and depreciation refunds - returned to customers September 2023 through August 2024
— 14.1 
Other21.7 24.1 
Entergy Louisiana Total (b)
$1,693.7 $1,407.7 

Entergy Mississippi
20242023
 (In Millions)
Deferred tax equity partnership earnings (Note 1)
$37.5 $30.5 
Retail rate rider over-recovery - refunded through formula rate or rate riders as rates are redetermined annually
12.2 2.4 
Other postretirement benefits (Note 11 - Entergy Mississippi Other Postretirement Benefits)
7.4 — 
Other2.4 0.8 
Entergy Mississippi Total$59.5 $33.7 
Entergy New Orleans
20242023
 (In Millions)
Credits from resolution of the 2016-2018 IRS audit - to be returned to customers over a 25-year period beginning January 2025 (Note 3)
$138.0 $60.0 
Refund from System Energy settlement with the City Council - returned to customers over a 25-year period beginning September 2024 (Note 2)
64.7 — 
Refund from System Energy settlement with the City Council - return to customers to be determined (Note 2)
32.0 — 
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually
16.3 20.1 
Sale-leaseback and depreciation refunds - returned to customers over a 10-year period beginning September 2023 (Note 2)
5.2 9.8 
Other4.5 0.5 
Entergy New Orleans Total (b)
$260.7 $90.4 

Entergy Texas
 20242023
 (In Millions)
Retail rate rider over-recovery - return to customers to be determined
$12.2 $23.8 
Retail refunds - return to customers to be determined
6.2 6.2 
Rate case settlement relate back - amortized over a six-month period beginning January 2024 (Note 2 - Retail Rate Proceedings)
— 10.3 
Other 0.3 2.7 
Entergy Texas Total$18.7 $43.0 

System Energy
 20242023
 (In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)
$702.8 $560.6 
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and the FERC
44.4 44.4 
Complaints against System Energy - potential future refunds (Note 2)
— 177.9 
System Energy Total$747.2 $782.9 

(a)Offset by related asset.
(b)Includes $1.6 million at Entergy, $1.2 million at Entergy Louisiana, and $0.4 million at Entergy New Orleans as of December 31, 2024 of regulatory liabilities related to the respective natural gas distribution businesses classified as held for sale and included within other non-current liabilities on the respective consolidated balance sheets. See Note 14 to the financial statements for further discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses and the classification as held for sale.
Regulatory activity regarding the Tax Cuts and Jobs Act

See the “Other Tax Matters - Tax Cuts and Jobs Act” section in Note 3 to the financial statements for discussion of the effects of the December 2017 enactment of the Tax Cuts and Jobs Act (Tax Act), including its effects on Entergy’s and the Registrant Subsidiaries’ regulatory asset/liability for income taxes.

Entergy Louisiana

In an electric formula rate plan settlement approved by the LPSC in April 2018, the parties agreed that Entergy Louisiana would return to customers one-half of its eligible unprotected excess deferred income taxes from May 2018 through December 2018 and return to customers the other half from January 2019 through August 2022. In addition, the settlement provided that in order to flow back to customers certain other tax benefits created by the Tax Act, Entergy Louisiana established a regulatory liability effective January 1, 2018 in the amount of $9.1 million per month to reflect these tax benefits already included in retail rates until new base rates under the formula rate plan were established in September 2018, and this regulatory liability was returned to customers over the September 2018 through August 2019 formula rate plan rate-effective period. The LPSC staff and intervenors in the settlement reserved the right to obtain data from Entergy Louisiana to confirm the determination of excess accumulated deferred income taxes resulting from the Tax Act and the analysis thereof as part of the formula rate plan review proceeding for the 2017 test year filing. As discussed below in “Retail Rate Proceedings - Filings with the LPSC (Entergy Louisiana) - Retail Rates - Electric - Formula Rate Plan Global Settlement”, a global settlement resolving the outstanding issues related to the 2017 formula rate plan filing was reached in October 2023 and approved by the LPSC in November 2023.

System Energy

In a filing made with the FERC in March 2018, System Energy proposed revisions to the Unit Power Sales Agreement to reflect the effects of the Tax Act. In the filing System Energy proposed to return identified quantities of unprotected excess accumulated deferred income taxes to its customers by the end of 2018. In May 2018 the FERC accepted System Energy’s proposed tax revisions with an effective date of June 1, 2018, subject to refund and the outcome of settlement and hearing procedures. Settlement discussions were terminated in April 2019, and a hearing was held in March 2020. In December 2022 the FERC issued an order requiring System Energy to compute the amount of excess accumulated deferred income taxes associated with a previously uncertain decommissioning tax position with consideration for the resolution of the tax position by the IRS. In February 2023, System Energy submitted its compliance filing. This matter was ultimately settled as a result of System Energy’s settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” below for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.
Fuel and purchased power cost recovery

The Utility operating companies are allowed to recover fuel and purchased power costs through fuel mechanisms included in electric and gas rates that are recorded as fuel cost recovery revenues.  The difference between revenues collected and the current fuel and purchased power costs is generally recorded as “Deferred fuel costs” on the Utility operating companies’ financial statements.  The table below shows the amount of deferred fuel costs as of December 31, 2024 and 2023 that each Utility operating company expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.

 20242023
 (In Millions)
Entergy Arkansas
($45.2)($88.3)
Entergy Louisiana (a) (b)$163.4 $192.9 
Entergy Mississippi($126.3)($130.6)
Entergy New Orleans (a) (b)$8.0 $10.2 
Entergy Texas($59.3)$139.0 

(a)Includes $168.1 million in both years for Entergy Louisiana and $4.1 million in both years for Entergy New Orleans of fuel, purchased power, and capacity costs, which do not currently earn a return on investment and whose recovery periods are indeterminate but are expected to be recovered over a period greater than twelve months.
(b)Includes $0.7 million at Entergy Louisiana and $4.9 million at Entergy New Orleans as of December 31, 2024 of deferred fuel assets related to the respective natural gas distribution businesses classified as held for sale and included within “Current assets held for sale” on the respective consolidated balance sheets. See Note 14 to the financial statements for further discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses and the classification as held for sale.

Entergy Arkansas

Energy Cost Recovery Rider

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

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

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

In March 2018, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01547 per kWh to $0.01882 per kWh. The Arkansas Attorney General filed a response to Entergy Arkansas’s annual redetermination filing requesting that the APSC suspend the proposed tariff to investigate the amount of the redetermination or, alternatively, to allow recovery subject to refund. Among the reasons the Attorney General cited for suspension were questions pertaining to how Entergy Arkansas forecasted sales and potential implications of the Tax Cuts and Jobs Act. Entergy Arkansas replied to the Attorney General’s filing and stated that, to the extent there are questions pertaining to its load forecasting or the operation of the energy cost recovery rider, those issues exceed the scope of the instant rate redetermination. Entergy Arkansas also stated that potential effects of the Tax Cuts and Jobs Act are appropriately considered in the APSC’s separate proceeding regarding potential implications of the tax law. The APSC general staff filed a reply to the Attorney General’s filing and agreed that Entergy Arkansas’s filing complied with the terms of the energy cost recovery rider. The redetermined rate became effective with the first billing cycle of April 2018. Subsequently in April 2018 the APSC issued an order declining to suspend Entergy Arkansas’s energy cost recovery rider rate and declining to require further investigation at that time of the issues suggested by the Attorney General in the proceeding. Following a period of discovery, the Attorney General filed a supplemental response in October 2018 raising new issues with Entergy Arkansas’s March 2018 rate redetermination and asserting that $45.7 million of the increase should be collected subject to refund pending further investigation. Entergy Arkansas filed to dismiss the Attorney General’s supplemental response, the APSC general staff filed a motion to strike the Attorney General’s filing, and the Attorney General filed a supplemental response disputing Entergy Arkansas and the APSC staff’s filing. Applicable APSC rules and processes authorize its general staff to initiate periodic audits of Entergy Arkansas’s energy cost recovery rider. In late-2018 the APSC general staff notified Entergy Arkansas it initiated an audit of the 2017 fuel costs. The time in which the audit will be complete is uncertain at this time.

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

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

In March 2024, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease in the rate from $0.01883 per kWh to $0.00882 per kWh. Due to a change in law in the State of Arkansas, the annual redetermination included $9 million, recorded as a credit to fuel expense in first quarter 2024, for recovery attributed to net metering costs in 2023. The primary reason for the rate decrease is a large over-recovered balance as a result of lower natural gas prices in 2023. To mitigate the effect of projected increases in natural gas prices in 2024, Entergy Arkansas adjusted the over-recovered balance included in the March 2024 annual redetermination filing by $43.7 million. This adjustment is expected to reduce the rate change that will be reflected in the 2025 energy cost rate redetermination. The redetermined rate of $0.00882 per kWh became effective with the first billing cycle in April 2024 through the normal operation of the tariff.

Entergy Louisiana

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

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

In March 2020 the LPSC staff provided notice of an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2016 through 2019. The LPSC staff issued its audit report in September 2021, and although certain internal record keeping recommendations were made, the LPSC staff did not recommend any disallowances. The next step is for the LPSC to review the report, but there is not a deadline for the review.

In January 2023 the LPSC staff provided notice of an audit of Entergy Louisiana’s purchased gas adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s purchased gas adjustment clause for the period from 2021 through 2022. Discovery is ongoing, and no audit report has been filed.
In January 2023 the LPSC staff provided notice of an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2020 through 2022. Discovery is ongoing, and no audit report has been filed.

Entergy Mississippi

Entergy Mississippi’s rate schedules include an energy cost recovery rider and a power management rider, both of which are adjusted annually to reflect accumulated over- or under-recoveries. Entergy Mississippi recovers fuel and purchased energy costs through its energy cost recovery rider and recovers costs associated with natural gas hedging and capacity payments through its power management rider. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.

In November 2021, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an under-recovery of approximately $80.6 million as of September 30, 2021. In December 2021, at the request of the MPSC, Entergy Mississippi submitted a proposal to mitigate the impact of rising fuel costs on customer bills during 2022. Entergy Mississippi proposed that the deferred fuel balance as of December 31, 2021, which was $121.9 million, be amortized over three years and that the MPSC authorize Entergy Mississippi to apply its weighted-average cost of capital as the carrying cost for the unamortized fuel balance. In January 2022 the MPSC approved the amortization of $100 million of the deferred fuel balance over two years and authorized Entergy Mississippi to apply its weighted-average cost of capital as the carrying cost for the unamortized fuel balance. The MPSC approved the proposed energy cost factor effective for February 2022 bills.

See “Complaints Against System Energy - System Energy Settlement with the MPSC” below for discussion of the settlement agreement filed with the FERC in June 2022. The settlement, which was approved by the FERC in November 2022, provided for a refund of $235 million from System Energy to Entergy Mississippi. In July 2022 the MPSC directed the disbursement of settlement proceeds, ordering Entergy Mississippi to provide a one-time $80 bill credit to each of its approximately 460,000 retail customers to be effective during the September 2022 billing cycle and to apply the remaining proceeds to Entergy Mississippi’s under-recovered deferred fuel balance. In accordance with the MPSC’s directive, Entergy Mississippi provided approximately $36.7 million in customer bill credits as a result of the settlement. In November 2022, Entergy Mississippi applied the remaining settlement proceeds in the amount of approximately $198.3 million to Entergy Mississippi’s under-recovered deferred fuel balance.

Entergy Mississippi had a deferred fuel balance of approximately $291.7 million under the energy cost recovery rider as of July 31, 2022, along with an over-recovery balance of $51.1 million under the power management rider. Without further action, Entergy Mississippi anticipated a year-end deferred fuel balance of approximately $200 million after application of a portion of the System Energy settlement proceeds, as discussed above. In September 2022, Entergy Mississippi filed for interim adjustments under both the energy cost recovery rider and the power management rider. Entergy Mississippi proposed five monthly incremental adjustments to the net energy cost factor designed to collect the under-recovered fuel balance as of July 31, 2022 and to reflect the recovery of a higher natural gas price. Entergy Mississippi also proposed five monthly incremental adjustments to the power management adjustment factor designed to flow through to customers the over-recovered power management rider balance as of July 31, 2022. In October 2022 the MPSC approved modified interim adjustments to Entergy Mississippi’s energy cost recovery rider and power management rider. The MPSC approved dividing the energy cost recovery rider interim adjustment into two components that would allow Entergy Mississippi to (1) recover a natural gas fuel rate that is better aligned with current prices; and (2) recover the estimated under-recovered deferred fuel balance as of September 30, 2022 over a period of 20 months. The MPSC approved six monthly incremental adjustments to the net energy cost factor designed to reflect the recovery of a higher natural gas price. The MPSC also approved six monthly incremental adjustments to the power management adjustment factor designed to flow through to customers the over-recovered power management rider balance. In accordance
with the order of the MPSC, Entergy Mississippi did not file an annual redetermination of the energy cost recovery rider or the power management rider in November 2022.

In June 2023 the MPSC approved the joint stipulation agreement between Entergy Mississippi and the Mississippi Public Utilities Staff for Entergy Mississippi’s 2023 formula rate plan filing. The stipulation directed Entergy Mississippi to make a compliance filing to revise its power management cost adjustment factor, to revise its grid modernization cost adjustment factor, and to include a revision to reduce the net energy cost factor to a level necessary to reflect an average natural gas price of $4.50 per MMBtu. The MPSC approved the compliance filing in June 2023, effective for July 2023 bills. See “Retail Rate Proceedings - Filings with the MPSC (Entergy Mississippi) - Retail Rates - 2023 Formula Rate Plan Filing” below for further discussion of the 2023 formula rate plan filing and the joint stipulation agreement.

In November 2023 Entergy Mississippi filed its annual redeterminations of the energy cost factor and the power management cost adjustment factor. The calculation of the annual factor for the energy cost recovery rider included a projected over-recovery balance of approximately $142 million at the end of January 2024. The calculation of the annual factor for the power management rider included a projected under-recovery of $47 million at the end of January 2024. In January 2024 the MPSC approved the proposed energy cost factor and the proposed power management cost factor effective for February 2024 bills.

In June 2024 the MPSC approved the joint stipulation agreement between Entergy Mississippi and the Mississippi Public Utilities Staff for Entergy Mississippi’s 2024 formula rate plan filing. The 2024 formula rate plan filing included the conclusion of the modified interim adjustments to Entergy Mississippi’s energy cost recovery rider and power management rider, which were approved in October 2022 and allowed Entergy Mississippi to recover certain under-collected fuel balances, effective for July 2024 bills. The stipulation provided for Entergy Mississippi to reduce its net energy cost factor. See “Retail Rate Proceedings - Filings with the MPSC (Entergy Mississippi) - Retail Rates - 2024 Formula Rate Plan Filing” below for further discussion of the 2024 formula rate plan filing and the joint stipulation agreement.

In November 2024, Entergy Mississippi filed its annual redeterminations of the energy cost factor and the power management cost adjustment factor. The calculation of the annual factor for the energy cost recovery rider included a projected over-recovery balance of approximately $144.6 million as of September 2024. The calculation of the annual factor for the power management rider included a projected under-recovery of $60.1 million as of September 2024. In January 2025 the MPSC approved a revised energy cost factor, effective for February 2025 bills, that did not reflect the fuel savings associated with Entergy Mississippi’s incremental increase in its share of capacity and energy in connection with Entergy Mississippi’s assumption of Entergy Louisiana’s entitlements to Grand Gulf capacity and energy, which was subject to the MPSC’s review at such time. In February 2025 the MPSC approved Entergy Mississippi’s notice of intent for Entergy Mississippi’s assumption of Entergy Louisiana’s entitlements to Grand Gulf capacity and energy, with associated fuel savings to be reflected in Entergy Mississippi’s energy cost recovery rider, effective for March 2025 bills. Additionally, in February 2025 the MPSC approved the proposed power management cost adjustment factor, effective for March 2025 bills.

Entergy New Orleans

Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.

Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.
Entergy Texas

Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, not recovered in base rates.  Historically, semi-annual revisions of the fixed fuel factor have been made in March and September based on the market price of natural gas and changes in fuel mix.  The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. In 2023 the Texas legislature modified the Texas Utilities Code to provide that material over- and under-recovered fuel balances are to be refunded or surcharged through interim fuel adjustments and that fuel reconciliations must be filed at least once every two years. Entergy Texas expects the PUCT to undertake a rulemaking to effectuate the new legislation in 2025.

In May 2022, Entergy Texas filed an application with the PUCT to implement an interim fuel surcharge to collect the cumulative under-recovery of approximately $51.7 million, including interest, of fuel and purchased power costs incurred from May 1, 2020 through December 31, 2021. The under-recovery balance was primarily attributable to the impacts of Winter Storm Uri, including historically high natural gas prices, partially offset by settlements received by Entergy Texas from MISO related to Hurricane Laura. Entergy Texas proposed that the interim fuel surcharge be assessed over a period of six months beginning with the first billing cycle after the PUCT issues a final order, but no later than the first billing cycle of September 2022. Also in May 2022, the PUCT referred the proceeding to the State Office of Administrative Hearings. In July 2022, Entergy Texas filed on behalf of the parties an unopposed settlement resolving all issues in the proceeding. In addition, Entergy Texas filed on behalf of the parties a motion to admit evidence, to approve interim rates as requested in the initial application, and to remand the proceeding to the PUCT to consider the unopposed settlement. In August 2022 the ALJ with the State Office of Administrative Hearings issued an order granting Entergy Texas’s motion, approving interim rates effective with the first billing cycle of September 2022, and remanding the case to the PUCT for final approval. The interim fuel surcharge was approved by the PUCT in January 2023.

In September 2022, Entergy Texas filed an application with the PUCT to reconcile its fuel and purchased power costs for the period from April 2019 through March 2022. During the reconciliation period, Entergy Texas incurred approximately $1.7 billion in eligible fuel and purchased power expenses, net of certain revenues credited to such expenses and other adjustments. As of the end of the reconciliation period, Entergy Texas’s cumulative under-recovery balance was approximately $103.1 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning April 2022, pending future surcharges or refunds as approved by the PUCT. In November 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In July 2023, Entergy Texas filed an unopposed settlement, supporting testimony, and an agreed motion to admit evidence and remand the proceeding to the PUCT. Pursuant to the unopposed settlement, Entergy Texas would receive no disallowance of fuel costs incurred over the three-year reconciliation period and retain $9.3 million in margins from off-system sales made during the reconciliation period, resulting in a cumulative under-recovery balance of approximately $99.7 million, including interest, as of the end of the reconciliation period. In July 2023 the ALJ with the State Office of Administrative Hearings granted the motion to admit evidence and remanded the proceeding to the PUCT for consideration of the unopposed settlement. The PUCT approved the settlement in September 2023.

In September 2024, Entergy Texas filed an application with the PUCT to reconcile its fuel and purchased power costs for the period from April 2022 through March 2024. During the reconciliation period, Entergy Texas incurred approximately $1.6 billion in eligible fuel and purchased power expenses to generate and purchase electricity to serve its customers, net of certain revenues credited to such expenses and other adjustments. Entergy Texas’s cumulative under-recovery balance for the reconciliation period was approximately $30 million, including interest, which Entergy Texas requested authority to carry over as part of the cumulative fuel balance for the subsequent reconciliation period beginning April 2024. In November 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 procedural schedule, with a hearing on the merits scheduled for May 2025. A PUCT decision is expected in third quarter 2025.
In December 2024, Entergy Texas filed an application with the PUCT to implement an interim fuel refund of $45.5 million, including interest. Entergy Texas proposed that the interim fuel refund be implemented over a three-month period beginning with the first billing cycle in February 2025 for residential and other small customers and through a one-time credit, or surcharge depending on historical usage for the respective customer, for certain transmission voltage level and seasonal agricultural customers in February 2025. Also in December 2024 the PUCT referred the proceeding to the State Office of Administrative Hearings. In January 2025 the ALJ with the State Office of Administrative Hearings issued an order approving the interim fuel refund consistent with Entergy Texas’s application and, because no hearing was requested in the proceeding, dismissing the case from the State Office of Administrative Hearings and the PUCT.
Retail Rate Proceedings

Filings with the APSC (Entergy Arkansas)

Retail Rates

2022 Formula Rate Plan Filing

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

2023 Formula Rate Plan Filing

In July 2023, Entergy Arkansas filed with the APSC its 2023 formula rate plan filing to set its formula rate for the 2024 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2024 and a netting adjustment for the historical year 2022. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2024 projected year was 8.11% resulting in a revenue deficiency of $80.5 million. The earned rate of return on common equity for the 2022 historical year was 7.29% resulting in a $49.8 million netting adjustment. The total proposed revenue change for the 2024 projected year and 2022 historical year netting adjustment was $130.3 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $88.6 million. The APSC general staff and intervenors filed their errors and objections in October 2023, proposing certain adjustments, including the APSC general staff’s update to annual filing year revenues which lowers the constraint to $87.7 million. Entergy Arkansas filed its rebuttal in October 2023. In October 2023, Entergy
Arkansas filed with the APSC a settlement agreement reached with other parties resolving all issues in the proceeding, none of which affected Entergy Arkansas’s requested recovery up to the constraint of $87.7 million. The settlement agreement provided for amortization of the approximately $39 million regulatory asset for costs associated with the COVID-19 pandemic over a 10-year period as well as recovery of $34.9 million related to the resolution of the 2016 and 2017 IRS audits from previous tax positions that are no longer uncertain, partially offset by $24.7 million in excess accumulated deferred income taxes from reductions in state income tax rates, each before consideration of their respective tax gross-up. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit and the State of Arkansas corporate income tax rate changes. In December 2023 the APSC approved the settlement agreement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2024.

2024 Formula Rate Plan Filing

In July 2024, Entergy Arkansas filed with the APSC its 2024 formula rate plan filing to set its formula rate for the 2025 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the 2025 projected year and a netting adjustment for the 2023 historical year. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2025 projected year was 8.43% resulting in a revenue deficiency of $69.5 million. The earned rate of return on common equity for the 2023 historical year was 7.48% resulting in a $33.1 million netting adjustment. The total proposed revenue change for the 2025 projected year and 2023 historical year netting adjustment is $102.6 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $82.6 million. The APSC general staff and intervenors filed their errors and objections in October 2024, proposing certain adjustments, including the APSC general staff’s update to annual filing year revenues that increases the constraint to $83.5 million. Entergy Arkansas filed its rebuttal in October 2024, and later in October 2024 the parties submitted a joint issues list and stipulations setting forth the disputed issues and the noncontested issues. In December 2024 the APSC approved the parties’ stipulations without modification, approved Entergy Arkansas’s adjustment with respect to storm costs, directed Entergy Arkansas to adjust its projected year distribution reliability capital closings, and deferred the recoverability of Entergy Arkansas’s opportunity sales legal fees until the next general rate case. Also in December 2024 the APSC approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2025. As a result of the proceeding, the total revenue change was $82.7 million, including a $63.7 million increase for the 2025 projected year and a $31.4 million netting adjustment for the 2023 historical year. In fourth quarter 2024, Entergy Arkansas recorded a regulatory asset of $15.5 million to reflect the amount of the 2023 historical year netting adjustment that it expects to collect from its customers during the 2025 rate effective period. Pursuant to the terms of the parties’ stipulations, Entergy Arkansas made a filing with the APSC in January 2025 to refund customers $30.1 million in excess accumulated deferred income taxes resulting from the reduction in the State of Arkansas’s income tax rate from 4.8% to 4.3% in 2024. Entergy Arkansas will make this refund over a 24-month period effective with the first billing cycle of February 2025.

Grand Gulf Credit Rider

In June 2024, Entergy Arkansas filed with the APSC a tariff to provide retail customers a credit resulting from the terms of the settlement agreement between Entergy Arkansas, System Energy, additional named Entergy parties, and the APSC pertaining to System Energy’s billings for wholesale sales of energy and capacity from the Grand Gulf nuclear plant. See “Complaints Against System Energy - System Energy Settlement with the APSC” below for discussion of the settlement. In July 2024 the APSC approved the tariff, under which Entergy Arkansas will refund to retail customers a total of $100.6 million. To date, Entergy Arkansas has refunded $92.3 million of the total through one-time bill credits during the August 2024 billing cycle and is finalizing plans for the refund of the remaining regulatory liability balance.
Filings with the LPSC (Entergy Louisiana)

Retail Rates - Electric

2020 Formula Rate Plan Filing

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

In November 2023 the LPSC approved a global settlement which resolved all outstanding issues related to the 2017, 2018, and 2019 formula rate plan filings and resolved certain issues with respect to the 2020 and 2021 formula rate plan filings. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” below for further discussion.

2021 Formula Rate Plan Filing

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

In November 2023 the LPSC approved a global settlement which resolved all outstanding issues related to the 2017, 2018, and 2019 formula rate plan filings and resolved certain issues with respect to the 2020 and 2021
formula rate plan filings. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” below for further discussion.

2022 Formula Rate Plan Filing

In May 2023, Entergy Louisiana filed its formula rate plan evaluation report for its 2022 calendar year operations. The 2022 test year evaluation report produced an earned return on common equity of 8.33%, requiring an approximately $70.7 million increase to base rider revenue. Due to a cap for the 2021 and 2022 test years, however, base rider formula rate plan revenues were only increased by approximately $4.9 million, resulting in a revenue deficiency of approximately $65.9 million and providing for prospective return on common equity opportunity of approximately 8.38%. Other changes in formula rate plan revenue driven by increases in capacity costs, primarily legacy capacity costs, additions eligible for recovery through the transmission recovery mechanism and distribution recovery mechanism, and higher sales during the test period were offset by reductions in net MISO costs as well as credits for FERC-ordered refunds. Also included in the 2022 test year distribution recovery mechanism revenue requirement was a $6 million credit relating to the distribution recovery mechanism performance accountability standards and requirements. In total, the net increase in formula rate plan revenues, including base formula rate plan revenues inside the formula rate plan bandwidth and subject to the cap, as well as other formula rate plan revenues outside of the bandwidth, was $85.2 million. In August 2023 the LPSC staff filed a list of objections/reservations, including outstanding issues from the test years 2017-2021 formula rate plan filings, the calculation of certain refunds from System Energy, and certain calculations relating to the tax reform adjustment mechanism. Subject to LPSC review, the resulting net increase in formula rate plan revenues of $85.2 million became effective for bills rendered during the first billing cycle of September 2023, subject to refund. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” below for further discussion.

2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request

In August 2023, Entergy Louisiana filed an application for approval of a regulatory blueprint necessary for it to strengthen the electric grid for the State of Louisiana, which contained a dual-path request to update rates through either: (1) extension of Entergy Louisiana’s current formula rate plan (with certain modifications) for three years (the Rate Mitigation Proposal), which is Entergy Louisiana’s recommended path; or (2) implementation of rates resulting from a cost-of-service study (the Rate Case path). The application complied with Entergy Louisiana’s previous formula rate plan extension order requiring that for Entergy Louisiana to obtain another extension of its formula rate plan that included a rate reset, Entergy Louisiana would need to submit a full cost-of-service rate case. Entergy Louisiana’s filing supported the need to extend Entergy Louisiana’s formula rate plan with credit supportive mechanisms needed to facilitate investment in the distribution, transmission, and generation functions.

In July 2024, Entergy Louisiana reached an agreement in principle with the LPSC staff and the intervenors in the proceeding and filed with the LPSC a joint motion to suspend the procedural schedule to allow for all parties to finalize a stipulated settlement agreement.

In August 2024, Entergy Louisiana and the LPSC staff jointly filed a global stipulated settlement agreement for consideration by the LPSC with key terms as follows:

•continuation of the formula rate plan for 2024-2026 (test years 2023-2025);
•a base formula rate plan revenue increase of $120 million for test year 2023, effective for rates beginning September 2024;
•a $140 million cumulative cap on base formula rate plan revenue increases, if needed, for test years 2024 and 2025, excluding outside the bandwidth items;
•$184 million of customer rate credits to be given over two years, including increasing customer sharing of income tax benefits resulting from the 2016-2018 IRS audit, to resolve any remaining disputed issues stemming from formula rate plan test years prior to test year 2023, including but not limited to the investigation into Entergy Services costs billed to Entergy Louisiana. As discussed in Note 3 to the financial statements, a $38 million regulatory liability was recorded in 2023 in connection with the 2016-2018 IRS audit;
•$75.5 million of customer rate credits, as provided for in the System Energy global settlement, to be credited over three years subject to and conditioned upon FERC approval of the System Energy global settlement, which was approved in November 2024. See “Complaints Against System Energy – System Energy Settlement with the LPSC” below for further details of the System Energy global settlement;
•$5.8 million of customer rate credits provided for in the Entergy Louisiana formula rate plan global settlement agreement approved by the LPSC in November 2023 credited over one year. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement;
•an increase in the allowed midpoint return on common equity from 9.5% to 9.7%, with a bandwidth of 40 basis points above and below the midpoint, for the extended term of the formula rate plan, except that for test year 2023 in which the authorized return on common equity shall have no bearing on the change in base formula rate plan revenue described above and, for test year 2024, any earnings above the authorized return on common equity shall be returned to customers through a credit;
•an increase in nuclear depreciation rates by $15 million in each of the 2023, 2024, and 2025 test years outside of the formula rate plan bandwidth calculation; and
•for the transmission recovery mechanism and the distribution recovery mechanism, no change to the existing floors, but the caps for both would be $350 million for test year 2023, $375 million for test year 2024, and $400 million for test year 2025. Transmission projects filed with the LPSC will be exempt from the transmission recovery mechanism cap.

The global stipulated settlement agreement was unanimously approved by the LPSC in August 2024 and an order was issued by the LPSC in September 2024 reflecting the approval of the settlement.

Based on the July 2024 agreement in principle, in second quarter 2024 Entergy Louisiana recorded expenses of $151 million ($112 million net-of-tax) primarily consisting of regulatory charges to reflect the effects of the agreement in principle.

Formula Rate Plan Global Settlement

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

2023 Formula Rate Plan Filing

In August 2024, pursuant to the global stipulated settlement agreement, Entergy Louisiana filed its formula rate plan evaluation report for its 2023 calendar year operations. Consistent with the global stipulated settlement agreement, the filing reflected a 9.7% allowed return on common equity with a bandwidth of 40 basis points above and below the midpoint. For the 2023 test year, however, the bandwidth provisions of the formula rate plan were
temporarily suspended and, pursuant to the terms of the global stipulated settlement agreement, Entergy Louisiana implemented the September 2024 formula rate plan rate adjustments effective with the first billing cycle of September 2024. Those adjustments included a $120 million increase in base rider formula rate plan revenue and a $101.8 million one-time incremental net decrease consistent with the terms of the global stipulated settlement. The formula rate plan rate adjustments reflected in the evaluation report also include a redetermination of the transmission recovery mechanism, the distribution recovery mechanism, the additional capacity mechanism, the tax adjustment mechanism, the MISO cost recovery mechanism, and other one-time adjustments. In January 2025, Entergy Louisiana and the LPSC filed a joint report indicating that no disputed issues remained in the proceeding and requesting that the LPSC issue an order accepting Entergy Louisiana’s evaluation report and, ultimately, resolving this matter. Entergy Louisiana expects a decision on the joint report in first quarter 2025.

Investigation of Costs Billed by Entergy Services

In November 2018 the LPSC issued a notice of proceeding initiating an investigation into costs incurred by Entergy Services that are included in the retail rates of Entergy Louisiana. As stated in the notice of proceeding, the LPSC observed an increase in capital construction-related costs incurred by Entergy Services. Discovery was issued and included efforts to seek highly detailed information on a broad range of matters unrelated to the scope of the audit. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” above for further discussion.

COVID-19 Orders

In April 2020 the LPSC issued an order authorizing utilities to record as a regulatory asset expenses incurred from the suspension of disconnections and collection of late fees imposed by LPSC orders associated with the COVID-19 pandemic. In April 2023, Entergy Louisiana filed an application proposing to utilize approximately $1.6 billion in certain low interest debt to generate earnings to apply toward the reduction of the COVID-19 regulatory asset, as well as to conduct additional outside right-of-way vegetation management activities and fund the minor storm reserve account. In that filing, Entergy Louisiana proposed to delay repayment of certain shorter-term first mortgage bonds that were issued to finance storm restoration costs until the costs could be securitized, and to invest the funds that otherwise would be used to repay those bonds in the money pool to take advantage of the spread between prevailing interest rates on investments in the money pool and the interest rates on the bonds. The LPSC approved Entergy Louisiana’s requested relief in June 2023. In November 2024, Entergy Louisiana submitted a filing to the LPSC requesting that the LPSC review Entergy Louisiana’s computation of the COVID-19 regulatory asset as well as Entergy Louisiana’s proposal to offset the regulatory asset against the interest earned on the short-term debt funds, resulting in no increased costs to customers. At the time of the filing, Entergy Louisiana had a regulatory asset of $47.8 million for costs associated with the COVID-19 pandemic. As of December 31, 2024, Entergy Louisiana had a regulatory liability of $48.9 million for the deferred earnings related to the approximately $1.6 billion in low interest debt, which had been fully repaid by August 2024. In granting Entergy Louisiana’s requested relief in June 2023, the LPSC ordered that any amount of earnings exceeding the amount of the COVID-19 regulatory asset be transferred to Entergy Louisiana’s storm reserve escrow account.

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 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.

Filings with the MPSC (Entergy Mississippi)

Retail Rates

2022 Formula Rate Plan Filing

In March 2022, Entergy Mississippi submitted its formula rate plan 2022 test year filing and 2021 look-back filing showing Entergy Mississippi’s earned return for the historical 2021 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2022 calendar year to be below the formula rate plan bandwidth. The 2022 test year filing showed a $69 million rate increase was necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.70% return on rate base, within the formula rate plan bandwidth. The change in formula rate plan revenues, however, was capped at 4% of retail revenues, which equated to a revenue change of $48.6 million. The 2021 look-back filing compared actual 2021 results to the approved benchmark return on rate base and reflected the need for a $34.5 million interim increase in formula rate plan revenues. In fourth quarter 2021, Entergy Mississippi recorded a regulatory asset of $19 million to reflect the then-current estimate in connection with the look-back feature of the formula rate plan. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $24.3 million interim rate increase, reflecting a cap equal to 2% of 2021 retail revenues, effective in April 2022. With the implementation of the interim formula rate plan rates, Entergy Mississippi began recovery of the bad debt expense deferral resulting from the COVID-19 pandemic over a three-year period.

In June 2022, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed the 2022 test year filing that resulted in a total rate increase of $48.6 million. Pursuant to the joint stipulation, Entergy Mississippi’s 2021 look-back filing reflected an earned return on rate base of 5.99% in calendar year 2021, which was below the look-back bandwidth, resulting in a $34.3 million increase in the formula rate plan revenues on an interim basis through June 2023. In July 2022 the MPSC approved the joint stipulation with rates effective in August 2022. In July 2022, Entergy Mississippi recorded regulatory credits of $22.6 million to reflect the effects of the joint stipulation.
In July 2022 the MPSC directed Entergy Mississippi to flow $14.1 million of the power management rider over-recovery balance to customers beginning in August 2022 through December 2022 to mitigate the bill impact of the increase in formula rate plan revenues.

2023 Formula Rate Plan Filing

In March 2023, Entergy Mississippi submitted its formula rate plan 2023 test year filing and 2022 look-back filing showing Entergy Mississippi’s earned return on rate base for the historical 2022 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2023 calendar year to be below the formula rate plan bandwidth. The 2023 test year filing showed a $39.8 million rate increase was necessary to reset Entergy Mississippi’s earned return on rate base to the specified point of adjustment of 6.67%, within the formula rate plan bandwidth. The 2022 look-back filing compared actual 2022 results to the approved benchmark return on rate base and reflected the need for a $19.8 million temporary increase in formula rate plan revenues, including the refund of a $1.3 million over-recovery resulting from the demand-side management costs true-up for 2022. In fourth quarter 2022, Entergy Mississippi recorded a regulatory asset of $18.2 million in connection with the look-back feature of the formula rate plan to reflect that the 2022 estimated earned return was below the formula rate plan bandwidth. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $27.9 million interim rate increase, reflecting a cap equal to 2% of 2022 retail revenues, effective in April 2023.

In May 2023, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed a 2023 test year filing resulting in a total revenue increase of $26.5 million for 2023. Pursuant to the joint stipulation, Entergy Mississippi’s 2022 look-back filing reflected an earned return on rate base of 6.10% in calendar year 2022, which was below the look-back bandwidth, resulting in a $19.0 million increase in the formula rate plan revenues on an interim basis through June 2024. Entergy Mississippi recorded a regulatory credit of $0.8 million in June 2023 to reflect the increase in the look-back regulatory asset. In addition, certain long-term service agreement and conductor handling costs were authorized for realignment from the formula rate plan to the annual power management and grid modernization riders effective January 2023, resulting in regulatory credits recorded in June 2023 of $4.1 million and $4.3 million, respectively. Also, the amortization of Entergy Mississippi’s COVID-19 bad debt expense deferral was suspended for calendar year 2023, but resumed in July 2024. In June 2023 the MPSC approved the joint stipulation with rates effective in July 2023.

2024 Formula Rate Plan Filing

In March 2024, Entergy Mississippi submitted its formula rate plan 2024 test year filing and 2023 look-back filing showing Entergy Mississippi’s earned return on rate base for the historical 2023 calendar year to be within the formula rate plan bandwidth and projected earned return for the 2024 calendar year to be below the formula rate plan bandwidth. The 2024 test year filing showed a $63.4 million rate increase was necessary to reset Entergy Mississippi’s earned return on rate base to the specified point of adjustment of 7.10%, within the formula rate plan bandwidth. The 2023 look-back filing compared actual 2023 results to the approved benchmark return on rate base and reflected no change in formula rate plan revenues. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $32.6 million interim rate increase, reflecting a cap equal to 2% of 2023 retail revenues, effective April 2024.

In December 2014 the MPSC ordered Entergy Mississippi to file an updated depreciation study at least once every four years. Pursuant to this order and Entergy Mississippi’s filing cycle, Entergy Mississippi would have filed an updated depreciation report with its formula rate plan filing in 2023. However, in July 2022 the MPSC directed Entergy Mississippi to file its next depreciation study in connection with its 2024 formula rate plan filing notwithstanding the MPSC’s prior order. Accordingly, Entergy Mississippi filed a depreciation study in February 2024. The study showed a need for an increase in annual depreciation expense of $55.2 million. The calculated increase in annual depreciation expense was excluded from Entergy Mississippi’s 2024 formula rate plan revenue increase request because the MPSC had not yet approved the proposed depreciation rates.
In June 2024, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed the 2024 test year filing, with the exception of immaterial adjustments to certain operation and maintenance expenses. After performance adjustments, the formula rate plan reflected an earned return on rate base of 6.08% for calendar year 2024, which resulted in a total revenue increase of $64.6 million for 2024. The joint stipulation also recommended approval of a revised customer charge of $31.82 per month for residential customers and $53.10 per month for general service customers. Pursuant to the stipulation, Entergy Mississippi’s 2023 look-back filing reflected an earned return on rate base of 6.81%, resulting in an increase of $0.3 million in the formula rate plan revenues for 2023. Finally, the stipulation recommended approval of Entergy Mississippi’s proposed depreciation rates with those rates to be implemented upon request and approval at a later date. In June 2024 the MPSC approved the joint stipulation with rates effective in July 2024. The approval also included a reduction to the energy cost factor, resulting in a net bill decrease for a typical residential customer using 1,000 kWh per month. Also in June 2024, Entergy Mississippi recorded regulatory credits of $7.3 million to reflect the difference between interim rates placed in effect in April 2024 and the rates reflected in the joint stipulation.

In May 2024, Entergy Mississippi received approval from the MPSC for formula rate plan revisions that were necessary for Entergy Mississippi to comply with state legislation passed in January 2024. The legislation allows Entergy Mississippi to make interim rate adjustments 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 filed the first of its annual interim facilities rate adjustment reports in May 2024 to recover approximately $8.7 million of these costs over a six-month period with rates effective beginning in July 2024. Entergy Mississippi filed its second annual interim facilities rate adjustment report in December 2024 to recover approximately $46.7 million of these costs over a 12-month period with rates effective beginning in January 2025.

Grand Gulf Capacity Filing

In September 2024, Entergy Mississippi filed a notice of intent with the MPSC to implement revisions to its unit power cost recovery rider that would allow Entergy Mississippi to recover the first year of costs associated with the transfer of Entergy Louisiana’s entitlements to Grand Gulf capacity and energy, which consists of Energy Louisiana’s interest in and purchases of Grand Gulf capacity and energy under the revised rider schedule, effective by January 1, 2025. This notice filing related to the divestiture of Entergy Louisiana’s 14% share of Grand Gulf capacity and energy under the Unit Power Sales Agreement and 2.43% share of capacity and energy from Entergy Arkansas under the MSS-4 replacement tariff. This divestiture is being effectuated initially through Entergy Mississippi’s purchases from Entergy Louisiana pursuant to a PPA governed by the MSS-4 replacement tariff, a tariff governing the sales of energy and capacity among the Utility operating companies as described in the System Energy global settlement with the LPSC and Entergy Louisiana. The MSS-4 replacement PPA to effectuate this divestiture was approved by the FERC in November 2024. In February 2025 the MPSC approved Entergy Mississippi’s notice of intent, finding that it was just and reasonable for Entergy Mississippi to obtain Entergy Louisiana’s entitlements to Grand Gulf capacity and energy and that Entergy Mississippi should be allowed to recover the costs associated with the transfer of such entitlements to Grand Gulf capacity and energy, as described above. The MPSC approved the MSS-4 replacement PPA, effective as of January 1, 2025. See “Complaints Against System Energy – System Energy Settlement with the LPSC” below for further details of the System Energy global settlement with the LPSC and Note 8 to the financial statements for discussion of the Unit Power Sales Agreement.

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.

Filings with the City Council (Entergy New Orleans)

Retail Rates

2022 Formula Rate Plan Filing

In April 2022, Entergy New Orleans submitted to the City Council its formula rate plan 2021 test year filing. The 2021 test year evaluation report, subsequently updated in a July 2022 filing, produced an earned return on equity of 6.88% compared to the authorized return on equity of 9.35%. Entergy New Orleans sought approval of a $42.1 million rate increase based on the formula set by the City Council in the 2018 rate case. The formula resulted in an increase in authorized electric revenues of $34.1 million and an increase in authorized gas revenues of $3.3 million. Entergy New Orleans also sought to commence collecting $4.7 million in electric revenues that were previously approved by the City Council for collection through the formula rate plan. In July 2022 the City Council’s advisors issued a report seeking a reduction to Entergy New Orleans’s proposed increase of approximately $17.1 million in total for electric and gas revenues. Effective with the first billing cycle of September 2022, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council including adjustments filed in the City Council’s advisors’ report, per the approved process for formula rate plan implementation. The total formula rate plan increase implemented was $24.7 million, which includes an increase of $18.2 million in electric revenues, $4.7 million in previously approved electric revenues, and an increase of $1.8 million in gas revenues. Additionally, credits of $13.9 million funded by certain regulatory liabilities currently held by Entergy New Orleans for customers were issued over an eight-month period beginning September 2022.

2023 Formula Rate Plan Filing

In April 2023, Entergy New Orleans submitted to the City Council its formula rate plan 2022 test year filing. The 2022 test year evaluation report produced an electric earned return on equity of 7.34% and a gas earned return on equity of 3.52% compared to the authorized return on equity for each of 9.35%. Entergy New Orleans sought approval of a $25.6 million rate increase based on the formula set by the City Council in the 2018 rate case. The formula would result in an increase in authorized electric revenues of $17.4 million and an increase in authorized gas revenues of $8.2 million. Entergy New Orleans also sought to commence collecting $3.4 million in electric revenues that were previously approved by the City Council for collection through the formula rate plan. In July 2023, Entergy New Orleans filed a report to decrease its requested formula rate plan revenues by approximately $0.5 million to account for minor errors discovered after the filing. The City Council advisors issued a report seeking a reduction in the requested formula rate plan revenues of approximately $8.3 million, combined for electric and gas, due to alleged errors. The City Council advisors proposed additional rate mitigation in the amount of $12 million through offsets to the formula rate plan rate increase by certain regulatory liabilities. In September 2023 the City Council approved an agreement to settle the 2023 formula rate plan filing. Effective with the first billing cycle of September 2023, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council, per the approved process for formula rate plan implementation. The agreement provides for a total increase in electric revenues of $10.5 million and a total increase in gas revenues of
$6.9 million. The agreement also provides for a minor storm accrual of $0.5 million per year and the distribution of $8.9 million of currently held customer credits to implement the City Council advisors’ mitigation recommendations.

Request for Extension and Modification of Formula Rate Plan

In September 2023, Entergy New Orleans filed a motion seeking City Council approval of a three-year extension of Entergy New Orleans’s electric and gas formula rate plans. In October 2023 the City Council granted Entergy New Orleans’s request for an extension, subject to minor modifications which included a 55% equity ratio for rate setting purposes.

2024 Formula Rate Plan Filing

In April 2024, Entergy New Orleans submitted to the City Council its formula rate plan 2023 test year filing. Without the requested rate change in 2024, the 2023 test year evaluation report produced an electric earned return on equity of 8.66% and a gas earned return on equity of 5.87% compared to the authorized return on equity for each of 9.35%. Entergy New Orleans sought approval of a $12.6 million rate increase based on the formula set by the City Council in the 2018 rate case and approved again by the City Council in 2023. The formula would result in an increase in authorized electric revenues of $7.0 million and an increase in authorized gas revenues of $5.6 million. Following City Council review, the City Council’s advisors issued a report in July 2024 seeking a reduction in Entergy New Orleans’s requested formula rate plan revenues in an aggregate amount of approximately $1.6 million for electric and gas together due to alleged errors. Effective with the first billing cycle of September 2024, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council, per the approved process for formula rate plan implementation. The total formula rate plan increase implemented was $11.2 million, which includes an increase of $5.8 million in electric revenues and an increase of $5.4 million in gas revenues.

Filings with the PUCT and Texas Cities (Entergy Texas)

Retail Rates

2022 Base Rate Case

In July 2022, Entergy Texas filed a base rate case with the PUCT seeking a net increase in base rates of approximately $131.4 million. The base rate case was based on a 12-month test year ending December 31, 2021. Key drivers of the requested increase were changes in depreciation rates as the result of a depreciation study and an increase in the return on equity. In addition, Entergy Texas included capital additions placed into service for the period of January 1, 2018 through December 31, 2021, including those additions reflected in the then-effective distribution and transmission cost recovery factor riders and the generation cost recovery rider, all of which were reset to zero in June 2023 as a result of this proceeding. In July 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In October 2022 intervenors filed direct testimony challenging and supporting various aspects of Entergy Texas’s rate case application. The key issues addressed included the appropriate return on equity, generation plant deactivations, depreciation rates, and proposed tariffs related to electric vehicles. In November 2022 the PUCT staff filed direct testimony addressing a similar set of issues and recommending a reduction of $50.7 million to Entergy Texas’s overall cost of service associated with the requested net increase in base rates of approximately $131.4 million. Entergy Texas filed rebuttal testimony in November 2022.

In May 2023, Entergy Texas filed on behalf of the parties an unopposed settlement resolving all issues in the proceeding, except for issues related to electric vehicle charging infrastructure which were eventually severed to a separate proceeding and resolved in October 2024, and Entergy Texas filed an agreed motion for interim rates, subject to refund or surcharge to the extent that the interim rates differ from the final approved rates. The unopposed settlement reflected a net base rate increase to be effective and relate back to December 2022 of
$54 million, exclusive of, and incremental to, the costs being realigned from the distribution and transmission cost recovery factor riders and the generation cost recovery rider and $4.8 million of rate case expenses to be recovered through a rider over a period of 36 months. The net base rate increase of $54 million includes updated depreciation rates and a total annual revenue requirement of $14.5 million for the accrual of a self-insured storm reserve and the recovery of the regulatory assets for the pension and postretirement benefits expense deferral, costs associated with the COVID-19 pandemic, and retired non-advanced metering system electric meters. In May 2023 the ALJ with the State Office of Administrative Hearings granted the motion for interim rates, which became effective in June 2023. Additionally, the ALJ remanded the proceeding to the PUCT to consider the settlement. In August 2023 the PUCT issued an order approving the unopposed settlement. Concurrently, Entergy Texas recorded the reversal of $21.9 million of regulatory liabilities to reflect the recognition of certain receipts by Entergy Texas under affiliated PPAs that have been resolved.

Following the PUCT’s approval of the unopposed settlement in August 2023, Entergy Texas recorded a regulatory liability of $10.3 million, which reflected the net effects of higher depreciation and amortizations for the relate back period, partially offset by the relate back of base rate revenues that would have been collected had the approved rates been in effect for the period from December 2022 through June 2023, the date the new base rates were implemented on an interim basis. In October 2023, Entergy Texas filed a relate back surcharge rider to collect over six months beginning in January 2024 an additional approximately $24.6 million, which was the revenue requirement associated with the relate back of rates from December 2022 through June 2023, including carrying costs, as authorized by the PUCT’s August 2023 order. In November 2023, Entergy Texas filed an amended relate back surcharge rider to collect approximately $24.1 million based on a revised carrying cost rate. The amended relate back surcharge rider was approved by the PUCT in December 2023. The higher depreciation and amortizations for the relate back period were also recognized over the six months beginning in January 2024, resulting in no effect on net income from the collection of the relate back surcharge rider.

Distribution Cost Recovery Factor (DCRF) Rider

In June 2024, Entergy Texas filed with the PUCT a request to set a new DCRF rider. The new rider was designed to collect from Entergy Texas’s retail customers approximately $40.3 million annually based on its capital invested in distribution between January 1, 2022 and March 31, 2024. In September 2024 the PUCT approved the DCRF rider, consistent with Entergy Texas’s as-filed request, and rates became effective with the first billing cycle in October 2024.

In September 2024, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $48.9 million annually, or $8.6 million in incremental annual revenues beyond Entergy Texas’s then-effective DCRF rider based on its capital invested in distribution between April 1, 2024 and June 30, 2024. In December 2024, Entergy Texas filed an errata to revise its DCRF application for minor corrections, which decreased the requested annual revenue requirement to $48.5 million. The amended request represented an incremental increase of $8.2 million in annual revenues beyond Entergy Texas’s then-effective DCRF rider. Also in December 2024 the PUCT approved the DCRF rider, consistent with Entergy Texas’s filed errata, and rates became effective on December 20, 2024.

Transmission Cost Recovery Factor (TCRF) Rider

In December 2018, Entergy Texas filed with the PUCT a request to set a new TCRF rider. The new TCRF rider was designed to collect approximately $2.7 million annually from Entergy Texas’s retail customers based on its capital invested in transmission between January 1, 2018 and September 30, 2018. In April 2019 parties filed testimony proposing a load growth adjustment, which would fully offset Entergy Texas’s proposed TCRF revenue requirement. In July 2019 the PUCT granted Entergy Texas’s application as filed to begin recovery of the requested $2.7 million annual revenue requirement, rejecting opposing parties’ proposed adjustment; however, the PUCT found that the question of prudence of the actual investment costs should be determined in Entergy Texas’s next rate case similar to the procedure used for the costs recovered through the DCRF rider. In October 2019 the PUCT
issued an order on a motion for rehearing, clarifying and affirming its prior order granting Entergy Texas’s application as filed. Also in October 2019 a second motion for rehearing was filed, and Entergy Texas filed a response in opposition to the motion. The second motion for rehearing was overruled by operation of law. In December 2019, Texas Industrial Energy Consumers filed an appeal to the PUCT order in district court alleging that the PUCT erred in declining to apply a load growth adjustment.

In October 2021, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $66.1 million annually, or $15.1 million in incremental annual revenues beyond Entergy Texas’s then-effective TCRF rider based on its capital invested in transmission between September 1, 2020 and July 31, 2021 and changes in approved transmission charges. In January 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In February 2022 the parties filed an unopposed settlement recommending that Entergy Texas be allowed to collect its full requested TCRF revenue requirement with interim rates effective March 2022. In February 2022 the ALJ granted the motion for interim rates, admitted evidence, and remanded the case to the PUCT for consideration of a final order at a future open meeting. In June 2022 the PUCT issued an order approving the settlement.

In October 2024, Entergy Texas filed with the PUCT a request to amend its TCRF rider, which was previously reset to zero in June 2023 as a result of the 2022 base rate case. The proposed rider is designed to collect from Entergy Texas’s retail customers approximately $9.7 million annually based on its capital invested in transmission between January 1, 2022 and June 30, 2024 and changes in other transmission charges. In December 2024 the PUCT staff filed a recommendation that the PUCT approve Entergy Texas’s as-filed application. In February 2025 the PUCT staff issued a proposed order that, if approved by the PUCT, would approve Entergy Texas’s TCRF rider as filed.

Generation Cost Recovery Rider

In October 2020, Entergy Texas filed an application to establish a generation cost recovery rider to begin recovering a return of and on its generation capital investment in the Montgomery County Power Station. Entergy Texas filed an unopposed settlement agreement in December 2020, and the PUCT approved the generation cost recovery rider settlement rates on an interim basis in January 2021. In March 2021, Entergy Texas filed to update its generation cost recovery rider, and an unopposed settlement agreement filed by Entergy Texas on behalf of the parties in October 2021 was approved by the PUCT in January 2022. In February 2022, Entergy Texas filed a relate-back rider to collect over five months an additional approximately $5 million, which was the difference between the interim revenue requirement approved in January 2021 and the revenue requirement approved in January 2022 reflecting Entergy Texas’s full generation capital investment and ownership in Montgomery County Power Station on January 1, 2021, plus carrying costs from January 2021 through January 2022 when the updated revenue requirement took effect. The PUCT approved the relate-back rider consistent with Entergy Texas’s as-filed request, and rates became effective over a five-month period, in August 2022.

In December 2020, Entergy Texas also filed an application to amend its generation cost recovery rider to reflect its acquisition of the Hardin County Peaking Facility, which closed in June 2021. Because Hardin was to be acquired in the future, the initial generation cost recovery rider rates proposed in the application represented no change from the generation cost recovery rider rates established in Entergy Texas’s previous generation cost recovery rider proceeding. In July 2021 the PUCT issued an order approving the application. In August 2021, Entergy Texas filed an update application to recover its actual investment in the acquisition of the Hardin County Peaking Facility, and in January 2022, Entergy Texas filed an update to its application to align the requested revenue requirement with the terms of the generation cost recovery rider settlement approved by the PUCT in January 2022. In April 2022, Entergy Texas filed on behalf of the parties a unanimous settlement agreement that would adjust its generation cost recovery rider to recover an annual revenue requirement of approximately $92.8 million, which was $4.5 million in incremental annual revenue above the revenue requirement approved in January 2022 described above and related to Entergy Texas’s investment in the Montgomery County Power Station. The PUCT approved the settlement agreement and rates became effective in August 2022. In September 2022,
Entergy Texas filed a relate-back rider designed to collect over three months an additional approximately $5.7 million, which is the revenue requirement, plus carrying costs, associated with Entergy Texas’s acquisition of Hardin County Peaking Facility from June 2021 through August 2022 when the updated revenue requirement took effect. In April 2023 the PUCT approved Entergy Texas’s as-filed request with rates effective over three months beginning in May 2023.
Entergy Arkansas Opportunity Sales Proceeding

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

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

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

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

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

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

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

In October 2018 the FERC issued an order addressing the ALJ’s July 2017 initial decision. The FERC reversed the ALJ’s decision to cap the reduction in Entergy Arkansas’s payment to account for the increased bandwidth payments that Entergy Arkansas made to the other operating companies. The FERC also reversed the ALJ’s decision that Grand Gulf sales from January through September 2000 should be included in the calculation of Entergy Arkansas’s payment. The FERC affirmed on other grounds the ALJ’s rejection of the LPSC’s claim that certain joint account sales should be accounted for as part of the calculation of Entergy Arkansas’s payment. In November 2018 the LPSC requested rehearing of the FERC’s October 2018 decision. In December 2019 the FERC denied the LPSC’s request for rehearing. In January 2020 the LPSC appealed the December 2019 decision to the D.C. Circuit.
In December 2018, Entergy made a compliance filing in response to the FERC’s October 2018 order. The compliance filing provided a final calculation of Entergy Arkansas’s payments to the other Utility operating companies, including interest. No protests were filed in response to the December 2018 compliance filing. Refunds and interest in the following amounts were paid by Entergy Arkansas to the other operating companies in December 2018:
 Total refunds including interest
Payment/(Receipt)
 (In Millions)
PrincipalInterestTotal
Entergy Arkansas$68$67$135
Entergy Louisiana($30)($29)($59)
Entergy Mississippi($18)($18)($36)
Entergy New Orleans($3)($4)($7)
Entergy Texas($17)($16)($33)

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

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

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

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

In July 2020 the APSC issued a decision finding that Entergy Arkansas’s application is not in the public interest. The order also directed Entergy Arkansas to refund to its retail customers within 30 days of the order the FERC-determined over-collection of $13.7 million, plus interest, associated with a recalculated bandwidth remedy. In addition to these primary findings, the order also denied the Attorney General’s request for Entergy Arkansas to prepare a compliance filing detailing all of the retail impacts from the opportunity sales and denied a request by the Arkansas Electric Energy Consumers to recalculate all costs using the revised responsibility ratio. Entergy Arkansas filed a motion for temporary stay of the 30-day requirement to allow Entergy Arkansas a reasonable opportunity to seek rehearing of the APSC order, but in July 2020 the APSC denied Entergy Arkansas’s request for a stay and directed Entergy Arkansas to refund to its retail customers the component of the total FERC-determined opportunity sales payment that was associated with increased bandwidth remedy payments of $13.7 million, plus interest. The refunds were issued in the August 2020 billing cycle. While the APSC denied Entergy Arkansas’s stay request, Entergy Arkansas believes its actions were prudent and, therefore, the costs, including the $13.7 million, plus interest, are recoverable. In July 2020, Entergy Arkansas requested rehearing of the APSC order, which rehearing was denied by the APSC in August 2020. In September 2020, Entergy Arkansas filed a complaint in the U.S. District Court for the Eastern District of Arkansas challenging the APSC’s order denying Entergy Arkansas’s request to recover the costs of these payments. In October 2020 the APSC filed a motion to dismiss Entergy Arkansas’s complaint, to which Entergy Arkansas responded. Also in December 2020, Entergy Arkansas and the APSC held a pre-trial conference, and filed a report with the court in January 2021. The court held a hearing in February 2021 regarding issues addressed in the pre-trial conference report, and in June 2021 the court stayed all discovery until it rules on pending motions, after which the court will issue an amended schedule if necessary. In March 2022 the court denied the APSC’s motion to dismiss, and, in April 2022, issued a scheduling order including a trial date in February 2023. In June 2022, Entergy Arkansas filed a motion asserting that it is entitled to summary judgment because Entergy Arkansas’s position that the APSC’s order is pre-empted by the filed rate doctrine and violates the Dormant Commerce Clause is premised on facts that are not subject to genuine dispute. In July 2022, Arkansas Electric Energy Consumers, Inc., an industrial customer association, filed a motion to intervene and to hold Entergy Arkansas’s motion for summary judgment in abeyance pending a ruling on the motion to intervene. Entergy Arkansas filed a consolidated opposition to both motions. In August 2022 the APSC filed a motion for summary judgment arguing that there is no genuine issue as to any material fact and the APSC is entitled to judgment as a matter of law. In September 2022, Entergy Arkansas filed an opposition to the motion. In October 2022 the APSC filed a motion asking the court to hold further proceedings in abeyance pending a decision on the motions for summary judgment filed by Entergy Arkansas and the APSC. Also in October 2022, Entergy Arkansas filed an opposition to the motion, and the APSC filed a reply in support of its motion for summary judgment. In January 2023 the judge assigned to the case, on her own motion, identified facts that may present a conflict and recused herself; a new judge was assigned to the case, but he also recused due to a conflict. The case again was reassigned to a new judge. In January 2023 the court denied all pending motions (including those described above) except for a motion by the APSC to exclude certain testimony and further ruled that the matter would proceed to trial. In January 2023, Arkansas Electric Energy Consumers, Inc. filed a notice of appeal of the court’s order denying its motion to intervene to the United States Court of Appeals for the Eighth Circuit and a motion with the district court to stay the proceedings pending the appeal, which was denied. In February 2023, Arkansas Electric Energy Consumers, Inc. filed a motion with the United States Court of Appeals for the Eighth Circuit to stay the proceedings pending the appeal, which also was denied. The trial was held in February 2023. Following the trial, Entergy Arkansas filed a motion with the United States Court of Appeals for the Eighth Circuit to expedite the appeal filed by Arkansas Electric Energy Consumers, Inc. The United States Court of Appeals for
the Eighth Circuit granted Entergy Arkansas’s request, and oral arguments were held in June 2023. In August 2023 the United States Court of Appeals for the Eighth Circuit affirmed the order of the court denying Arkansas Electric Energy Consumers, Inc.’s motion to intervene.

In March 2024 the U.S. District Court for the Eastern District of Arkansas issued a judgment in favor of the APSC and against Entergy Arkansas. In March 2024 Entergy Arkansas filed a notice of appeal and a motion to expedite oral arguments with the United States Court of Appeals for the Eighth Circuit and the court granted the motion to expedite. Briefing to the United States Court of Appeals for the Eighth Circuit concluded in July 2024 and oral arguments concluded in September 2024. As a result of the adverse decision by the U.S. District Court for the Eastern District of Arkansas, Entergy Arkansas concluded that it could no longer support the recognition of its $131.8 million regulatory asset reflecting the previously-expected recovery of a portion of the costs at issue in the opportunity sales proceeding and recorded a $131.8 million ($99.1 million net-of-tax) charge to earnings in first quarter 2024. In December 2024 the United States Court of Appeals for the Eighth Circuit affirmed the decision of the U.S. District Court for the Eastern District of Arkansas, and Entergy Arkansas filed a petition for rehearing en banc. In January 2025 the United States Court of Appeals for the Eighth Circuit denied Entergy Arkansas’s petition. Entergy Arkansas is evaluating a petition for certiorari with the United States Supreme Court.
MSS-4 Replacement Tariff – Net Operating Loss Carryforward Proceeding

In January 2021, pursuant to section 205 of the Federal Power Act, Entergy Services filed an amendment to the MSS-4 replacement tariff, a tariff governing the sales of energy and capacity among the Utility operating companies, in order to provide for the inclusion of specified accumulated deferred income taxes, including net operating loss carryforward accumulated deferred income taxes (NOLC ADIT), in the rate for sales of energy among the Utility operating companies on a prospective basis. In March 2021, the FERC accepted the filing, subject to refund and hearing procedures.

In October 2021 the LPSC filed a complaint with the FERC alleging that Entergy Services improperly excluded NOLC ADIT from MSS-4 replacement tariff rates in the period before March 20, 2021. The LPSC argued that sales from Entergy Louisiana to Entergy Texas and Entergy New Orleans were charged at rates lower than they otherwise should have been, and it accordingly seeks surcharges for the period prior to March 20, 2021. The FERC set the complaint for hearing procedures and subsequently the hearing for this complaint proceeding was consolidated with the hearing procedures for Entergy Services’ January 2021 NOLC ADIT filing.

Testimony was filed by parties in 2023, and the hearing before a FERC ALJ was concluded in February 2024. In June 2024, the FERC ALJ issued an initial decision addressing three major issues: (1) whether Entergy Services’ proposed prospective inclusion and allocation of NOLC ADIT in MSS-4 replacement tariff rates using a modified with-and-without methodology is just and reasonable; (2) whether Entergy Services correctly calculated excess and deficient accumulated deferred income taxes in accordance with the terms of a prior settlement; and (3) whether NOLC ADIT should have been included in MSS-4 replacement tariff rates prior to the effective date of the January 2021 MSS-4 replacement tariff filing.

With respect to issues (1) and (2), the presiding ALJ concluded that Entergy Services’ proposed methodology for allocating and including NOLC ADIT in MSS-4 replacement tariff rates was just and reasonable and that Entergy Services correctly performed the excess and deficient accumulated deferred income taxes calculations. With respect to issue (3), however, the presiding ALJ agreed with the LPSC that NOLC ADIT should have been included in MSS-4 replacement tariff rates since September 1, 2016, and as a result, the presiding ALJ ordered that Entergy Louisiana and Entergy Arkansas recalculate bills for the period of September 1, 2016 through November 11, 2023 with surcharges expected to be due to those operating companies from the purchasing operating companies, Entergy New Orleans, Entergy Texas, and Entergy Louisiana (for some Entergy Arkansas sales). The presiding ALJ also ordered Entergy Services to pay the interest owed to Entergy Louisiana on these surcharges.
The surcharge methodology that the presiding ALJ recommended in connection with issue (3) was not supported by any participant in the hearing. As part of their exceptions to the initial decision, all parties to the proceeding opposed the use of the ALJ’s methodology, except for the FERC trial staff, which took no position. During the hearing, the LPSC and the FERC trial staff advocated that the alleged tariff violation should be remedied by the application of Entergy Services’ January 2021 proposed methodology. All other parties, including the PUCT, the City Council, and Entergy Services, opposed any surcharges for the period prior to the March 20, 2021 effective date of the January 2021 filing.

Entergy Services disputes the presiding ALJ's rulings on issue (3) and filed exceptions to these rulings in July 2024. The ALJ's initial decision is not binding on the FERC and is an interim step in the hearing process. No refunds will be owed in connection with this proceeding unless and until the FERC requires them in a final order.
Complaints Against System Energy

System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf.  System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. System Energy and the Unit Power Sales Agreement have been the subject of several litigation proceedings at the FERC, including challenges with respect to System Energy’s authorized return on equity and capital structure, renewal of its sale-leaseback arrangement, treatment of uncertain tax positions, a broader investigation of rates under the Unit Power Sales Agreement, and two prudence complaints, one challenging the extended power uprate completed at Grand Gulf in 2012 and the operation and management of Grand Gulf, particularly in the 2016-2020 time period, and the second challenging the operation and management of Grand Gulf in the 2021-2022 time period. Settlements that resolve all significant aspects of these complaints have been reached with the MPSC, the APSC, the City Council, and the LPSC, and these settlements have been approved by the FERC. Following are discussions of the proceedings.

Return on Equity and Capital Structure Complaints

In January 2017 the APSC and the MPSC filed a complaint with the FERC against System Energy. The complaint sought a reduction in the return on equity component of the Unit Power Sales Agreement pursuant to which System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. Entergy Arkansas also sells some of its Grand Gulf capacity and energy to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under separate agreements. The return on equity under the Unit Power Sales Agreement at the time of the complaint was 10.94%, which was established in a rate proceeding that became final in July 2001.

The APSC and the MPSC complaint alleged that the return on equity was unjust and unreasonable because capital market and other considerations indicated that it was excessive. The complaint requested proceedings to investigate the return on equity and establish a lower return on equity, and also requested that the FERC establish January 23, 2017 as a refund effective date. The complaint included a return on equity analysis that purported to establish that the range of reasonable return on equity for System Energy was between 8.37% and 8.67%. System Energy answered the complaint in February 2017 and disputed that a return on equity of 8.37% to 8.67% was just and reasonable. The LPSC and the City Council intervened in the proceeding expressing support for the complaint. In September 2017 the FERC established a refund effective date of January 23, 2017 and directed the parties to engage in settlement proceedings before an ALJ. The parties were unable to settle the return on equity issue and a FERC hearing judge was assigned in July 2018. The 15-month refund period in connection with the APSC/MPSC complaint expired on April 23, 2018.

In April 2018 the LPSC filed a complaint with the FERC against System Energy seeking an additional 15-month refund period.  The LPSC complaint requested similar relief from the FERC with respect to System Energy’s
return on equity and also requested the FERC to investigate System Energy’s capital structure.  The APSC, the MPSC, and the City Council intervened in the proceeding, filed an answer expressing support for the complaint, and asked the FERC to consolidate this proceeding with the proceeding initiated by the complaint of the APSC and the MPSC in January 2017. System Energy answered the LPSC complaint in May 2018 and also filed a motion to dismiss the complaint. In August 2018 the FERC issued an order dismissing the LPSC’s request to investigate System Energy’s capital structure and setting for hearing the return on equity complaint, with a refund effective date of April 27, 2018. The 15-month refund period in connection with the LPSC return on equity complaint expired on July 26, 2019.

The portion of the LPSC’s complaint dealing with return on equity was subsequently consolidated with the APSC and the MPSC complaint for hearing. The parties also addressed an order (issued in a separate FERC proceeding involving New England transmission owners) that proposed modifying the FERC’s standard methodology for determining return on equity. In September 2018 the LPSC filed an amended complaint raising the same capital structure claim the FERC had earlier dismissed. The FERC initiated a new proceeding for the amended capital structure complaint, and System Energy answered the complaint in October 2018. In January 2019 the FERC set the amended complaint for settlement and hearing proceedings. Settlement proceedings in the capital structure proceeding commenced in February 2019, but were terminated in June 2019, and the amended capital structure complaint was consolidated with the ongoing return on equity proceeding. The 15-month refund period in connection with the capital structure complaint was from September 24, 2018 to December 23, 2019.

Several rounds of testimony were filed by the parties in these proceedings between January 2019 and August 2020. Some of these rounds of testimony were precipitated by developments in an unrelated proceeding in which the FERC issued orders addressing the methodology for determining the return on equity applicable to transmission owners in MISO (Opinion Nos. 569 and 569-A). The final positions of the parties, after the submission of all pre-filed testimony, were as follows. With regard to the return on equity complaints for the first refund period, based on their respective interpretations and applications of the Opinion No. 569-A methodology, the LPSC argued for an authorized return on equity for System Energy of 7.97%; the MPSC and the APSC argued for an authorized return on equity of 9.24%; and the FERC trial staff argued for an authorized return on equity of 9.49%. For the second refund period and on a prospective basis, based on their respective interpretations and applications of the Opinion No. 569-A methodology, the LPSC argued for an authorized return on equity for System Energy of 7.78%; the MPSC and the APSC argued that an authorized return on equity of 9.15% may be appropriate if the second complaint was not dismissed; and the FERC trial staff argued for an authorized return on equity of 9.09% if the second complaint was not dismissed. The LPSC also continued to support as its primary recommendation, based on an alternative analysis to the Opinion No. 569-A methodology, an authorized return on equity for System Energy as low as 7.56% for the first complaint refund period and as low as 7.18% for the second complaint refund period and prospectively. The MPSC and the APSC also continued to support as their primary recommendation, based on an alternative analysis to the Opinion No. 569-A methodology, an authorized return on equity for System Energy as low as 8.26% for the first complaint refund period and as low as 8.32% for the second complaint refund period and prospectively. System Energy argued that strict application of the Opinion No. 569-A methodology produces results inconsistent with investor requirements and does not provide a sound basis on which to evaluate System Energy’s authorized return on equity. Therefore, as its primary recommendation, System Energy argued for the use of a methodology that incorporates four separate financial models and, based on application of this recommended methodology, an authorized return on equity of 10.12% for the first refund period, which also fell within the presumptively just and reasonable range calculated for the second refund period and prospectively. Under the Opinion No. 569-A methodology, System Energy calculated an authorized return on equity of 9.44% for the first refund period, which also fell within the presumptively just and reasonable range calculated for the second refund period and prospectively.

With regard to the capital structure, the LPSC’s primary recommendation was that the FERC establish a hypothetical capital structure for System Energy for ratemaking purposes, according to which System Energy’s common equity ratio would be set to Entergy Corporation’s equity ratio of 37% equity and 63% debt. The APSC and the MPSC recommended that 35.98% be set as the common equity ratio for System Energy. The FERC trial
staff argued that the average capital structure of the proxy group used to develop System Energy’s return on equity should be used to establish the capital structure. Using this approach, the FERC trial staff calculated the average capital structure for its proposed proxy group of 46.74% common equity and 53.26% debt. System Energy disputed all of these recommendations and argued that the use of its actual capital structure was just and reasonable.

After conducting a hearing, in March 2021 the FERC ALJ issued an initial decision. With regard to System Energy’s authorized return on equity, the ALJ determined that the existing return on equity of 10.94% was no longer just and reasonable, and that the replacement authorized return on equity, based on application of the Opinion No. 569-A methodology, should be 9.32%. The ALJ further determined that System Energy should pay refunds for a fifteen-month refund period (January 2017-April 2018) based on the difference between the current return on equity and the replacement authorized return on equity. The ALJ determined that the April 2018 complaint concerning the authorized return on equity should be dismissed, and that no refunds for a second fifteen-month refund period should be due. With regard to System Energy’s capital structure, the ALJ determined that System Energy’s actual equity ratio was excessive and that the just and reasonable equity ratio was 48.15% equity, based on the average equity ratio of the proxy group used to evaluate the return on equity for the second complaint. The ALJ further determined that System Energy should pay refunds for a fifteen-month refund period (September 2018-December 2019) based on the difference between the actual equity ratio and the 48.15% equity ratio.

In April 2021, System Energy filed its brief on exceptions, in which it challenged the initial decision’s findings on both the return on equity and capital structure issues. Also in April 2021 the LPSC, the APSC, the MPSC, the City Council, and the FERC trial staff filed briefs on exceptions. Reply briefs opposing exceptions were filed in May 2021 by System Energy, the FERC trial staff, the LPSC, the APSC, the MPSC, and the City Council.

As discussed below in “System Energy Settlement with the MPSC,” “System Energy Settlement with the APSC,” “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the MPSC, the APSC, the City Council, and the LPSC have settled their claims related to these proceedings. As part of the settlements with their respective retail regulators, effective July 2022 for Entergy Mississippi, November 2023 for Entergy Arkansas, June 2024 for Entergy New Orleans, and September 2024 for Entergy Louisiana, bills issued under the Unit Power Sales Agreement reflect a return on equity of 9.65% and a capital structure not to exceed 52% equity.

In August 2022 the D.C. Circuit issued an order addressing appeals of FERC’s Opinion No. 569 and 569-A, which established the methodology applied in the ALJ’s initial decision in the proceeding against System Energy discussed above. The appellate order addressed the methodology for determining the return on equity applicable to transmission owners in MISO. The D.C. Circuit found the FERC’s use of the Risk Premium model as part of the methodology to be arbitrary and capricious, and remanded the case back to the FERC. In October 2024, after System Energy had reached settlements with each of the retail regulators involved in the return on equity and capital structure proceeding discussed above, the FERC issued a remand order in the MISO transmission owners’ return on equity case, concluding that the record supported the methodology that it originally directed in Opinion No. 569 utilizing an equal weighting of the two-step discounted cash flow model and capital asset pricing model. As a result, it determined that the just and reasonable return on equity for the MISO transmission owners is 9.98%. In light of the System Energy settlements detailed below, the FERC’s changes to its return on equity methodology in the decision on the MISO transmission owners’ return on equity will not have any immediate effect on System Energy’s return on equity because System Energy’s return on equity has been set at 9.65% through the global settlement through the end of June 2026.

Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue

In May 2018 the LPSC filed a complaint against System Energy and Entergy Services related to System Energy’s renewal of a sale-leaseback transaction originally entered into in December 1988 for an 11.5% undivided interest in Grand Gulf Unit 1. The complaint alleged that System Energy violated the filed rate and the FERC’s ratemaking and accounting requirements when it included in Unit Power Sales Agreement billings the cost of
capital additions associated with the sale-leaseback interest, and that System Energy was double-recovering costs by including both the lease payments and the capital additions in Unit Power Sales Agreement billings. The complaint also claimed that System Energy was imprudent in entering into the sale-leaseback renewal because the Utility operating companies that purchase Grand Gulf’s output from System Energy could have obtained cheaper capacity and energy in the MISO markets. The complaint further alleged that System Energy violated various other reporting and accounting requirements and should have sought prior FERC approval of the lease renewal. The complaint sought various forms of relief from the FERC, including refunds for capital addition costs for all years in which they were recorded in allegedly non-formula accounts or, alternatively, the disallowance of the return on equity for the capital additions in those years plus interest; a disallowance and refund of the lease costs of the sale-leaseback renewal on grounds of imprudence; an investigation into System Energy’s treatment of a DOE litigation payment; and the imposition of certain forward-looking procedural protections, including audit rights for retail regulators of the Unit Power Sales Agreement formula rates. The APSC, the MPSC, and the City Council intervened in the proceeding.

In June 2018, System Energy and Entergy Services filed a motion to dismiss and an answer to the LPSC complaint denying that System Energy’s treatment of the sale-leaseback renewal and capital additions violated the terms of the filed rate or any other FERC ratemaking, accounting, or legal requirements or otherwise constituted double recovery. The response also argued that the complaint was inconsistent with a FERC-approved settlement to which the LPSC is a party and that explicitly authorized System Energy to recover its lease payments. Finally, the response argued that both the capital additions and the sale-leaseback renewal were prudent investments and the LPSC complaint failed to justify any disallowance or refunds. The response also offered to submit formula rate protocols for the Unit Power Sales Agreement similar to the procedures used for reviewing transmission rates under the MISO tariff. In September 2018 the FERC issued an order setting the complaint for hearing and settlement proceedings and establishing a refund effective date of May 18, 2018.

In February 2019 the presiding ALJ ruled that the hearing ordered by the FERC includes the issue of whether specific subcategories of accumulated deferred income tax should be included in, or excluded from, System Energy’s formula rate. Testimony was filed by the LPSC, the MPSC, the APSC, the City Council, the FERC trial staff, and System Energy between March 2019 and October 2019. The final positions of the parties, after all pre-filed testimony was submitted, were as follows. The LPSC sought refunds that included the renewal lease payments (approximately $17.2 million per year since July 2015), rate base reductions for accumulated deferred income tax associated with uncertain tax positions (with a corresponding refund of approximately $512 million), and the cost of capital additions associated with the sale-leaseback interest, as well as interest on those amounts. The LPSC also argued that adjustments to depreciation rates should require retroactive depreciation expense refunds but only prospective rate base adjustments. The APSC, the MPSC, and the City Council generally agreed with the LPSC’s positions. The FERC trial staff argued for refunds for rate base reductions for liabilities associated with uncertain tax positions, and also argued that System Energy recovered $32 million more than it should have in depreciation expense for capital additions. System Energy filed testimony asking the FERC to reject all of the LPSC’s claims for refunds and opposing the FERC trial staff’s position regarding the uncertain tax position issue. System Energy also argued that the FERC trial staff’s position regarding depreciation rates for capital additions was not unreasonable, but any change in depreciation expense is only one element of a Unit Power Sales Agreement re-billing calculation. Adjustments to depreciation expense in any re-billing under the Unit Power Sales Agreement formula rate would also involve changes to accumulated depreciation, accumulated deferred income taxes, and other formula elements as needed.

After holding a hearing in November 2019, in April 2020 the FERC ALJ issued the initial decision. Among other things, the ALJ determined that refunds were due on three main issues. First, with regard to the lease renewal payments, the ALJ determined that System Energy was recovering an unjust acquisition premium through the lease renewal payments, and that System Energy’s recovery from customers through rates should be limited to the cost of service based on the remaining net book value of the leased assets, which was approximately $70 million. The ALJ found that the remedy for this issue should be the refund of lease payments (approximately $17.2 million per year since July 2015) with interest determined at the FERC quarterly interest rate, which would be offset by the addition
of the net book value of the leased assets in the cost of service. The ALJ did not calculate a value for the refund expected as a result of this remedy. In addition, System Energy would no longer recover the lease payments in rates prospectively. Second, with regard to the liabilities associated with uncertain tax positions, the ALJ determined that the liabilities are accumulated deferred income taxes and that System Energy’s rate base should have been reduced for those liabilities. The ALJ also found that System Energy should include liabilities associated with uncertain tax positions as a rate base reduction going forward. Third, with regard to the depreciation expense adjustments, the ALJ found that System Energy should correct for the error in re-billings retroactively and prospectively, but that System Energy should not be permitted to recover interest on any retroactive return on enhanced rate base resulting from such corrections.

In June 2020, System Energy, the LPSC, and the FERC trial staff filed briefs on exceptions, challenging several of the initial decision’s findings. System Energy’s brief on exceptions challenged the initial decision’s limitations on recovery of the lease renewal payments, its proposed rate base refund for the liabilities associated with uncertain tax positions, and its proposal to asymmetrically treat interest on bill corrections for depreciation expense adjustments. The LPSC’s and the FERC trial staff’s briefs on exceptions each challenged the initial decision’s allowance for recovery of the cost of service associated with the lease renewal based on the remaining net book value of the leased assets, its calculation of the remaining net book value of the leased assets, and the amount of the initial decision’s proposed rate base refund for the liabilities associated with uncertain tax positions. The LPSC’s brief on exceptions also challenged the initial decision’s proposal that depreciation expense adjustments include retroactive adjustments to rate base and its finding that section 203 of the Federal Power Act did not apply to the lease renewal. The FERC trial staff’s brief on exceptions also challenged the initial decision’s finding that the FERC need not institute a formal investigation into System Energy’s tariff. In October 2020, System Energy, the LPSC, the MPSC, the APSC, and the City Council filed briefs opposing exceptions. System Energy opposed the exceptions filed by the LPSC and the FERC trial staff. The LPSC, the MPSC, the APSC, the City Council, and the FERC trial staff opposed the exceptions filed by System Energy. Also in October 2020 the MPSC, the APSC, and the City Council filed briefs adopting the exceptions of the LPSC and the FERC trial staff.

In addition, in September 2020, the IRS issued a Notice of Proposed Adjustment (NOPA) and Entergy executed it. The NOPA memorialized the IRS’s decision to adjust the 2015 consolidated federal income tax return of Entergy Corporation and certain of its subsidiaries, including System Energy, with regard to the uncertain decommissioning tax position. Pursuant to the audit resolution documented in the NOPA, the IRS allowed System Energy’s inclusion of $102 million of future nuclear decommissioning costs in System Energy’s cost of goods sold for the 2015 tax year, roughly 10% of the requested deduction, but disallowed the balance of the position. In September 2020, System Energy filed a motion to lodge the NOPA into the record in the FERC proceeding. In October 2020 the LPSC, the APSC, the MPSC, the City Council, and the FERC trial staff filed oppositions to System Energy’s motion. As a result of the NOPA issued by the IRS in September 2020, System Energy filed, in October 2020, a new Federal Power Act section 205 filing at FERC to establish an ongoing rate base credit for the accumulated deferred income taxes resulting from the decommissioning uncertain tax position. On a prospective basis beginning with the October 2020 bill, System Energy proposed to include the accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position as a credit to rate base under the Unit Power Sales Agreement. In November 2020 the LPSC, the APSC, the MPSC, and the City Council filed a protest to the filing, and System Energy responded.

In November 2020 the IRS issued a Revenue Agent’s Report (RAR) for the 2014/2015 tax year and in December 2020 Entergy executed it. The RAR contained the same adjustment to the uncertain nuclear decommissioning tax position as that which the IRS had announced in the NOPA. In December 2020, System Energy filed a motion to lodge the RAR into the record in the FERC proceeding addressing the uncertain tax position rate base issue. In January 2021 the LPSC, the APSC, the MPSC, and the City Council filed a protest to the motion.

As a result of the RAR, in December 2020, System Energy filed amendments to its new Federal Power Act section 205 filings to establish an ongoing rate base credit for the accumulated deferred income taxes resulting from
the decommissioning uncertain tax position and to credit excess accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position. The amendments both proposed the inclusion of the RAR as support for the filings. In December 2020 the LPSC, the APSC, and the City Council filed protests to the amendments. In February 2021 the FERC issued an order accepting System Energy’s Federal Power Act section 205 filings subject to refund, setting them for hearing, and holding the hearing in abeyance.

In December 2020, System Energy filed a new Federal Power Act section 205 filing to provide a one-time, historical credit of $25.2 million for the accumulated deferred income taxes that would have been created by the decommissioning uncertain tax position if the IRS’s decision had been known in 2016. In January 2021 the LPSC, APSC, MPSC, and City Council filed a protest to the filing. In February 2021 the FERC issued an order accepting System Energy’s Federal Power Act section 205 filing subject to refund, setting it for hearing, and holding the hearing in abeyance. System Energy provided the one-time credit during the first quarter 2021.

In December 2022 the FERC issued an order on the ALJ’s initial decision, which affirmed it in part and modified it in part. The FERC’s order directed System Energy to calculate refunds on three issues, and to provide a compliance report detailing the calculations. The FERC’s order also disallowed the future recovery of sale-leaseback renewal costs, which is estimated at approximately $11.5 million annually for purchases from Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans through July 2036. The three refund issues were rental expenses related to the renewal of the sale-leaseback arrangements; refunds, if any, for the revenue requirement impact of including accumulated deferred income taxes resulting from the decommissioning uncertain tax positions from 2004 through the present; and refunds for the net effect of correcting the depreciation inputs for capital additions attributable to the portion of plant subject to the sale-leaseback.

As a result of the FERC order’s directives regarding the recovery of the sale-leaseback transaction, in December 2022 System Energy reduced the Grand Gulf sale-leaseback regulatory liability by $56 million, reduced the related accumulated deferred income tax asset by $94 million, and reduced the Grand Gulf sale-leaseback accumulated deferred income tax regulatory liability by $25 million, resulting in an increase in income tax expense of $13 million. In addition, the FERC determined that System Energy recognized excess depreciation expense related to property subject to the sale-leaseback. As a result, in December 2022, System Energy recorded a reduction in depreciation expense and the related accumulated depreciation of $33 million.

In January 2023, System Energy filed its compliance report with the FERC. With respect to the sale-leaseback renewal costs, System Energy calculated a refund of $89.8 million, which represented all of the sale-leaseback renewal rental costs that System Energy recovered in rates, with interest. With respect to the decommissioning uncertain tax position issue, System Energy calculated that no additional refunds were owed because it had already provided a one-time historical credit (for the period January 2016 through September 2020) of $25.2 million based on the accumulated deferred income taxes that resulted from the IRS’s partial acceptance of the decommissioning tax position, and because it has been providing an ongoing rate base credit for the accumulated deferred income taxes that resulted from the IRS’s partial acceptance of the decommissioning tax position since October 2020. With respect to the depreciation refund, System Energy calculated a refund of $13.7 million, which is the net total of a refund to customers for excess depreciation expense previously collected, plus interest, offset by the additional return on rate base that System Energy previously did not collect, without interest. See “System Energy Settlement with the MPSC” below for discussion of the regulatory charge and corresponding regulatory liability recorded in June 2022 related to these proceedings. In January 2023, System Energy paid the refunds of $103.5 million, which included refunds of $41.7 million to Entergy Arkansas, $27.8 million to Entergy Louisiana, and $34 million to Entergy New Orleans.

In February 2023 the LPSC, the APSC, and the City Council filed protests to System Energy’s January 2023 compliance report, in which they challenged System Energy’s calculation of the refunds associated with the decommissioning tax position but did not protest the other components of the compliance report. Each of them argued that System Energy should have paid additional refunds for the decommissioning tax position issue, and the City Council estimated the total additional refunds owed to customers of Entergy Louisiana, Entergy New Orleans,
and Entergy Arkansas for that issue as $493 million, including interest (and without factoring in the $25.2 million refund that System Energy already paid in 2021).

In January 2023, System Energy filed a request for rehearing of the FERC’s determinations in the December 2022 order on sale-leaseback refund issues and future lease cost disallowances, the FERC’s prospective policy on uncertain tax positions, and the proper accounting of System Energy’s accumulated deferred income taxes adjustment for the Tax Cuts and Jobs Act of 2017; and a motion for confirmation of its interpretation of the December 2022 order’s remedy concerning the decommissioning tax position. In January 2023 the retail regulators filed a motion for confirmation of their interpretation of the refund requirement in the December 2022 FERC order and a provisional request for rehearing. In February 2023 the FERC issued a notice that the rehearing requests were denied by operation of law. In March 2023, System Energy filed in the United States Court of Appeals for the Fifth Circuit a petition for review of the December 2022 order. In March 2023, System Energy also filed an unopposed motion to stay the proceeding in the Fifth Circuit pending the FERC’s disposition of the pending motions, and the court granted the motion to stay.

In February 2023, System Energy submitted a tariff compliance filing with the FERC to clarify that, consistent with the releases provided in the MPSC settlement, Entergy Mississippi will continue to be charged for its allocation of the sale-leaseback renewal costs under the Unit Power Sales Agreement. See “System Energy Settlement with the MPSC” below for discussion of the settlement. In March 2023 the MPSC filed a protest to System Energy’s tariff compliance filing. The MPSC argues that the settlement did not specifically address post-settlement sale-leaseback renewal costs and that the sale-leaseback renewal costs may not be recovered under the Unit Power Sales Agreement. Entergy Mississippi’s allocated sale-leaseback renewal costs are estimated at $5.7 million annually for the remaining term of the sale-leaseback renewal.

In August 2023 the FERC issued an order addressing arguments raised on rehearing and partially setting aside the prior order (rehearing order). The rehearing order addressed rehearing requests that were filed in January 2023 separately by System Energy and the LPSC, the APSC, and the City Council.

In the rehearing order, the FERC directed System Energy to recalculate refunds for two issues: (1) refunds of rental expenses related to the renewal of the sale-leaseback arrangements and (2) refunds for the net effect of correcting the depreciation inputs for capital additions associated with the sale-leaseback. With regard to the sale-leaseback renewal rental expenses, the rehearing order allowed System Energy to recover an implied return of and on the depreciated cost of the portion of the plant subject to the sale-leaseback as of the expiration of the initial lease term. With regard to the depreciation input issue, the rehearing order allowed System Energy to offset refunds so that System Energy may collect interest on the rate base recalculations that were part of the overall depreciation rate recalculations. The rehearing order further directed System Energy to submit within 60 days of the date of the rehearing order an additional compliance filing to revise the total refunds for these two issues. As discussed above, System Energy’s January 2023 compliance filing calculated $103.5 million in total refunds, and the refunds were paid in January 2023. In October 2023, System Energy filed its compliance report with the FERC as directed in the August 2023 rehearing order. The October 2023 compliance report reflected recalculated refunds totaling $35.7 million for the two issues resulting in $67.8 million in refunds that could be recouped by System Energy. As discussed below in “System Energy Settlement with the APSC,” System Energy reached a settlement in principle with the APSC to resolve several pending cases under the FERC’s jurisdiction, including this one, pursuant to which it agreed not to recoup the $27.3 million calculated for Entergy Arkansas in the compliance filing. As a result of the FERC’s rulings on the sale-leaseback and depreciation input issues in the August 2023 rehearing order, in third quarter 2023, System Energy recorded a regulatory asset and corresponding regulatory credit of $40 million to reflect the portion of the January 2023 refunds to be recouped from Entergy Louisiana and Entergy New Orleans. Consistent with the compliance filing, in October 2023, Entergy Louisiana and Entergy New Orleans paid recoupment amounts of $18.2 million and $22.3 million, respectively, to System Energy.
On the third refund issue identified in the rehearing requests, concerning the decommissioning uncertain tax positions, the rehearing order denied all rehearing requests, re-affirmed the remedy contained in the December 2022 order, and did not direct System Energy to recalculate refunds or to submit an additional compliance filing.

In September 2023, System Energy filed a protective appeal of the rehearing order with the United States Court of Appeals for the Fifth Circuit. The appeal was consolidated with System Energy’s prior appeal of the December 2022 order.

In September 2023 the LPSC filed with the FERC a request for rehearing and clarification of the rehearing order. The LPSC requested that the FERC reverse its determination in the rehearing order that System Energy may collect an implied return of and on the depreciated cost of the portion of the plant subject to the sale-leaseback, as of the expiration of the initial lease term, as well as its determination in the rehearing order that System Energy may offset the refunds for the depreciation rate input issue and collect interest on the rate base recalculations that were part of the overall depreciation rate recalculations. In addition, the LPSC requested that the FERC either confirm the LPSC’s interpretation of the refund associated with the decommissioning uncertain tax positions or explain why it is not doing so. In October 2023 the FERC issued a notice that the rehearing request was deemed denied by operation of law. In November 2023 the FERC issued a further notice stating that it would not issue any further order addressing the rehearing request. Also in November 2023 the LPSC filed with the United States Court of Appeals for the Fifth Circuit a petition for review of the FERC’s August 2023 rehearing order and denials of the September 2023 rehearing request.

In December 2023 the United States Court of Appeals for the Fifth Circuit lifted the abeyance on the consolidated System Energy appeals and it also consolidated the LPSC’s appeal with the System Energy appeals. Briefing of the appeals occurred between March 2024 and July 2024. In September 2024 the parties filed a joint motion to continue and stay oral argument, previously scheduled for October 2024, pending the FERC’s decision whether to approve the settlement between System Energy and the LPSC, and the United States Court of Appeals for the Fifth Circuit granted the motion. In November 2024, after the FERC issued the order approving the settlement between System Energy and the LPSC, System Energy, the LPSC, the APSC, and the FERC filed a joint stipulation to dismiss the pending appeals, which the United States Court of Appeals for the Fifth Circuit granted.

As discussed below in “System Energy Settlement with the MPSC,” “System Energy Settlement with the APSC,” “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the MPSC, the APSC, the City Council, and the LPSC have settled their claims related to this proceeding.

LPSC Additional Complaints

In May 2020 the LPSC authorized its staff to file additional complaints at the FERC related to the rates charged by System Energy for Grand Gulf energy and capacity supplied to Entergy Louisiana under the Unit Power Sales Agreement. The LPSC directive noted that the initial decision issued by the presiding ALJ in the Grand Gulf sale-leaseback complaint proceeding did not address, for procedural reasons, certain rate issues raised by the LPSC and declined to order further investigation of rates charged by System Energy.

Unit Power Sales Agreement Complaint

The first of the additional complaints was filed by the LPSC, the APSC, the MPSC, and the City Council in September 2020. The first complaint raised two sets of rate allegations: violations of the filed rate and a corresponding request for refunds for prior periods; and elements of the Unit Power Sales Agreement are unjust and unreasonable and a corresponding request for refunds for the 15-month refund period and changes to the Unit Power Sales Agreement prospectively. Several of the filed rate allegations overlapped with the previous complaints. The filed rate allegations not previously raised were that System Energy: failed to provide a rate base credit to customers for the “time value” of sale-leaseback lease payments collected from customers in advance of the time those payments were due to the owner-lessors; improperly included certain sale-leaseback transaction costs in rate base as
prepayments; improperly included nuclear refueling outage costs in rate base; wrongly included categories of accumulated deferred income taxes as increases to rate base; charged customers based on a higher equity ratio than would be appropriate due to excessive retained earnings; and did not correctly reflect money pool investments and imprudently invested cash into the money pool. The elements of the Unit Power Sales Agreement that the complaint alleged were unjust and unreasonable include: the current cash working capital allowance of zero, uncapped recovery of incentive and executive compensation, lack of an equity re-opener, and recovery of lobbying and private airplane travel expenses. The complaint also requested a rate investigation into the Unit Power Sales Agreement and System Energy’s billing practices pursuant to section 206 of the Federal Power Act, including any issue relevant to the Unit Power Sales Agreement and its inputs. System Energy filed its answer opposing the complaint in November 2020. In its answer, System Energy argued that all of the claims raised in the complaint should be dismissed and agreed that bill adjustment with respect to two discrete issues were justified. System Energy argued that dismissal was warranted because all claims fell into one or more of the following categories: the claims had been raised and were being litigated in another proceeding; the claims did not present a prima facie case and did not satisfy the threshold burden to establish a complaint proceeding; the claims were premised on a theory or request relief that is incompatible with federal law or FERC policy; the claims request relief that is inconsistent with the filed rate; the claims were barred or waived by the legal doctrine of laches; and/or the claims had been fully addressed and do not warrant further litigation. In December 2020, System Energy filed a bill adjustment report indicating that $3.4 million had been credited to customers in connection with the two discrete issues concerning the inclusion of certain accumulated deferred income taxes balances in rates.

In May 2021 the FERC issued an order addressing the complaint, establishing a refund effective date of September 21, 2020, establishing hearing procedures, and holding those procedures in abeyance pending the FERC’s review of the initial decision in the Grand Gulf sale-leaseback renewal complaint discussed above. System Energy agreed that the hearing should be held in abeyance but sought rehearing of FERC’s decision as related to matters set for hearing that were beyond the scope of FERC’s jurisdiction or authority. The complainants sought rehearing of FERC’s decision to hold the hearing in abeyance and filed a motion to proceed, which motion System Energy opposed. In June 2021, System Energy’s request for rehearing was denied by operation of law, and System Energy filed an appeal of FERC’s orders in the Court of Appeals for the Fifth Circuit. In November 2021 the Fifth Circuit dismissed the appeal as premature.

In August 2021 the FERC issued an order addressing System Energy’s and the complainants’ rehearing requests. The FERC dismissed part of the complaint seeking an equity re-opener, maintained the abeyance for issues related to the proceeding addressing the sale-leaseback renewal and uncertain tax positions, lifted the abeyance for issues unrelated to that proceeding, and clarified the scope of the hearing.

In November 2021 the LPSC, the APSC, and the City Council filed direct testimony and requested the FERC to order refunds for prior periods and prospective amendments to the Unit Power Sales Agreement. The LPSC’s refund claims included, among other things, allegations that: (1) System Energy should not have included certain sale-leaseback transaction costs in prepayments; (2) System Energy should have credited rate base to reflect the time value of money associated with the advance collection of lease payments; (3) System Energy incorrectly included refueling outage costs that were recorded in account 174 in rate base; and (4) System Energy should have excluded several accumulated deferred income tax balances in account 190 from rate base. The LPSC also sought a retroactive adjustment to retained earnings and capital structure in conjunction with the implementation of its proposed refunds. In addition, the LPSC sought amendments to the Unit Power Sales Agreement going forward to address below-the-line costs, incentive compensation, the working capital allowance, litigation expenses, and the 2019 termination of the capital funds agreement. The APSC argued that: (1) System Energy should have included borrowings from the Entergy system money pool in its determination of short-term debt in its cost of capital; and (2) System Energy should credit customers with System Energy’s allocation of earnings on money pool investments. The City Council alleged that System Energy has maintained excess cash on hand in the money pool and that retention of excess cash was imprudent. Based on this allegation, the City Council’s witness recommended a refund of approximately $98.8 million for the period 2004-September 2021 or other alternative relief. The City Council
further recommended that the FERC impose a hypothetical equity ratio such as 48.15% equity to capital on a prospective basis.

In January 2022, System Energy filed answering testimony arguing that the FERC should not order refunds for prior periods or any prospective amendments to the Unit Power Sales Agreement. In response to the LPSC’s refund claims, System Energy argued, among other things, that: (1) the inclusion of sale-leaseback transaction costs in prepayments was correct; (2) that the filed rate doctrine bars the request for a retroactive credit to rate base for the time value of money associated with the advance collection of lease payments; (3) that an accounting misclassification for deferred refueling outage costs had been corrected, caused no harm to customers, and requires no refunds; and (4) that its accounting and ratemaking treatment of specified accumulated deferred income tax balances in account 190 had been correct. System Energy further responded that no retroactive adjustment to retained earnings or capital structure should be ordered because there was no general policy requiring such a remedy, and there was no showing that the retained earnings element of the capital structure was incorrectly implemented. Further, System Energy presented evidence that all of the costs that were being challenged were long known to the retail regulators and were approved by them for inclusion in retail rates, and the attempt to retroactively challenge these costs, some of which had been included in rates for decades, was unjust and unreasonable. In response to the LPSC’s proposed going-forward adjustments, System Energy presented evidence to show that none of the proposed adjustments were needed. On the issue of below-the-line expenses, during discovery procedures System Energy identified a historical allocation error in certain months and agreed to provide a bill credit to customers to correct the error. In response to the APSC’s claims, System Energy argued that the Unit Power Sales Agreement did not include System Energy’s borrowings from the Entergy system money pool or earnings on deposits to the Entergy system money pool in the determination of the cost of capital; and accordingly, no refunds were appropriate on those issues. In response to the City Council’s claims, System Energy argued that it has reasonably managed its cash and that the City Council’s theory of cash management was defective because it failed to adequately consider the relevant cash needs of System Energy and it made faulty presumptions about the operation of the Entergy system money pool. System Energy further pointed out that the issue of its capital structure was already subject to pending FERC litigation.

In March 2022 the FERC trial staff filed direct and answering testimony in response to the LPSC, the APSC, and the City Council’s direct testimony. In its testimony, the FERC trial staff recommended refunds for two primary reasons: (1) it concluded that System Energy should have excluded specified accumulated deferred income tax balances in account 190 associated with rate refunds; and (2) it concluded that System Energy should have excluded specified accumulated deferred income tax balances in account 190 associated with a deemed contract satisfaction and reissuance that occurred in 2005. The FERC trial staff recommended refunds of $84.1 million, exclusive of any tax gross-up or FERC interest. In addition, the FERC trial staff recommended the following prospective modifications to the Unit Power Sales Agreement: (1) inclusion of a rate base credit to recognize the time value of money associated with the advance collection of lease payments; (2) exclusion of executive incentive compensation costs for members of the Office of the Chief Executive and long-term performance unit costs where awards are based solely or primarily on financial metrics; and (3) exclusion of unvested, accrued amounts for stock options, performance units, and restricted stock awards. With respect to issues that ultimately concerned the reasonableness of System Energy’s rate of return, the FERC trial staff stated that it was unnecessary to consider such issues in the proceeding, in light of the pending case concerning System Energy’s return on equity and capital structure. On all other material issues raised by the LPSC, the APSC, and the City Council, the FERC trial staff recommended either no refunds or no modification to the Unit Power Sales Agreement.

In April 2022, System Energy filed cross-answering testimony in response to the FERC trial staff’s recommendations of refunds for the accumulated deferred income taxes issues and proposed modifications to the Unit Power Sales Agreement for the executive incentive compensation issues. In June 2022 the FERC trial staff submitted revised answering testimony, in which it recommended additional refunds associated with the accumulated deferred income tax balances in account 190 associated with a deemed contract satisfaction and reissuance that occurred in 2005. Based on the testimony revisions, the FERC trial staff’s recommended refunds total $106.6 million, exclusive of any tax gross-up or FERC awarded interest. Also in June 2022, System Energy
filed revised and supplemental cross-answering testimony to respond to the FERC trial staff’s testimony and oppose its revised recommendation.

In May 2022 the LPSC, the APSC, and the City Council filed rebuttal testimony. The LPSC’s testimony asserted new claims, including that: (1) certain of the sale-leaseback transaction costs may have been imprudently incurred; (2) accumulated deferred income taxes associated with sale-leaseback transaction costs should have been included in rate base; (3) accumulated deferred income taxes associated with federal investment tax credits should have been excluded from rate base; (4) monthly net operating loss accumulated deferred income taxes should have been excluded from rate base; and (5) several categories of proposed rate changes, including executive incentive compensation, air travel, industry dues, and legal costs, also warranted historical refunds. The LPSC’s rebuttal testimony argued that refunds for the alleged tariff violations and other claims must be calculated by rerunning the Unit Power Sales Agreement formula rate; however, it included estimates of refunds associated with some, but not all, of its claims, totaling $286 million without interest. The City Council’s rebuttal testimony also proposed a new, alternate theory and claim for relief regarding System Energy’s participation in the Entergy system money pool, under which it calculates estimated refunds of approximately $51.7 million. The APSC’s rebuttal testimony agreed with the LPSC’s direct testimony that retained earnings should be adjusted in a comprehensive refund calculation. The testimony quantified the estimated impacts of three issues: (1) a $1.5 million reduction in the revenue requirement under the Unit Power Sales Agreement if System Energy’s borrowings from the money pool were included in short-term debt; (2) a $1.9 million reduction in the revenue requirement if System Energy’s allocated share of money pool earnings were credited through the Unit Power Sales Agreement; and (3) a $1.9 million reduction in the revenue requirement for every $50 million of refunds ordered in a given year, without interest. In total, excluding the settled issues noted below, the claims sought more than $700 million in refunds and interest, based on charges to all Unit Power Sales Agreement purchasers including Entergy Mississippi. The hearing before a FERC ALJ occurred between September and December 2022.

In November 2022, System Energy filed a partial settlement agreement with the APSC, the City Council, and the LPSC that resolved the following issues raised in the Unit Power Sales Agreement complaint: advance collection of lease payments, aircraft costs, executive incentive compensation, money pool borrowings, advertising expenses, deferred nuclear refueling outage costs, industry association dues, and termination of the capital funds agreement. The settlement provided that System Energy would provide a black box refund of $18 million (inclusive of interest), plus additional refund amounts with interest to be calculated for certain issues to be distributed to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans as the Utility operating companies other than Entergy Mississippi purchasing under the Unit Power Sales Agreement. The settlement further provided that if the APSC, the City Council, or the LPSC agreed to the global settlement System Energy entered into with the MPSC (discussed below), and such global settlement included a black box refund amount, then the black box refund for this settlement agreement would not be incremental or in addition to the global black box refund amount. The settlement agreement addressed other matters as well, including adjustments to rate base beginning in October 2022, exclusion of certain other costs, and inclusion of money pool borrowings, if any, in short-term debt within the cost of capital calculation used in the Unit Power Sales Agreement. In April 2023 the FERC approved the settlement agreement. The refund provided for in the settlement agreement was included in the May 2023 service month bills under the Unit Power Sales Agreement.

In May 2023 the presiding ALJ issued an initial decision finding that System Energy should have excluded multiple identified categories of accumulated deferred income taxes from rate base when calculating Unit Power Sales Agreement bills. The initial decision also found that the Unit Power Sales Agreement should be modified such that a cash working capital allowance of negative $36.4 million is applied prospectively. On the other non-settled issues for which the complainants sought refunds or changes to the Unit Power Sales Agreement, the initial decision ruled against the complainants.

System Energy disagreed with the ALJ’s findings concerning the accumulated deferred income taxes issues and cash working capital. In July 2023, System Energy filed a brief on exceptions to the initial decision’s accumulated deferred income taxes findings. Also in July 2023, the APSC, the LPSC, the City Council, and the
FERC trial staff filed separate briefs on exceptions. In August 2023 all parties filed separate briefs opposing exceptions.

As discussed below in “System Energy Settlement with the MPSC,” “System Energy Settlement with the APSC,” and “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the MPSC, the APSC, and the City Council, and the LPSC have settled their claims related to this proceeding.

Grand Gulf Prudence Complaints

The second of the additional complaints was filed at the FERC in March 2021 by the LPSC, the APSC, and the City Council against System Energy, Entergy Services, Entergy Operations, and Entergy Corporation. The second complaint contained two primary allegations. First, it alleged that, based on the plant’s capacity factor and alleged safety performance, System Energy and the other respondents imprudently operated Grand Gulf during the period 2016-2020, and it sought refunds of at least $360 million in alleged replacement energy costs, in addition to other costs, including those that could only be identified upon further investigation. Second, it alleged that the performance and/or management of the 2012 extended power uprate of Grand Gulf was imprudent, and it sought refunds of all costs of the 2012 uprate that were determined to result from imprudent planning or management of the project. In addition to the requested refunds, the complaint asked that the FERC modify the Unit Power Sales Agreement to provide for full cost recovery only if certain performance indicators were met and to require pre-authorization of capital improvement projects in excess of $125 million before related costs could be passed through to customers in rates. In April 2021, System Energy and the other respondents filed their motion to dismiss and answer to the complaint. System Energy requested that the FERC dismiss the claims within the complaint. With respect to the claim concerning operations, System Energy argued that the complaint did not meet its legal burden because, among other reasons, it failed to allege any specific imprudent conduct. With respect to the claim concerning the uprate, System Energy argued that the complaint failed because, among other reasons, the complainants’ own conduct prevented them from raising a serious doubt as to the prudence of the uprate. System Energy also requested that the FERC dismiss other elements of the complaint, including the proposed modifications to the Unit Power Sales Agreement, because they were not warranted. In February 2023 the FERC issued an order denying rehearing and thereby affirming its order setting the complaint for settlement and hearing procedures. In July 2023 the FERC chief ALJ terminated settlement procedures and appointed a presiding ALJ to oversee hearing procedures. In September 2023 a procedural schedule for hearing procedures was established. Also in September 2023 the LPSC authorized its staff to file an additional complaint concerning the prudence of System Energy’s operation and management of Grand Gulf in the year 2022. In October 2023 the LPSC, the APSC, and the City Council filed what they styled as an amended and supplemental complaint with the FERC against System Energy, Entergy Services, and Entergy Operations. In November 2023, System Energy answered the amended and supplemental complaint. Pursuant to the procedural schedule, the complainants’ testimony in the original complaint proceeding was filed in December 2023. System Energy’s answering testimony was filed in May 2024, and the FERC trial staff’s direct and answering testimony was filed in June 2024.

As discussed below in “System Energy Settlement with the APSC,” “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the APSC, the City Council, and the LPSC have settled all of their claims related to this proceeding.

System Energy Settlement with the MPSC

In June 2022, System Energy, Entergy Mississippi, and additional named Entergy parties involved in thirteen docketed proceedings before the FERC filed with the FERC a partial settlement agreement and offer of settlement. The settlement memorialized the Entergy parties’ agreement with the MPSC to globally resolve all actual and potential claims between the Entergy parties and the MPSC associated with those FERC proceedings and with System Energy’s past implementation of the Unit Power Sales Agreement. The Unit Power Sales Agreement is a FERC-jurisdictional formula rate tariff for sales of energy and capacity from System Energy’s owned and
leased share of Grand Gulf to Entergy Mississippi, Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans. Entergy Mississippi purchases the greatest single amount, nearly 40% of System Energy’s share of Grand Gulf, after its additional purchases from affiliates are considered.

The settlement provided for a black box refund of $235 million from System Energy to Entergy Mississippi. In addition, beginning with the July 2022 service month, the settlement provided for Entergy Mississippi’s bills from System Energy to be adjusted to reflect: an authorized rate of return on equity of 9.65%, a capital structure not to exceed 52% equity, a rate base reduction for the advance collection of sale-leaseback rental costs, and the exclusion of certain long-term incentive plan performance unit costs from rates. The settlement was approved by the MPSC in June 2022 and the FERC in November 2022.

System Energy had previously recorded a provision and associated liability of $37 million for elements of the applicable litigation. In June 2022, System Energy recorded a regulatory charge of $551 million ($413 million net-of-tax), increasing the regulatory liability to $588 million, which consisted of $235 million for the settlement with the MPSC and $353 million for potential future refunds to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans. System Energy paid the black box refund of $235 million to Entergy Mississippi in November 2022.

System Energy Settlement with the APSC

In October 2023, System Energy, Entergy Arkansas, and additional named Entergy parties involved in multiple docketed proceedings pending before the FERC reached a settlement in principle with the APSC to globally resolve all of their actual and potential claims in those dockets and with System Energy’s past implementation of the Unit Power Sales Agreement. The settlement also covered the amended and supplemental complaint, discussed above in “Grand Gulf Prudence Complaint,” filed at the FERC in October 2023. System Energy, Entergy Arkansas, additional Entergy parties, and the APSC filed the settlement agreement and supporting materials with the FERC in November 2023.

The terms of the settlement with the APSC aligned with the $588 million global black box settlement reached between System Energy and the MPSC in June 2022 and provided for Entergy Arkansas to receive a black box refund of $142 million from System Energy, inclusive of $49.5 million already received by Entergy Arkansas from System Energy. In addition, beginning with the November 2023 service month, the settlement provided for Entergy Arkansas’s bills from System Energy to be adjusted to reflect an authorized rate of return on equity of 9.65% and a capital structure not to exceed 52% equity. In March 2024 the FERC approved the settlement, and System Energy paid the remaining black box refund of $93 million to Entergy Arkansas in 2024.

System Energy Settlement with the City Council

In April 2024, System Energy, Entergy New Orleans, and additional named Entergy parties involved in multiple docketed proceedings pending before the FERC reached a settlement in principle with the City Council to globally resolve all of their actual and potential claims in those dockets and with System Energy’s past implementation of the Unit Power Sales Agreement. The settlement also covered the amended and supplemental complaint, discussed in “Grand Gulf Prudence Complaints” above, filed by the LPSC, the APSC, and the City Council at the FERC in October 2023. In May 2024, System Energy, Entergy New Orleans, additional named Entergy parties, and the City Council filed the settlement agreement and supporting materials with the FERC.

The terms of the settlement with the City Council aligned with the $588 million global black box settlement amount reflected in the prior settlements reached between System Energy and the MPSC in June 2022 and between System Energy and the APSC in November 2023. The settlement provided for Entergy New Orleans to receive a black box refund of $116 million from System Energy, inclusive of approximately $18 million already received by Entergy New Orleans from System Energy. In addition, beginning with the June 2024 service month, the settlement provided for Entergy New Orleans’s bills from System Energy to be adjusted to reflect an authorized rate of return on equity of 9.65% and a capital structure not to exceed 52% equity. In August 2024 the FERC approved the
settlement, and System Energy paid the remaining black box refund of $98 million to Entergy New Orleans in October 2024.

System Energy Settlement with the LPSC

In July 2024, System Energy and the LPSC staff reached a settlement in principle to globally resolve all of the LPSC’s actual and potential claims in multiple docketed proceedings pending before the FERC (including all docketed proceedings resolved by the MPSC, the APSC, and the City Council settlements) and with System Energy’s past implementation of the Unit Power Sales Agreement. The settlement also covered the amended and supplemental complaint, discussed above in “Grand Gulf Prudence Complaints,” filed by the LPSC, the APSC, and the City Council at the FERC in October 2023. In August 2024 the LPSC approved the settlement. In September 2024 the settling parties filed the settlement for approval by the FERC.

The terms of the settlement with the LPSC staff aligned with the $588 million global black box settlement amount reflected in the prior settlements reached between System Energy and the MPSC in June 2022, between System Energy and the APSC in November 2023, and between System Energy and the City Council in April 2024. The settlement in principle provided for Entergy Louisiana to receive a black box refund of $95 million from System Energy, inclusive of approximately $15 million already received by Entergy Louisiana from System Energy. In addition, beginning with the September 2024 service month, the settlement provided for Entergy Louisiana’s bills from System Energy to be adjusted to reflect an authorized rate of return on equity of 9.65% and a capital structure not to exceed 52% equity. In November 2024 the FERC approved the settlement, and System Energy paid the remaining black box refund of $80 million to Entergy Louisiana in December 2024.

The settlement also included an agreement that, subject to the receipt of necessary regulatory approvals, Entergy Louisiana will divest to Entergy Mississippi all of its interest in Grand Gulf capacity and energy under the Unit Power Sales Agreement and its purchases from Entergy Arkansas under the MSS-4 replacement tariff. In October 2024 Entergy Louisiana and Entergy Mississippi filed with the FERC a PPA under which Entergy Mississippi would purchase Entergy Louisiana’s purchases of Grand Gulf capacity and energy. The PPA is governed by the MSS-4 replacement tariff, a tariff governing the sales of energy and capacity among the Utility operating companies. The requisite approvals for the PPA were issued by the FERC in November 2024 and the MPSC in February 2025. The divestiture is effective as of January 1, 2025.

System Energy Regulatory Liability for Pending Complaints

Prior to June 2022, System Energy recorded a provision and associated liability of $37 million for elements of the complaints against System Energy. In June 2022, as discussed in “System Energy Settlement with the MPSC” above, System Energy recorded a regulatory charge of $551 million ($413 million net-of-tax), increasing System Energy’s regulatory liability to $588 million, which consisted of $235 million for the settlement with the MPSC and $353 million for potential future refunds to Entergy Arkansas, Entergy New Orleans, and Entergy Louisiana. System Energy paid the black box refund of $235 million to Entergy Mississippi in November 2022. As discussed above in “Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue,” in January 2023 System Energy paid refunds of $103.5 million as a result of the FERC’s order in December 2022 in that proceeding and recouped $40.5 million of the $103.5 million from Entergy Louisiana and Entergy New Orleans in October 2023. In addition, as discussed above in “Unit Power Sales Agreement Complaint,” a black box refund of $18 million was made by System Energy in 2023 in connection with a partial settlement in that proceeding. Based on analysis of the then-pending complaints against System Energy and potential future settlement negotiations with the LPSC and the City Council, in third quarter 2023, System Energy recorded a regulatory charge of $40 million to increase System Energy’s regulatory liability related to complaints against System Energy. In December 2023 the $93 million black box refund to Entergy Arkansas was reclassified from the regulatory liability to accounts payable - associated companies on System Energy’s balance sheet. System Energy paid the remaining black box refunds of $93 million to Entergy Arkansas, $98 million to Entergy New Orleans, and $80 million to Entergy Louisiana in 2024.
Unit Power Sales Agreement

System Energy Formula Rate Annual Protocols Formal Challenge Concerning 2020 Calendar Year Bills

System Energy’s Unit Power Sales Agreement includes formula rate protocols that provide for the disclosure of cost inputs, an opportunity for informal discovery procedures, and a challenge process. In February 2022, pursuant to the protocols procedures, the LPSC, the APSC, the MPSC, the City Council, and the Mississippi Public Utilities Staff filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2020. This formal challenge was ultimately settled as a result of System Energy’s global settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” above for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.

System Energy Formula Rate Annual Protocols Formal Challenge Concerning 2021 Calendar Year Bills

In March 2023, pursuant to the protocols procedures discussed above, the LPSC, the APSC, and the City Council filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2021. This formal challenge was ultimately settled as a result of System Energy’s global settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” above for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.

System Energy Formula Rate Annual Protocols Formal Challenge Concerning 2022 Calendar Year Bills

In February 2024, pursuant to the protocols procedures, the LPSC and the City Council filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2022. This formal challenge was ultimately settled as a result of System Energy’s global settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” above for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.

Depreciation Amendment Proceeding

In December 2021, System Energy submitted to the FERC proposed amendments to the Unit Power Sales Agreement to adopt updated rates for use in calculating Grand Gulf plant depreciation and amortization expenses. The proposed amendments would result in higher charges to the Utility operating companies that buy capacity and energy from System Energy under the Unit Power Sales Agreement. In February 2022 the FERC accepted System Energy’s proposed increased depreciation rates with an effective date of March 1, 2022, subject to refund pending the outcome of the settlement and/or hearing procedures. In June 2023 System Energy filed with the FERC an unopposed offer of settlement that it had negotiated with intervenors to the proceeding. In August 2023 the FERC approved the settlement, which resolves the proceeding. In third quarter 2023, System Energy recorded a reduction in depreciation expense of $41 million representing the cumulative difference in depreciation expense resulting from the depreciation rates used from March 2022 through June 2023 and the depreciation rates included in the settlement filing approved by the FERC. In October 2023, System Energy filed a refund report with the FERC. The refund provided for in the refund report was included in the September 2023 service month bills under the Unit Power Sales Agreement. No comments or protests to the refund report were filed.

Pension Costs Amendment Proceeding

In October 2021, System Energy submitted to the FERC proposed amendments to the Unit Power Sales Agreement to include in rate base the prepaid and accrued pension costs associated with System Energy’s qualified pension plans. Based on data ending in 2020, the increased annual revenue requirement associated with the filing is approximately $8.9 million. In March 2022 the FERC accepted System Energy’s proposed amendments with an
effective date of December 1, 2021, subject to refund pending the outcome of the settlement and/or hearing procedures. In August 2023 the FERC chief ALJ terminated settlement procedures and designated a presiding ALJ to oversee hearing procedures. Testimony was filed by the parties from October 2023 through April 2024, and the hearing concluded in June 2024.

In September 2024 the presiding ALJ issued an initial decision recommending that the FERC approve inclusion of a line item in rate base for prepaid and accrued pension costs; however, the presiding ALJ did not agree with System Energy’s proposed methodology to calculate the value of the prepaid and accrued pension cost input. Instead, the presiding ALJ recommended limiting System Energy’s recovery to the prepaid and accrued pension costs that were incurred beginning in 2015 and later.

System Energy disputes the presiding ALJ's determination concerning the methodology used to calculate the prepaid and accrued pension input, and System Energy filed exceptions to these rulings in October 2024. In October 2024, the LPSC, the APSC, and the FERC trial staff filed separate briefs on exceptions; these parties generally argue that the presiding ALJ should have rejected System Energy’s filing entirely, rather than limit System Energy’s recovery of the prepaid and accrued pension costs. Later in October 2024, System Energy, the LPSC, the APSC, and the FERC trial staff filed separate briefs opposing exceptions.

If the ALJ’s determination is affirmed by the FERC, System Energy estimates refunds, including interest through December 31, 2024, of approximately $16 million to $21 million would be owed. The ALJ's initial decision is not binding on the FERC and is an interim step in the hearing process. No refunds will be owed in connection with this proceeding and no changes to System Energy’s pension cost recovery methodology will be implemented unless and until the FERC requires them in a final order. This proceeding is not covered by the global settlements described above.
Storm Cost Recovery Filings with Retail Regulators

Entergy Louisiana

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.

In December 2024, and subsequently amended in an errata filed in February 2025, Entergy Louisiana submitted an application to the LPSC seeking a determination that approximately $183.6 million in storm restoration costs associated with Hurricane Francine were reasonable and necessary and, therefore, eligible for recovery from customers, as well as approval to recover approximately $3.6 million in certain carrying costs from customers. The $183.6 million includes approximately $152.8 million in distribution capital costs and approximately $29.8 million in non-capital costs; the balance consists of transmission and generation capital costs. Entergy Louisiana proposes in its application to recover its distribution-related capital costs of $152.8 million through the distribution recovery mechanism of its formula rate plan. Entergy Louisiana has further requested the LPSC to authorize recovery of these distribution-related capital expenses through an interim rate adjustment, subject to true-up and refund, that would begin with the first billing cycle of March 2025. Entergy Louisiana also requested to recover, from its storm reserve escrow account, $33.5 million, which consists of non-capital costs and certain carrying costs. Entergy Louisiana has also proposed to recover the transmission and generation capital costs through separate ratemaking proceedings. In February 2025, Entergy Louisiana withdrew the $33.5 million from its storm reserve escrow account. The period for intervention has expired, and a status conference for the purpose of establishing a procedural schedule has been set for March 2025.
Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida

In August 2020 and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of Entergy Louisiana’s service area. The storms resulted in widespread outages, significant damage to distribution and transmission infrastructure, and the loss of sales during the outages. Additionally, as a result of Hurricane Laura’s extensive damage to the grid infrastructure serving the impacted area, large portions of the underlying transmission system required nearly a complete rebuild.

In October 2020, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments in connection with the issuance of shorter-term mortgage bonds to provide interim financing for restoration costs associated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta. Subsequently, Entergy Louisiana and the LPSC staff filed a joint motion seeking approval to exclude from the derivation of Entergy Louisiana’s capital structure and cost rate of debt for ratemaking purposes, including the allowance for funds used during construction, shorter-term debt up to $1.1 billion issued by Entergy Louisiana to fund costs associated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta costs on an interim basis. In November 2020 the LPSC issued an order approving the joint motion, and Entergy Louisiana issued $1.1 billion of 0.62% Series mortgage bonds due November 2023. Also in November 2020, Entergy Louisiana withdrew $257 million from its funded storm reserves.

In February 2021 two winter storms (collectively, Winter Storm Uri) brought freezing rain and ice to Louisiana. Ice accumulation sagged or downed trees, limbs, and power lines, causing damage to Entergy Louisiana’s transmission and distribution systems. The additional weight of ice caused trees and limbs to fall into power lines and other electric equipment. When the ice melted, it affected vegetation and electrical equipment, causing additional outages. Entergy Louisiana recovered the incremental fuel costs associated with Winter Storm Uri over a five-month period from April 2021 through August 2021.

In April 2021, Entergy Louisiana filed an application with the LPSC relating to Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri restoration costs and in July 2021, Entergy Louisiana made a supplemental filing updating the total restoration costs. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by these storms were estimated to be approximately $2.06 billion, including approximately $1.68 billion in capital costs and approximately $380 million in non-capital costs. Including carrying costs through January 2022, Entergy Louisiana sought an LPSC determination that $2.11 billion was prudently incurred and, therefore, was eligible for recovery from customers. Additionally, Entergy Louisiana requested that the LPSC determine that re-establishment of a storm escrow account to the previously authorized amount of $290 million was appropriate. In July 2021, Entergy Louisiana supplemented the application with a request regarding the financing and recovery of the recoverable storm restoration costs. Specifically, Entergy Louisiana requested approval to securitize its restoration costs pursuant to Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021.

In August 2021, Hurricane Ida caused extensive damage to Entergy Louisiana’s distribution and, to a lesser extent, transmission systems resulting in widespread power outages. In September 2021, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments in connection with the issuance of approximately $1 billion of shorter-term mortgage bonds to provide interim financing for restoration costs associated with Hurricane Ida, which bonds were issued in October 2021. Also in September 2021, Entergy Louisiana sought approval for the creation and funding of a $1 billion restricted escrow account for Hurricane Ida related restoration costs, subject to a subsequent prudence review.

After filing of testimony by the LPSC staff and intervenors, which generally supported or did not oppose Entergy Louisiana’s requests in regard to Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida, the parties negotiated and executed an uncontested stipulated settlement which was filed with the LPSC in February 2022. The settlement agreement contained the following key terms: $2.1 billion of restoration costs from Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri were prudently incurred and
eligible for recovery; carrying costs of $51 million were recoverable; a $290 million cash storm reserve should be re-established; a $1 billion reserve should be established to partially pay for Hurricane Ida restoration costs; and Entergy Louisiana was authorized to finance $3.186 billion utilizing the securitization process authorized by Act 55, as supplemented by Act 293. The LPSC issued an order approving the settlement in March 2022. As a result of the financing order, Entergy Louisiana reclassified $1.942 billion from utility plant to other regulatory assets.

In May 2022 the securitization financing closed, resulting in the issuance of $3.194 billion principal amount of bonds by Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA), a political subdivision of the State of Louisiana. The securitization was authorized pursuant to the Louisiana Utilities Restoration Corporation Act, Part VIII of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana legislature approved in 2021. The LCDA loaned the proceeds to the LURC. Pursuant to Act 293, the LURC contributed the net bond proceeds to a State legislatively authorized and LURC-sponsored trust, Restoration Law Trust I (the storm trust I).

Pursuant to Act 293, the net proceeds of the bonds were used by the storm trust I to purchase 31,635,718.7221 Class A preferred, non-voting membership interest units (the preferred membership interests) issued by Entergy Finance Company. Entergy Finance Company is required to make annual distributions (dividends) commencing on December 15, 2022 on the preferred membership interests issued to the storm trust I. These annual dividends received by the storm trust I will be distributed to Entergy Louisiana and the LURC, as beneficiaries of the storm trust I. Specifically, 1% of the annual dividends received by the storm trust I will be distributed to the LURC, for the benefit of customers, and 99% will be distributed to Entergy Louisiana, net of storm trust expenses. The preferred membership interests have a stated annual cumulative cash dividend rate of 7% and a liquidation price of $100 per unit. The terms of the preferred membership interests include certain financial covenants to which Entergy Finance Company is subject. Semi-annual redemptions of the preferred membership interests, subject to certain conditions, are expected to occur over the next 15 years.

Entergy and Entergy Louisiana do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA. The bonds are secured by system restoration property, which is the right granted by law to the LURC to collect a system restoration charge from customers. The system restoration charge is adjusted at least semi-annually to ensure that it is sufficient to service the bonds. Entergy Louisiana collects the system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee. Entergy Louisiana began collecting the system restoration charge effective with the first billing cycle of June 2022 and the system restoration charge is expected to remain in place for up to 15 years. Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as a billing and collection agent for the LCDA and the LURC. In the remote possibility that the system restoration charge, as well as any funds in the excess subaccount and funds in the debt service reserve account, are insufficient to service the bonds resulting in a payment default, the storm trust I is required to liquidate Entergy Finance Company preferred membership interests in an amount equal to what would be required to cure the default. The estimated value of this indirect guarantee is immaterial.

From the proceeds from the issuance of the preferred membership interests, Entergy Finance Company distributed $1.4 billion to its parent, Entergy Holdings Company, LLC, a company wholly-owned and consolidated by Entergy. Subsequently, Entergy Holdings Company liquidated, distributing the $1.4 billion it received from Entergy Finance Company to Entergy Louisiana as holder of 6,843,780.24 units of Class A, 4,126,940.15 units of Class B, and 2,935,152.69 units of Class C preferred membership interests. Entergy Louisiana had acquired these preferred membership interests with proceeds from previous securitizations of storm restoration costs. Entergy Finance Company loaned the remaining $1.7 billion from the preferred membership interests proceeds to Entergy which used the cash to redeem $650 million of 4.00% Series senior notes due July 2022 and indirectly contributed $1 billion to Entergy Louisiana as a capital contribution.

Entergy Louisiana used the $1 billion capital contribution to fund its Hurricane Ida escrow account and subsequently withdrew the $1 billion from the escrow account. With a portion of the $1 billion withdrawn from the
escrow account and the $1.4 billion from the Entergy Holdings Company liquidation, Entergy Louisiana deposited $290 million in a restricted escrow account as a storm damage reserve for future storms, used $1.2 billion to repay its unsecured term loan due June 2023, and used $435 million to redeem a portion of its 0.62% Series mortgage bonds due November 2023.

As discussed in Note 3 to the financial statements, the securitization resulted in recognition of a reduction of income tax expense of approximately $290 million by Entergy Louisiana. Entergy’s recognition of reduced income tax expense was partially offset by other tax charges resulting in a net reduction of income tax expense of $283 million. In recognition of obligations described in an LPSC ancillary order issued as part of the securitization regulatory proceeding, Entergy Louisiana recorded a $224 million ($165 million net-of-tax) regulatory charge and a corresponding regulatory liability to reflect its obligation to provide credits to its customers.

As discussed in Note 6 and Note 17 to the financial statements, Entergy Louisiana consolidates the storm trust I as a variable interest entity and the LURC’s 1% beneficial interest is presented as noncontrolling interest in the financial statements. In second quarter 2022, Entergy Louisiana recorded a charge of $31.6 million in other income to reflect the LURC’s beneficial interest in the storm trust I.

In April 2022, Entergy Louisiana filed an application with the LPSC relating to Hurricane Ida restoration costs. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by Hurricane Ida were estimated to be approximately $2.54 billion, including approximately $1.96 billion in capital costs and approximately $586 million in non-capital costs. Including carrying costs of $57 million through December 2022, Entergy Louisiana was seeking an LPSC determination that $2.60 billion was prudently incurred and, therefore, eligible for recovery from customers. As part of this filing, Entergy Louisiana also was seeking an LPSC determination that an additional $32 million in costs associated with the restoration of Entergy Louisiana’s electric facilities damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta as well as Winter Storm Uri was prudently incurred. This amount was exclusive of the requested $3 million in carrying costs through December 2022. In total, Entergy Louisiana was requesting an LPSC determination that $2.64 billion was prudently incurred and, therefore, eligible for recovery from customers. As discussed above, in March 2022 the LPSC approved financing of a $1 billion storm escrow account from which funds were withdrawn to finance costs associated with Hurricane Ida restoration. In June 2022, Entergy Louisiana supplemented the application with a request regarding the financing and recovery of the recoverable storm restoration costs. Specifically, Entergy Louisiana requested approval to securitize its restoration costs pursuant to Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021. In October 2022 the LPSC staff recommended a finding that the requested storm restoration costs of $2.64 billion, including associated carrying costs of $59.1 million, were prudently incurred and eligible for recovery from customers. The LPSC staff further recommended approval of Entergy Louisiana’s plans to securitize these costs, net of the $1 billion in funds withdrawn from the storm escrow account described above. The parties negotiated and executed an uncontested stipulated settlement which was filed with the LPSC in December 2022. The settlement agreement contains the following key terms: $2.57 billion of restoration costs from Hurricane Ida, Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri were prudently incurred and eligible for recovery; carrying costs of $59.2 million were recoverable; and Entergy Louisiana was authorized to finance $1.657 billion utilizing the securitization process authorized by Act 55, as supplemented by Act 293. A procedural motion to consider the uncontested settlement at the December 2022 LPSC meeting did not pass and the settlement was not voted on. In January 2023 an ALJ with the LPSC conducted a settlement hearing to receive the uncontested settlement and supporting testimony into evidence and issued a report of proceedings, which allows the LPSC to consider the uncontested settlement without the procedural motion that did not pass in December. In January 2023 the LPSC approved the stipulated settlement subject to certain modifications. These modifications include the recognition of accumulated deferred income tax benefits related to damaged assets and system restoration costs as a reduction of the amount authorized to be financed utilizing the securitization process authorized by Act 55, as supplemented by Act 293, from $1.657 billion to $1.491 billion. These modifications did not affect the LPSC’s conclusion that all system restoration costs sought by Entergy Louisiana were reasonable and prudent. In February 2023 the Louisiana Bond Commission voted to authorize the LCDA to issue the bonds authorized in the LPSC’s financing order.
In March 2023 the Hurricane Ida securitization financing closed, resulting in the issuance of approximately $1.491 billion principal amount of bonds by the LCDA and a remaining regulatory asset of $180 million to be recovered through the exclusion of the accumulated deferred income taxes related to damaged assets and system restoration costs from the determination of future rates. The securitization was authorized pursuant to the Louisiana Utilities Restoration Corporation Act, Part VIII of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021. The LCDA loaned the proceeds to the LURC. Pursuant to Act 293, the LURC contributed the net bond proceeds to a State legislatively authorized and LURC-sponsored trust, Restoration Law Trust II (the storm trust II).

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

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

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

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

As discussed in Note 6 and Note 17 to the financial statements, Entergy Louisiana consolidates the storm trust II as a variable interest entity and the LURC’s 1% beneficial interest is presented as noncontrolling interest in
the financial statements. In first quarter 2023, Entergy Louisiana recorded a charge of $14.6 million in other income to reflect the LURC’s beneficial interest in the storm trust II.

Hurricane Isaac

In August 2012, Hurricane Isaac caused extensive damage to Entergy Louisiana’s service area.  In June 2014 the LPSC authorized Entergy Louisiana to utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs.  Entergy Louisiana committed to pass on to customers a minimum of $30.8 million of customer benefits through annual customer credits of approximately $6.2 million for five years. Approvals for the Act 55 financings were obtained from the LURC and the Louisiana State Bond Commission.

In August 2014 the LCDA issued $314.85 million in bonds under Louisiana Act 55.  From the $309 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $16 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $293 million directly to Entergy Louisiana.  Entergy Louisiana used the $293 million received from the LURC to acquire 2,935,152.69 Class C preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 7.5% annual distribution rate. Distributions were payable quarterly commencing on September 15, 2014, and the membership interests had a liquidation price of $100 per unit. The preferred membership interests were callable at the option of Entergy Holdings Company after ten years under the terms of the LLC agreement. The terms of the membership interests included certain financial covenants to which Entergy Holdings Company was subject, including the requirement to maintain a net worth of at least $1.75 billion. As discussed above in “Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida”, in May 2022, Entergy Holdings Company liquidated and distributed cash to Entergy Louisiana as holder of the 2,935,152.69 units of Class C preferred membership interests.

Entergy and Entergy Louisiana do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA and there is no recourse against Entergy or Entergy Louisiana in the event of a bond default.  To service the bonds, Entergy Louisiana collects a system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee.  Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as the billing and collection agent for the state.

Hurricane Gustav and Hurricane Ike

In September 2008, Hurricane Gustav and Hurricane Ike caused catastrophic damage to Entergy Louisiana’s service territory.  In December 2009, Entergy Louisiana entered into a stipulation agreement with the LPSC staff regarding its storm costs.  In March and April 2010, Entergy Louisiana and other parties to the proceeding filed with the LPSC an uncontested stipulated settlement that included Entergy Louisiana’s proposal to utilize Act 55 financing, which included a commitment to pass on to customers a minimum of $43.3 million of customer benefits through a prospective annual rate reduction of $8.7 million for five years.  In April 2010 the LPSC approved the settlement and subsequently issued financing orders and a ratemaking order intended to facilitate the implementation of the Act 55 financings.  In June 2010 the Louisiana State Bond Commission approved the Act 55 financing. The settlement agreement allowed for an adjustment to the credits if there was a change in the applicable federal or state income tax rate. As a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, and the lowering of the federal corporate income tax rate from 35% to 21%, the Louisiana Act 55 financing savings obligation regulatory liability related to Hurricane Gustav and Hurricane Ike was reduced by $2.7 million, with a corresponding increase to Other regulatory credits on the income statement. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.

In July 2010 the LCDA issued two series of bonds totaling $713.0 million under Act 55.  From the $702.7 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $290 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $412.7 million directly to Entergy Louisiana.  From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana
used $412.7 million to acquire 4,126,940.15 Class B preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 9% annual distribution rate. Distributions were payable quarterly commencing on September 15, 2010, and the membership interests had a liquidation price of $100 per unit. The preferred membership interests were callable at the option of Entergy Holdings Company after ten years under the terms of the LLC agreement.  The terms of the membership interests included certain financial covenants to which Entergy Holdings Company was subject, including the requirement to maintain a net worth of at least $1 billion. As discussed above in “Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida”, in May 2022, Entergy Holdings Company liquidated and distributed cash to Entergy Louisiana as holder of the 4,126,940.15 units of Class B preferred membership interests.

The bonds were repaid in 2022. Entergy and Entergy Louisiana did not report the bonds issued by the LCDA on their balance sheets because the bonds were the obligation of the LCDA, and there was no recourse against Entergy or Entergy Louisiana in the event of a bond default.  To service the bonds, Entergy Louisiana collected a system restoration charge on behalf of the LURC and remitted the collections to the bond indenture trustee.  Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as the billing and collection agent for the state.

Hurricane Katrina and Hurricane Rita

In August and September 2005, Hurricanes Katrina and Rita caused catastrophic damage to Entergy Louisiana’s service territory. In March 2008, Entergy Louisiana and the LURC filed at the LPSC an application requesting that the LPSC grant a financing order authorizing the financing of Entergy Louisiana storm costs, storm reserves, and issuance costs pursuant to Louisiana Act 55.  Entergy Louisiana also filed an application requesting LPSC approval for ancillary issues including the mechanism to flow charges and savings to customers via a storm cost offset rider.  In April 2008 the Louisiana Public Facilities Authority (LPFA), which is the issuer of the bonds pursuant to the Act 55 financing, approved requests for the Act 55 financing.  Also in April 2008, Entergy Louisiana and the LPSC staff filed with the LPSC an uncontested stipulated settlement that included Entergy Louisiana’s proposal under the Act 55 financing, which included a commitment to pass on to customers a minimum of $40 million of customer benefits through a prospective annual rate reduction of $8 million for five years.  The LPSC subsequently approved the settlement and issued two financing orders and one ratemaking order intended to facilitate implementation of the Act 55 financing.  In May 2008 the Louisiana State Bond Commission granted final approval of the Act 55 financing. The settlement agreement allowed for an adjustment to the credits if there was a change in the applicable federal or state income tax rate. As a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, and the lowering of the federal corporate income tax rate from 35% to 21%, the Louisiana Act 55 financing savings obligation regulatory liability related to Hurricanes Katrina and Rita was reduced by $22.3 million, with a corresponding increase to Other regulatory credits on the income statement. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.

In July 2008 the LPFA issued $687.7 million in bonds under the aforementioned Act 55.  From the $679 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $152 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $527 million directly to Entergy Louisiana.  From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $545 million, including $17.8 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 5,449,861.85 Class A preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 10% annual distribution rate.  In August 2008 the LPFA issued $278.4 million in bonds under the aforementioned Act 55.  From the $274.7 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $87 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $187.7 million directly to Entergy Louisiana.  From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $189.4 million, including $1.7 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 1,893,918.39 Class A preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 10% annual distribution rate.  Distributions were payable quarterly commencing on September 15, 2008 and had a
liquidation price of $100 per unit.  The preferred membership interests were callable at the option of Entergy Holdings Company after ten years under the terms of the LLC agreement.  The terms of the membership interests included certain financial covenants to which Entergy Holdings Company was subject, including the requirement to maintain a net worth of at least $1 billion.  In February 2012, Entergy Louisiana sold 500,000 of its Class A preferred membership units in Entergy Holdings Company to a third party. Those preferred membership units were subsequently repurchased by Entergy Holdings Company in March 2019. As discussed above in “Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida”, in May 2022, Entergy Holdings Company liquidated and distributed cash to Entergy Louisiana as holder of the remaining 6,843,780.24 units of Class A preferred membership interests.

The bonds were repaid in 2018. Entergy and Entergy Louisiana did not report the bonds issued by the LPFA on their balance sheets because the bonds were the obligation of the LPFA, and there was no recourse against Entergy or Entergy Louisiana in the event of a bond default.  To service the bonds, Entergy Louisiana collected a system restoration charge on behalf of the LURC and remitted the collections to the bond indenture trustee.  Entergy and Entergy Louisiana did not report the collections as revenue because Entergy Louisiana was merely acting as the billing and collection agent for the state.

Entergy Mississippi

Prior to June 2024, Entergy Mississippi had approval from the MPSC to collect a storm damage provision of $1.75 million per month. If Entergy Mississippi’s accumulated storm damage provision balance exceeded $15 million, the collection of the storm damage provision ceased until such time that the accumulated storm damage provision became less than $10 million. Entergy Mississippi’s storm damage provision balance had been less than $10 million since May 2019, and Entergy Mississippi had been billing the monthly storm damage provision since July 2019.

In December 2023, Entergy Mississippi filed a Notice of Storm Escrow Disbursement and Request for Interim Relief notifying the MPSC that Entergy Mississippi had requested disbursement of approximately $34.5 million of storm escrow funds from its restricted storm escrow account. The filing also requested authorization from the MPSC, on a temporary basis, that the $34.5 million of storm escrow funds be credited to Entergy Mississippi’s storm damage provision, pending the MPSC’s review of Entergy Mississippi’s storm-related costs, and that Entergy Mississippi continue to bill its monthly storm damage provision without suspension in the event the storm damage provision balance exceeded $15 million, in anticipation of a subsequent filing by Entergy Mississippi in this proceeding. The storm damage provision exceeded $15 million upon receipt of the storm escrow funds. Because the MPSC had not entered an order on Entergy Mississippi’s filing on the requested relief to continue billing this provision, Entergy Mississippi suspended billing the monthly storm damage provision effective with February 2024 bills.

In March 2024, Entergy Mississippi made a combined dual filing which included a notice of intent to make routine change in rates and schedules and a motion for determination relating to the above-described notice of storm escrow disbursement. The notice of intent proposed a new storm damage mitigation and restoration rider to supersede both the then-current storm damage rate schedule and the vegetation management rider schedule, in which the collection of both expenses would be combined. The proposal requested that the MPSC authorize Entergy Mississippi to collect approximately $5.2 million per month for vegetation management and a storm damage provision. Furthermore, if Entergy Mississippi’s accumulated vegetation management and storm damage provision balance were to exceed $70 million, collection under the storm damage mitigation and restoration rider would cease until such time that the accumulated vegetation management and storm damage provision would become less than $60 million.

The Mississippi Public Utilities Staff reviewed the storm-related costs submitted by Entergy Mississippi and found them prudent. In June 2024 the MPSC considered and unanimously granted the relief sought by Entergy Mississippi, including authorization to credit any remaining funds in the storm escrow account to Entergy
Mississippi’s storm damage provision and to close the storm escrow account and approving the new storm damage mitigation and restoration rider. Entergy Mississippi’s storm escrow account was liquidated in July 2024, and the new combined storm damage mitigation and restoration rider became effective with the July 2024 billing cycle. Additionally, Entergy Mississippi made a compliance filing to cease billing under the existing vegetation management rider schedule as of the same billing cycle.

Entergy New Orleans

Hurricane Ida

In August 2021, Hurricane Ida caused significant damage to Entergy New Orleans’s service area, including Entergy’s electrical grid. The storm resulted in widespread power outages, including the loss of 100% of Entergy New Orleans’s load and damage to distribution and transmission infrastructure, including the loss of connectivity to the eastern interconnection. In September 2021, Entergy New Orleans withdrew $39 million from its funded storm reserves. In June 2022, Entergy New Orleans filed an application with the City Council requesting approval and certification that storm restoration costs associated with Hurricane Ida of approximately $170 million, which included $11 million in estimated costs, were reasonable, necessary, and prudently incurred to enable Entergy New Orleans to restore electric service to its customers and to repair Entergy New Orleans’s electric utility infrastructure. In addition, estimated carrying costs through December 2022 related to Hurricane Ida restoration costs were $9 million. Also, Entergy New Orleans requested approval that the $39 million withdrawal from its funded storm reserve in September 2021 and $7 million in excess storm reserve escrow withdrawals related to Hurricane Zeta in October 2020 and prior miscellaneous storms were properly applied to Hurricane Ida storm restoration costs, the application of which reduced the amount to be recovered from Entergy New Orleans customers by $46 million.

Additionally, in February 2022, Entergy New Orleans and the LURC filed with the City Council a securitization application requesting that the City Council review Entergy New Orleans’s storm reserve and increase the storm reserve funding level to $150 million, to be funded through securitization. In August 2022 the City Council’s advisors recommended that the City Council authorize a single securitization bond issuance to fund Entergy New Orleans’s storm recovery reserves to an amount sufficient to: (1) allow recovery of all of Entergy New Orleans’s unrecovered storm recovery costs following Hurricane Ida, subject to City Council review and certification; (2) provide initial funding of storm recovery reserves for future storms to a level of $75 million; and (3) fund the storm recovery bonds’ upfront financing costs. In September 2022, Entergy New Orleans and the City Council’s advisors entered into an agreement in principle, which was approved by the City Council along with a financing order in October 2022, which authorized Entergy New Orleans and the LURC to proceed with a single securitization bond issuance of approximately $206 million (subject to further adjustment and review pursuant to the Final Issuance Advice Letter process set forth in the financing order), with $125 million of that total to be used for interim recovery, subject to City Council review and certification, to be allocated to unrecovered Hurricane Ida storm recovery costs; $75 million of that total to provide for a storm recovery reserve for future storms; and the remainder to fund the recovery of the storm recovery bonds’ upfront financing costs.

In December 2022, Entergy New Orleans and the LURC filed with the City Council the Final Issuance Advice Letter for a securitization bond issuance in the amount of $209.3 million, the final structuring, terms, and pricing of which were approved by the City Council in accordance with the financing order. Also in December 2022 the LCDA issued $209.3 million in bonds pursuant to the Louisiana Electric Utility Storm Recovery Securitization Act, Part V-B of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana Regular Session of 2021. The LCDA loaned $201.8 million of bond proceeds, net of certain debt service and issuance costs, to the LURC. The LURC used the proceeds to purchase from Entergy New Orleans the storm recovery property, which is the right to collect storm recovery charges sufficient to pay the storm recovery bonds and associated financing costs, and Entergy New Orleans deposited $200 million in a restricted storm reserve escrow account as a storm damage reserve for Entergy New Orleans and received directly $1.8 million in estimated upfront financing costs. Subsequently, Entergy New Orleans withdrew $125 million from the newly securitized
storm reserve to cover Hurricane Ida storm recovery costs, subject to a final determination from the City Council regarding the prudency of the storm recovery costs.

Entergy and Entergy New Orleans do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA, and there is no recourse against Entergy or Entergy New Orleans in the event of a bond default. To service the bonds, Entergy New Orleans collects a storm recovery charge on behalf of the LURC and remits the collections to the bond indenture trustee. Entergy and Entergy New Orleans do not report the collections as revenue because Entergy New Orleans is merely acting as the billing and collection agent for the LURC.

In August 2023 the City Council advisors issued a report recommending that the City Council find that Entergy New Orleans prudently incurred approximately $164.1 million in storm restoration costs and $7.5 million in carrying charges and that such costs have already been properly recovered by Entergy New Orleans through withdrawals from the storm reserve escrow account. The City Council advisors also recommended that the City Council find that approximately $1.2 million in storm restoration costs had already been recovered through Entergy New Orleans’s base rates and that approximately $0.9 million in unused credits be applied against future storm costs. In August 2023 the City Council hearing officer certified the evidentiary record. In December 2023 the City Council approved a resolution adopting the advisors’ report and recommendations.

Entergy Texas

Hurricane Laura, Hurricane Delta, and Winter Storm Uri

In August 2020 and October 2020, Hurricane Laura and Hurricane Delta caused extensive damage to Entergy Texas’s service area. In February 2021, Winter Storm Uri also caused damage to Entergy Texas’s service area. The storms resulted in widespread power outages, significant damage primarily to distribution and transmission infrastructure, and the loss of sales during the power outages. In April 2021, Entergy Texas filed an application with the PUCT requesting a determination that approximately $250 million of system restoration costs associated with Hurricane Laura, Hurricane Delta, and Winter Storm Uri, including approximately $200 million in capital costs and approximately $50 million in non-capital costs, were reasonable and necessary to enable Entergy Texas to restore electric service to its customers and Entergy Texas’s electric utility infrastructure. The filing also included the projected balance of approximately $13 million of a regulatory asset containing previously approved system restoration costs related to Hurricane Harvey. In September 2021 the parties filed an unopposed settlement agreement, pursuant to which Entergy Texas removed from the amount to be securitized approximately $4.3 million that will instead be charged to its storm reserve, $5 million related to no particular issue, of which Entergy Texas would be permitted to seek recovery in a future proceeding, and approximately $300 thousand related to attestation costs. In December 2021 the PUCT issued an order approving the unopposed settlement and determining system restoration costs of $243 million related to Hurricane Laura, Hurricane Delta, and Winter Storm Uri and the $13 million projected remaining balance of the Hurricane Harvey system restoration costs were eligible for securitization. The order also determines that Entergy Texas can recover carrying costs on the system restoration costs related to Hurricane Laura, Hurricane Delta, and Winter Storm Uri.

In July 2021, Entergy Texas filed with the PUCT an application for a financing order to approve the securitization of the system restoration costs that are the subject of the April 2021 application. In November 2021 the parties filed an unopposed settlement agreement supporting the issuance of a financing order consistent with Entergy Texas’s application and with minor adjustments to certain upfront and ongoing costs to be incurred to facilitate the issuance and serving of system restoration bonds. In January 2022 the PUCT issued a financing order consistent with the unopposed settlement. As a result of the financing order, Entergy Texas reclassified $153 million from utility plant to other regulatory assets.

In April 2022, Entergy Texas Restoration Funding II, LLC, a company wholly-owned and consolidated by Entergy Texas, issued $290.85 million of senior secured system restoration bonds (securitization bonds). With the
proceeds, Entergy Texas Restoration Funding II purchased from Entergy Texas the transition property, which is the right to recover from customers through a system restoration charge amounts sufficient to service the securitization bonds. Entergy Texas began cost recovery through the system restoration charge effective with the first billing cycle of May 2022 and the system restoration charge is expected to remain in place up to 15 years. See Note 5 to the financial statements for a discussion of the April 2022 issuance of the securitization bonds.
Entergy Louisiana [Member]  
Public Utilities Disclosure [Text Block] RATE AND REGULATORY MATTERS (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Regulatory Assets and Regulatory 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. In addition to the regulatory assets and liabilities that are specifically disclosed on the face of the balance sheets, the tables below provide detail of “Other regulatory assets” and “Other regulatory liabilities” that are included on Entergy’s and the Registrant Subsidiaries’ balance sheets as of December 31, 2024 and 2023 (as noted in footnotes to the tables, a portion of these regulatory assets and regulatory liabilities is classified as held for sale in the balance sheets as of December 31, 2024):

Other Regulatory Assets

Entergy
20242023
 (In Millions)
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
$1,387.6 $1,655.5 
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or shutdown of non-nuclear power plants and solar facilities (Note 9) (a)
1,358.7 1,285.0 
Removal costs (Note 9)
1,107.6 1,010.7 
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators and Note 5 - Securitization Bonds)
547.3 536.9 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
227.1 250.9 
Retail rate deferrals - recovered through formula rates or rate riders as rates are redetermined by retail regulators
195.1 248.6 
Retired electric and gas meters - recovered through retail rates as determined by retail regulators (Note 2 - Retail Rate Proceedings)
135.7 153.8 
Deferred COVID-19 costs - recovered through retail rates as determined by retail regulators (Note 2 - Retail Rate Proceedings)
104.0 118.0 
Unamortized loss on reacquired debt - recovered over term of debt
57.9 63.1 
Advanced metering system surcharge for residential customers - recovered through December 2029
39.7 20.2 
Formula rate plan historical year rate adjustment (Note 2 - Retail Rate Proceedings) (b)
15.5 — 
Pension & postretirement benefits expense deferral - recovered through retail rates (Note 2 - Retail Rate Proceedings and Note 11 - Entergy Texas Reserve)
15.0 32.7 
Rate case depreciation relate back deferral - recovered over a six-month period beginning January 2024 (Note 2 - Retail Rate Proceedings)
— 27.6 
Opportunity sales - (Note 2 - Entergy Arkansas Opportunity Sales Proceeding) (b)
— 131.8 
Other99.7 134.6 
Entergy Total (c)
$5,290.9 $5,669.4 
Entergy Arkansas
 20242023
 (In Millions)
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or shutdown of non-nuclear power plants and solar facilities (Note 9) (a)
$693.0 $639.1 
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
433.3 536.6 
Removal costs (Note 9)
337.9 319.7 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
75.8 84.1 
Deferred COVID-19 costs - recovered over a 10-year period through December 2033
35.1 39.0 
Retired electric meters - recovered over a 15-year period through March 2034
32.8 36.3 
Storm damage costs - recovered through retail rates
29.8 33.1 
Unamortized loss on reacquired debt - recovered over term of debt
18.6 19.9 
Formula rate plan historical year rate adjustment (Note 2 - Retail Rate Proceedings) (b)
15.5 — 
Retail rate deferrals - recovered through rate riders as rates are redetermined annually (b)
13.6 24.9 
ANO Fukushima and Flood Barrier costs - recovered through retail rates through February 2026 (b)
2.1 3.8 
Opportunity sales - (Note 2 - Entergy Arkansas Opportunity Sales Proceeding) (b)
— 131.8 
Other12.6 17.1 
Entergy Arkansas Total$1,700.1 $1,885.4 

Entergy Louisiana
 20242023
 (In Millions)
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or shutdown of non-nuclear power plants (Note 9) (a)
$421.5 $408.7 
Pension & postretirement costs (Note 11 - Qualified Pension Plans and Non-Qualified Pension Plans) (a)
367.7 412.0 
Removal costs (Note 9)
323.2 262.3 
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)
226.6 202.6 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
111.4 123.0 
Retired electric and gas meters - recovered over a 22-year period through July 2041
78.5 83.2 
Deferred COVID-19 costs - recovery period to be determined (Note 2 - Retail Rate Proceedings) (a)
47.8 47.8 
Unamortized loss on reacquired debt - recovered over term of debt
21.7 23.4 
Other48.5 85.9 
Entergy Louisiana Total (c)
$1,646.9 $1,648.9 
Entergy Mississippi
 20242023
(In Millions)
Removal costs (Note 9)
$184.8 $188.0 
Retail rate deferrals - recovered through formula rates or rate riders as rates are redetermined annually
162.5 192.8 
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
112.1 127.6 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
29.1 32.0 
Asset retirement obligation - recovery dependent upon timing of shutdown of non-nuclear power plants and solar facility (Note 9) (a)
9.4 6.8 
Unamortized loss on reacquired debt - recovered over term of debt
9.1 10.0 
Attorney General litigation costs - recovered over a six-year period through March 2026 (b)
6.0 10.9 
Other12.8 11.0 
Entergy Mississippi Total$525.8 $579.1 

Entergy New Orleans
 20242023
 (In Millions)
Removal costs (Note 9)
$62.5 $61.1 
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
22.9 41.4 
Retired electric and gas meters - recovered over a 12-year period through July 2031 (b)
13.5 15.5 
Gas cross-boring costs - recovered through formula rates as rates are redetermined by retail regulators
11.9 10.9 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
10.8 11.8 
Deferred COVID-19 costs - recovered over a five-year period through August 2028 (b)
10.2 13.0 
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators and Note 5 - Entergy New Orleans Securitization Bonds - Hurricane Isaac)
4.0 3.9 
Unamortized loss on reacquired debt - recovered over term of debt
0.5 0.8 
Other20.7 24.0 
Entergy New Orleans Total (c)
$157.0 $182.4 
Entergy Texas
 20242023
 (In Millions)
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators and Note 5 - Entergy Texas Securitization Bonds - Hurricane Laura, Hurricane Delta, and Winter Storm Uri)
$286.5 $297.3 
Removal costs (Note 9)
102.3 77.5 
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
62.9 85.6 
Advanced metering system surcharge for residential customers - recovered through December 2029
39.7 20.2 
Pension & postretirement benefits expense deferral - recovered through retail rates (Note 2 - Retail Rate Proceedings and Note 11 - Entergy Texas Reserve)
15.0 32.7 
Retired electric meters - recovered through retail rates (Note 2 - Retail Rate Proceedings)
10.9 18.8 
Neches and Sabine costs - recovered over a 10-year period through September 2028
9.2 11.6 
Unamortized loss on reacquired debt - recovered over term of debt
7.6 8.3 
Rate case depreciation relate back deferral - recovered over a six-month period beginning January 2024 (Note 2 - Retail Rate Proceedings)
— 27.6 
Other15.6 17.0 
Entergy Texas Total$549.7 $596.6 

System Energy
 20242023
 (In Millions)
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear unit (Note 9) (b)
$224.8 $222.0 
Pension & postretirement costs (Note 11 - Qualified Pension Plans and Other Postretirement Benefits) (a)
104.4 121.6 
Removal costs - recovered through depreciation rates (Note 9)
96.9 102.1 
Unamortized loss on reacquired debt - recovered over term of debt
0.4 0.7 
System Energy Total$426.5 $446.4 

(a)Does not earn a return on investment, but is offset by related liabilities.
(b)Does not earn a return on investment.
(c)Includes $35.4 million at Entergy, $8.9 million at Entergy Louisiana, and $23.7 million at Entergy New Orleans as of December 31, 2024 of regulatory assets related to the respective natural gas distribution businesses classified as held for sale and included within “Non-current assets held for sale” on the respective consolidated balance sheets. See Note 14 to the financial statements for further discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses and the classification as held for sale.
Other Regulatory Liabilities

Entergy
20242023
(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)
$2,262.5 $1,826.2 
Securitization financing savings obligation (Note 3)
371.3 405.2 
Retail rate rider over-recovery - refunded through formula rate or rate riders as rates are redetermined by retail regulators
164.9 142.7 
Credits from resolution of the 2016-2018 IRS audit (Note 3)
163.3 98.0 
Customer rate credits from global stipulated settlement with the LPSC - returned to customers September 2024 through August 2026 (Note 2)
121.7 — 
Refund from System Energy settlement with the LPSC - to be returned to customers January 2025 through August 2027 (Note 2)
75.8 — 
Deferred tax equity partnership earnings (Note 1)
69.9 57.9 
Vidalia purchased power agreement (Note 8)
67.4 82.5 
Refund from System Energy settlement with the City Council - returned to customers over a 25-year period beginning September 2024 (Note 2)
64.7 — 
Shorter-term financing interest earnings (Note 2 - Retail Rate Proceedings) (a)
48.9 36.8 
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and the FERC
44.4 44.4 
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)
40.9 44.3 
Refund from System Energy settlement with the City Council - return to customers to be determined (Note 2)
32.0 — 
Refund from System Energy settlement with the APSC - refunded through a rate rider as rates are re-determined periodically (Note 2)
8.2 93.0 
Complaints against System Energy - potential future refunds (Note 2)
— 177.9 
Other75.2 108.0 
Entergy Total (b)
$3,611.1 $3,116.9 

Entergy Arkansas
 20242023
 (In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)
$761.3 $621.6 
Deferred tax equity partnership earnings (Note 1)
32.4 27.4 
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually
27.9 10.6 
Refund from System Energy settlement with the APSC - refunded through a rate rider as rates are re-determined periodically (Note 2)
8.2 93.0 
Internal restructuring guaranteed customer credits - returned to customers over a six-year period through December 2024
— 6.6 
Other1.4 — 
Entergy Arkansas Total$831.2 $759.2 
Entergy Louisiana
 20242023
 (In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)
$798.4 $644.0 
Securitization financing savings obligation (Note 3)
371.3 405.2 
Customer rate credits from global stipulated settlement with the LPSC - returned to customers September 2024 through August 2026 (Note 2)
121.7 — 
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually
96.3 86.4 
Refund from System Energy settlement with the LPSC - to be returned to customers January 2025 through August 2027 (Note 2)
75.8 — 
Vidalia purchased power agreement (Note 8)
67.4 82.5 
Shorter-term financing interest earnings (Note 2 - Retail Rate Proceedings) (a)
48.9 36.8 
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)
40.9 44.3 
Hurricane Ida insurance proceeds - returned to customers August 2024 to July 2025
26.0 32.3 
Credits from resolution of the 2016-2018 IRS audit - returned to customers September 2024 through August 2025 (Note 3)
25.3 38.0 
Sale-leaseback and depreciation refunds - returned to customers September 2023 through August 2024
— 14.1 
Other21.7 24.1 
Entergy Louisiana Total (b)
$1,693.7 $1,407.7 

Entergy Mississippi
20242023
 (In Millions)
Deferred tax equity partnership earnings (Note 1)
$37.5 $30.5 
Retail rate rider over-recovery - refunded through formula rate or rate riders as rates are redetermined annually
12.2 2.4 
Other postretirement benefits (Note 11 - Entergy Mississippi Other Postretirement Benefits)
7.4 — 
Other2.4 0.8 
Entergy Mississippi Total$59.5 $33.7 
Entergy New Orleans
20242023
 (In Millions)
Credits from resolution of the 2016-2018 IRS audit - to be returned to customers over a 25-year period beginning January 2025 (Note 3)
$138.0 $60.0 
Refund from System Energy settlement with the City Council - returned to customers over a 25-year period beginning September 2024 (Note 2)
64.7 — 
Refund from System Energy settlement with the City Council - return to customers to be determined (Note 2)
32.0 — 
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually
16.3 20.1 
Sale-leaseback and depreciation refunds - returned to customers over a 10-year period beginning September 2023 (Note 2)
5.2 9.8 
Other4.5 0.5 
Entergy New Orleans Total (b)
$260.7 $90.4 

Entergy Texas
 20242023
 (In Millions)
Retail rate rider over-recovery - return to customers to be determined
$12.2 $23.8 
Retail refunds - return to customers to be determined
6.2 6.2 
Rate case settlement relate back - amortized over a six-month period beginning January 2024 (Note 2 - Retail Rate Proceedings)
— 10.3 
Other 0.3 2.7 
Entergy Texas Total$18.7 $43.0 

System Energy
 20242023
 (In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)
$702.8 $560.6 
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and the FERC
44.4 44.4 
Complaints against System Energy - potential future refunds (Note 2)
— 177.9 
System Energy Total$747.2 $782.9 

(a)Offset by related asset.
(b)Includes $1.6 million at Entergy, $1.2 million at Entergy Louisiana, and $0.4 million at Entergy New Orleans as of December 31, 2024 of regulatory liabilities related to the respective natural gas distribution businesses classified as held for sale and included within other non-current liabilities on the respective consolidated balance sheets. See Note 14 to the financial statements for further discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses and the classification as held for sale.
Regulatory activity regarding the Tax Cuts and Jobs Act

See the “Other Tax Matters - Tax Cuts and Jobs Act” section in Note 3 to the financial statements for discussion of the effects of the December 2017 enactment of the Tax Cuts and Jobs Act (Tax Act), including its effects on Entergy’s and the Registrant Subsidiaries’ regulatory asset/liability for income taxes.

Entergy Louisiana

In an electric formula rate plan settlement approved by the LPSC in April 2018, the parties agreed that Entergy Louisiana would return to customers one-half of its eligible unprotected excess deferred income taxes from May 2018 through December 2018 and return to customers the other half from January 2019 through August 2022. In addition, the settlement provided that in order to flow back to customers certain other tax benefits created by the Tax Act, Entergy Louisiana established a regulatory liability effective January 1, 2018 in the amount of $9.1 million per month to reflect these tax benefits already included in retail rates until new base rates under the formula rate plan were established in September 2018, and this regulatory liability was returned to customers over the September 2018 through August 2019 formula rate plan rate-effective period. The LPSC staff and intervenors in the settlement reserved the right to obtain data from Entergy Louisiana to confirm the determination of excess accumulated deferred income taxes resulting from the Tax Act and the analysis thereof as part of the formula rate plan review proceeding for the 2017 test year filing. As discussed below in “Retail Rate Proceedings - Filings with the LPSC (Entergy Louisiana) - Retail Rates - Electric - Formula Rate Plan Global Settlement”, a global settlement resolving the outstanding issues related to the 2017 formula rate plan filing was reached in October 2023 and approved by the LPSC in November 2023.

System Energy

In a filing made with the FERC in March 2018, System Energy proposed revisions to the Unit Power Sales Agreement to reflect the effects of the Tax Act. In the filing System Energy proposed to return identified quantities of unprotected excess accumulated deferred income taxes to its customers by the end of 2018. In May 2018 the FERC accepted System Energy’s proposed tax revisions with an effective date of June 1, 2018, subject to refund and the outcome of settlement and hearing procedures. Settlement discussions were terminated in April 2019, and a hearing was held in March 2020. In December 2022 the FERC issued an order requiring System Energy to compute the amount of excess accumulated deferred income taxes associated with a previously uncertain decommissioning tax position with consideration for the resolution of the tax position by the IRS. In February 2023, System Energy submitted its compliance filing. This matter was ultimately settled as a result of System Energy’s settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” below for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.
Fuel and purchased power cost recovery

The Utility operating companies are allowed to recover fuel and purchased power costs through fuel mechanisms included in electric and gas rates that are recorded as fuel cost recovery revenues.  The difference between revenues collected and the current fuel and purchased power costs is generally recorded as “Deferred fuel costs” on the Utility operating companies’ financial statements.  The table below shows the amount of deferred fuel costs as of December 31, 2024 and 2023 that each Utility operating company expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.

 20242023
 (In Millions)
Entergy Arkansas
($45.2)($88.3)
Entergy Louisiana (a) (b)$163.4 $192.9 
Entergy Mississippi($126.3)($130.6)
Entergy New Orleans (a) (b)$8.0 $10.2 
Entergy Texas($59.3)$139.0 

(a)Includes $168.1 million in both years for Entergy Louisiana and $4.1 million in both years for Entergy New Orleans of fuel, purchased power, and capacity costs, which do not currently earn a return on investment and whose recovery periods are indeterminate but are expected to be recovered over a period greater than twelve months.
(b)Includes $0.7 million at Entergy Louisiana and $4.9 million at Entergy New Orleans as of December 31, 2024 of deferred fuel assets related to the respective natural gas distribution businesses classified as held for sale and included within “Current assets held for sale” on the respective consolidated balance sheets. See Note 14 to the financial statements for further discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses and the classification as held for sale.

Entergy Arkansas

Energy Cost Recovery Rider

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

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

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

In March 2018, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01547 per kWh to $0.01882 per kWh. The Arkansas Attorney General filed a response to Entergy Arkansas’s annual redetermination filing requesting that the APSC suspend the proposed tariff to investigate the amount of the redetermination or, alternatively, to allow recovery subject to refund. Among the reasons the Attorney General cited for suspension were questions pertaining to how Entergy Arkansas forecasted sales and potential implications of the Tax Cuts and Jobs Act. Entergy Arkansas replied to the Attorney General’s filing and stated that, to the extent there are questions pertaining to its load forecasting or the operation of the energy cost recovery rider, those issues exceed the scope of the instant rate redetermination. Entergy Arkansas also stated that potential effects of the Tax Cuts and Jobs Act are appropriately considered in the APSC’s separate proceeding regarding potential implications of the tax law. The APSC general staff filed a reply to the Attorney General’s filing and agreed that Entergy Arkansas’s filing complied with the terms of the energy cost recovery rider. The redetermined rate became effective with the first billing cycle of April 2018. Subsequently in April 2018 the APSC issued an order declining to suspend Entergy Arkansas’s energy cost recovery rider rate and declining to require further investigation at that time of the issues suggested by the Attorney General in the proceeding. Following a period of discovery, the Attorney General filed a supplemental response in October 2018 raising new issues with Entergy Arkansas’s March 2018 rate redetermination and asserting that $45.7 million of the increase should be collected subject to refund pending further investigation. Entergy Arkansas filed to dismiss the Attorney General’s supplemental response, the APSC general staff filed a motion to strike the Attorney General’s filing, and the Attorney General filed a supplemental response disputing Entergy Arkansas and the APSC staff’s filing. Applicable APSC rules and processes authorize its general staff to initiate periodic audits of Entergy Arkansas’s energy cost recovery rider. In late-2018 the APSC general staff notified Entergy Arkansas it initiated an audit of the 2017 fuel costs. The time in which the audit will be complete is uncertain at this time.

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

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

In March 2024, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease in the rate from $0.01883 per kWh to $0.00882 per kWh. Due to a change in law in the State of Arkansas, the annual redetermination included $9 million, recorded as a credit to fuel expense in first quarter 2024, for recovery attributed to net metering costs in 2023. The primary reason for the rate decrease is a large over-recovered balance as a result of lower natural gas prices in 2023. To mitigate the effect of projected increases in natural gas prices in 2024, Entergy Arkansas adjusted the over-recovered balance included in the March 2024 annual redetermination filing by $43.7 million. This adjustment is expected to reduce the rate change that will be reflected in the 2025 energy cost rate redetermination. The redetermined rate of $0.00882 per kWh became effective with the first billing cycle in April 2024 through the normal operation of the tariff.

Entergy Louisiana

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

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

In March 2020 the LPSC staff provided notice of an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2016 through 2019. The LPSC staff issued its audit report in September 2021, and although certain internal record keeping recommendations were made, the LPSC staff did not recommend any disallowances. The next step is for the LPSC to review the report, but there is not a deadline for the review.

In January 2023 the LPSC staff provided notice of an audit of Entergy Louisiana’s purchased gas adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s purchased gas adjustment clause for the period from 2021 through 2022. Discovery is ongoing, and no audit report has been filed.
In January 2023 the LPSC staff provided notice of an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2020 through 2022. Discovery is ongoing, and no audit report has been filed.

Entergy Mississippi

Entergy Mississippi’s rate schedules include an energy cost recovery rider and a power management rider, both of which are adjusted annually to reflect accumulated over- or under-recoveries. Entergy Mississippi recovers fuel and purchased energy costs through its energy cost recovery rider and recovers costs associated with natural gas hedging and capacity payments through its power management rider. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.

In November 2021, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an under-recovery of approximately $80.6 million as of September 30, 2021. In December 2021, at the request of the MPSC, Entergy Mississippi submitted a proposal to mitigate the impact of rising fuel costs on customer bills during 2022. Entergy Mississippi proposed that the deferred fuel balance as of December 31, 2021, which was $121.9 million, be amortized over three years and that the MPSC authorize Entergy Mississippi to apply its weighted-average cost of capital as the carrying cost for the unamortized fuel balance. In January 2022 the MPSC approved the amortization of $100 million of the deferred fuel balance over two years and authorized Entergy Mississippi to apply its weighted-average cost of capital as the carrying cost for the unamortized fuel balance. The MPSC approved the proposed energy cost factor effective for February 2022 bills.

See “Complaints Against System Energy - System Energy Settlement with the MPSC” below for discussion of the settlement agreement filed with the FERC in June 2022. The settlement, which was approved by the FERC in November 2022, provided for a refund of $235 million from System Energy to Entergy Mississippi. In July 2022 the MPSC directed the disbursement of settlement proceeds, ordering Entergy Mississippi to provide a one-time $80 bill credit to each of its approximately 460,000 retail customers to be effective during the September 2022 billing cycle and to apply the remaining proceeds to Entergy Mississippi’s under-recovered deferred fuel balance. In accordance with the MPSC’s directive, Entergy Mississippi provided approximately $36.7 million in customer bill credits as a result of the settlement. In November 2022, Entergy Mississippi applied the remaining settlement proceeds in the amount of approximately $198.3 million to Entergy Mississippi’s under-recovered deferred fuel balance.

Entergy Mississippi had a deferred fuel balance of approximately $291.7 million under the energy cost recovery rider as of July 31, 2022, along with an over-recovery balance of $51.1 million under the power management rider. Without further action, Entergy Mississippi anticipated a year-end deferred fuel balance of approximately $200 million after application of a portion of the System Energy settlement proceeds, as discussed above. In September 2022, Entergy Mississippi filed for interim adjustments under both the energy cost recovery rider and the power management rider. Entergy Mississippi proposed five monthly incremental adjustments to the net energy cost factor designed to collect the under-recovered fuel balance as of July 31, 2022 and to reflect the recovery of a higher natural gas price. Entergy Mississippi also proposed five monthly incremental adjustments to the power management adjustment factor designed to flow through to customers the over-recovered power management rider balance as of July 31, 2022. In October 2022 the MPSC approved modified interim adjustments to Entergy Mississippi’s energy cost recovery rider and power management rider. The MPSC approved dividing the energy cost recovery rider interim adjustment into two components that would allow Entergy Mississippi to (1) recover a natural gas fuel rate that is better aligned with current prices; and (2) recover the estimated under-recovered deferred fuel balance as of September 30, 2022 over a period of 20 months. The MPSC approved six monthly incremental adjustments to the net energy cost factor designed to reflect the recovery of a higher natural gas price. The MPSC also approved six monthly incremental adjustments to the power management adjustment factor designed to flow through to customers the over-recovered power management rider balance. In accordance
with the order of the MPSC, Entergy Mississippi did not file an annual redetermination of the energy cost recovery rider or the power management rider in November 2022.

In June 2023 the MPSC approved the joint stipulation agreement between Entergy Mississippi and the Mississippi Public Utilities Staff for Entergy Mississippi’s 2023 formula rate plan filing. The stipulation directed Entergy Mississippi to make a compliance filing to revise its power management cost adjustment factor, to revise its grid modernization cost adjustment factor, and to include a revision to reduce the net energy cost factor to a level necessary to reflect an average natural gas price of $4.50 per MMBtu. The MPSC approved the compliance filing in June 2023, effective for July 2023 bills. See “Retail Rate Proceedings - Filings with the MPSC (Entergy Mississippi) - Retail Rates - 2023 Formula Rate Plan Filing” below for further discussion of the 2023 formula rate plan filing and the joint stipulation agreement.

In November 2023 Entergy Mississippi filed its annual redeterminations of the energy cost factor and the power management cost adjustment factor. The calculation of the annual factor for the energy cost recovery rider included a projected over-recovery balance of approximately $142 million at the end of January 2024. The calculation of the annual factor for the power management rider included a projected under-recovery of $47 million at the end of January 2024. In January 2024 the MPSC approved the proposed energy cost factor and the proposed power management cost factor effective for February 2024 bills.

In June 2024 the MPSC approved the joint stipulation agreement between Entergy Mississippi and the Mississippi Public Utilities Staff for Entergy Mississippi’s 2024 formula rate plan filing. The 2024 formula rate plan filing included the conclusion of the modified interim adjustments to Entergy Mississippi’s energy cost recovery rider and power management rider, which were approved in October 2022 and allowed Entergy Mississippi to recover certain under-collected fuel balances, effective for July 2024 bills. The stipulation provided for Entergy Mississippi to reduce its net energy cost factor. See “Retail Rate Proceedings - Filings with the MPSC (Entergy Mississippi) - Retail Rates - 2024 Formula Rate Plan Filing” below for further discussion of the 2024 formula rate plan filing and the joint stipulation agreement.

In November 2024, Entergy Mississippi filed its annual redeterminations of the energy cost factor and the power management cost adjustment factor. The calculation of the annual factor for the energy cost recovery rider included a projected over-recovery balance of approximately $144.6 million as of September 2024. The calculation of the annual factor for the power management rider included a projected under-recovery of $60.1 million as of September 2024. In January 2025 the MPSC approved a revised energy cost factor, effective for February 2025 bills, that did not reflect the fuel savings associated with Entergy Mississippi’s incremental increase in its share of capacity and energy in connection with Entergy Mississippi’s assumption of Entergy Louisiana’s entitlements to Grand Gulf capacity and energy, which was subject to the MPSC’s review at such time. In February 2025 the MPSC approved Entergy Mississippi’s notice of intent for Entergy Mississippi’s assumption of Entergy Louisiana’s entitlements to Grand Gulf capacity and energy, with associated fuel savings to be reflected in Entergy Mississippi’s energy cost recovery rider, effective for March 2025 bills. Additionally, in February 2025 the MPSC approved the proposed power management cost adjustment factor, effective for March 2025 bills.

Entergy New Orleans

Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.

Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.
Entergy Texas

Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, not recovered in base rates.  Historically, semi-annual revisions of the fixed fuel factor have been made in March and September based on the market price of natural gas and changes in fuel mix.  The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. In 2023 the Texas legislature modified the Texas Utilities Code to provide that material over- and under-recovered fuel balances are to be refunded or surcharged through interim fuel adjustments and that fuel reconciliations must be filed at least once every two years. Entergy Texas expects the PUCT to undertake a rulemaking to effectuate the new legislation in 2025.

In May 2022, Entergy Texas filed an application with the PUCT to implement an interim fuel surcharge to collect the cumulative under-recovery of approximately $51.7 million, including interest, of fuel and purchased power costs incurred from May 1, 2020 through December 31, 2021. The under-recovery balance was primarily attributable to the impacts of Winter Storm Uri, including historically high natural gas prices, partially offset by settlements received by Entergy Texas from MISO related to Hurricane Laura. Entergy Texas proposed that the interim fuel surcharge be assessed over a period of six months beginning with the first billing cycle after the PUCT issues a final order, but no later than the first billing cycle of September 2022. Also in May 2022, the PUCT referred the proceeding to the State Office of Administrative Hearings. In July 2022, Entergy Texas filed on behalf of the parties an unopposed settlement resolving all issues in the proceeding. In addition, Entergy Texas filed on behalf of the parties a motion to admit evidence, to approve interim rates as requested in the initial application, and to remand the proceeding to the PUCT to consider the unopposed settlement. In August 2022 the ALJ with the State Office of Administrative Hearings issued an order granting Entergy Texas’s motion, approving interim rates effective with the first billing cycle of September 2022, and remanding the case to the PUCT for final approval. The interim fuel surcharge was approved by the PUCT in January 2023.

In September 2022, Entergy Texas filed an application with the PUCT to reconcile its fuel and purchased power costs for the period from April 2019 through March 2022. During the reconciliation period, Entergy Texas incurred approximately $1.7 billion in eligible fuel and purchased power expenses, net of certain revenues credited to such expenses and other adjustments. As of the end of the reconciliation period, Entergy Texas’s cumulative under-recovery balance was approximately $103.1 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning April 2022, pending future surcharges or refunds as approved by the PUCT. In November 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In July 2023, Entergy Texas filed an unopposed settlement, supporting testimony, and an agreed motion to admit evidence and remand the proceeding to the PUCT. Pursuant to the unopposed settlement, Entergy Texas would receive no disallowance of fuel costs incurred over the three-year reconciliation period and retain $9.3 million in margins from off-system sales made during the reconciliation period, resulting in a cumulative under-recovery balance of approximately $99.7 million, including interest, as of the end of the reconciliation period. In July 2023 the ALJ with the State Office of Administrative Hearings granted the motion to admit evidence and remanded the proceeding to the PUCT for consideration of the unopposed settlement. The PUCT approved the settlement in September 2023.

In September 2024, Entergy Texas filed an application with the PUCT to reconcile its fuel and purchased power costs for the period from April 2022 through March 2024. During the reconciliation period, Entergy Texas incurred approximately $1.6 billion in eligible fuel and purchased power expenses to generate and purchase electricity to serve its customers, net of certain revenues credited to such expenses and other adjustments. Entergy Texas’s cumulative under-recovery balance for the reconciliation period was approximately $30 million, including interest, which Entergy Texas requested authority to carry over as part of the cumulative fuel balance for the subsequent reconciliation period beginning April 2024. In November 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 procedural schedule, with a hearing on the merits scheduled for May 2025. A PUCT decision is expected in third quarter 2025.
In December 2024, Entergy Texas filed an application with the PUCT to implement an interim fuel refund of $45.5 million, including interest. Entergy Texas proposed that the interim fuel refund be implemented over a three-month period beginning with the first billing cycle in February 2025 for residential and other small customers and through a one-time credit, or surcharge depending on historical usage for the respective customer, for certain transmission voltage level and seasonal agricultural customers in February 2025. Also in December 2024 the PUCT referred the proceeding to the State Office of Administrative Hearings. In January 2025 the ALJ with the State Office of Administrative Hearings issued an order approving the interim fuel refund consistent with Entergy Texas’s application and, because no hearing was requested in the proceeding, dismissing the case from the State Office of Administrative Hearings and the PUCT.
Retail Rate Proceedings

Filings with the APSC (Entergy Arkansas)

Retail Rates

2022 Formula Rate Plan Filing

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

2023 Formula Rate Plan Filing

In July 2023, Entergy Arkansas filed with the APSC its 2023 formula rate plan filing to set its formula rate for the 2024 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2024 and a netting adjustment for the historical year 2022. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2024 projected year was 8.11% resulting in a revenue deficiency of $80.5 million. The earned rate of return on common equity for the 2022 historical year was 7.29% resulting in a $49.8 million netting adjustment. The total proposed revenue change for the 2024 projected year and 2022 historical year netting adjustment was $130.3 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $88.6 million. The APSC general staff and intervenors filed their errors and objections in October 2023, proposing certain adjustments, including the APSC general staff’s update to annual filing year revenues which lowers the constraint to $87.7 million. Entergy Arkansas filed its rebuttal in October 2023. In October 2023, Entergy
Arkansas filed with the APSC a settlement agreement reached with other parties resolving all issues in the proceeding, none of which affected Entergy Arkansas’s requested recovery up to the constraint of $87.7 million. The settlement agreement provided for amortization of the approximately $39 million regulatory asset for costs associated with the COVID-19 pandemic over a 10-year period as well as recovery of $34.9 million related to the resolution of the 2016 and 2017 IRS audits from previous tax positions that are no longer uncertain, partially offset by $24.7 million in excess accumulated deferred income taxes from reductions in state income tax rates, each before consideration of their respective tax gross-up. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit and the State of Arkansas corporate income tax rate changes. In December 2023 the APSC approved the settlement agreement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2024.

2024 Formula Rate Plan Filing

In July 2024, Entergy Arkansas filed with the APSC its 2024 formula rate plan filing to set its formula rate for the 2025 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the 2025 projected year and a netting adjustment for the 2023 historical year. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2025 projected year was 8.43% resulting in a revenue deficiency of $69.5 million. The earned rate of return on common equity for the 2023 historical year was 7.48% resulting in a $33.1 million netting adjustment. The total proposed revenue change for the 2025 projected year and 2023 historical year netting adjustment is $102.6 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $82.6 million. The APSC general staff and intervenors filed their errors and objections in October 2024, proposing certain adjustments, including the APSC general staff’s update to annual filing year revenues that increases the constraint to $83.5 million. Entergy Arkansas filed its rebuttal in October 2024, and later in October 2024 the parties submitted a joint issues list and stipulations setting forth the disputed issues and the noncontested issues. In December 2024 the APSC approved the parties’ stipulations without modification, approved Entergy Arkansas’s adjustment with respect to storm costs, directed Entergy Arkansas to adjust its projected year distribution reliability capital closings, and deferred the recoverability of Entergy Arkansas’s opportunity sales legal fees until the next general rate case. Also in December 2024 the APSC approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2025. As a result of the proceeding, the total revenue change was $82.7 million, including a $63.7 million increase for the 2025 projected year and a $31.4 million netting adjustment for the 2023 historical year. In fourth quarter 2024, Entergy Arkansas recorded a regulatory asset of $15.5 million to reflect the amount of the 2023 historical year netting adjustment that it expects to collect from its customers during the 2025 rate effective period. Pursuant to the terms of the parties’ stipulations, Entergy Arkansas made a filing with the APSC in January 2025 to refund customers $30.1 million in excess accumulated deferred income taxes resulting from the reduction in the State of Arkansas’s income tax rate from 4.8% to 4.3% in 2024. Entergy Arkansas will make this refund over a 24-month period effective with the first billing cycle of February 2025.

Grand Gulf Credit Rider

In June 2024, Entergy Arkansas filed with the APSC a tariff to provide retail customers a credit resulting from the terms of the settlement agreement between Entergy Arkansas, System Energy, additional named Entergy parties, and the APSC pertaining to System Energy’s billings for wholesale sales of energy and capacity from the Grand Gulf nuclear plant. See “Complaints Against System Energy - System Energy Settlement with the APSC” below for discussion of the settlement. In July 2024 the APSC approved the tariff, under which Entergy Arkansas will refund to retail customers a total of $100.6 million. To date, Entergy Arkansas has refunded $92.3 million of the total through one-time bill credits during the August 2024 billing cycle and is finalizing plans for the refund of the remaining regulatory liability balance.
Filings with the LPSC (Entergy Louisiana)

Retail Rates - Electric

2020 Formula Rate Plan Filing

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

In November 2023 the LPSC approved a global settlement which resolved all outstanding issues related to the 2017, 2018, and 2019 formula rate plan filings and resolved certain issues with respect to the 2020 and 2021 formula rate plan filings. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” below for further discussion.

2021 Formula Rate Plan Filing

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

In November 2023 the LPSC approved a global settlement which resolved all outstanding issues related to the 2017, 2018, and 2019 formula rate plan filings and resolved certain issues with respect to the 2020 and 2021
formula rate plan filings. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” below for further discussion.

2022 Formula Rate Plan Filing

In May 2023, Entergy Louisiana filed its formula rate plan evaluation report for its 2022 calendar year operations. The 2022 test year evaluation report produced an earned return on common equity of 8.33%, requiring an approximately $70.7 million increase to base rider revenue. Due to a cap for the 2021 and 2022 test years, however, base rider formula rate plan revenues were only increased by approximately $4.9 million, resulting in a revenue deficiency of approximately $65.9 million and providing for prospective return on common equity opportunity of approximately 8.38%. Other changes in formula rate plan revenue driven by increases in capacity costs, primarily legacy capacity costs, additions eligible for recovery through the transmission recovery mechanism and distribution recovery mechanism, and higher sales during the test period were offset by reductions in net MISO costs as well as credits for FERC-ordered refunds. Also included in the 2022 test year distribution recovery mechanism revenue requirement was a $6 million credit relating to the distribution recovery mechanism performance accountability standards and requirements. In total, the net increase in formula rate plan revenues, including base formula rate plan revenues inside the formula rate plan bandwidth and subject to the cap, as well as other formula rate plan revenues outside of the bandwidth, was $85.2 million. In August 2023 the LPSC staff filed a list of objections/reservations, including outstanding issues from the test years 2017-2021 formula rate plan filings, the calculation of certain refunds from System Energy, and certain calculations relating to the tax reform adjustment mechanism. Subject to LPSC review, the resulting net increase in formula rate plan revenues of $85.2 million became effective for bills rendered during the first billing cycle of September 2023, subject to refund. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” below for further discussion.

2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request

In August 2023, Entergy Louisiana filed an application for approval of a regulatory blueprint necessary for it to strengthen the electric grid for the State of Louisiana, which contained a dual-path request to update rates through either: (1) extension of Entergy Louisiana’s current formula rate plan (with certain modifications) for three years (the Rate Mitigation Proposal), which is Entergy Louisiana’s recommended path; or (2) implementation of rates resulting from a cost-of-service study (the Rate Case path). The application complied with Entergy Louisiana’s previous formula rate plan extension order requiring that for Entergy Louisiana to obtain another extension of its formula rate plan that included a rate reset, Entergy Louisiana would need to submit a full cost-of-service rate case. Entergy Louisiana’s filing supported the need to extend Entergy Louisiana’s formula rate plan with credit supportive mechanisms needed to facilitate investment in the distribution, transmission, and generation functions.

In July 2024, Entergy Louisiana reached an agreement in principle with the LPSC staff and the intervenors in the proceeding and filed with the LPSC a joint motion to suspend the procedural schedule to allow for all parties to finalize a stipulated settlement agreement.

In August 2024, Entergy Louisiana and the LPSC staff jointly filed a global stipulated settlement agreement for consideration by the LPSC with key terms as follows:

•continuation of the formula rate plan for 2024-2026 (test years 2023-2025);
•a base formula rate plan revenue increase of $120 million for test year 2023, effective for rates beginning September 2024;
•a $140 million cumulative cap on base formula rate plan revenue increases, if needed, for test years 2024 and 2025, excluding outside the bandwidth items;
•$184 million of customer rate credits to be given over two years, including increasing customer sharing of income tax benefits resulting from the 2016-2018 IRS audit, to resolve any remaining disputed issues stemming from formula rate plan test years prior to test year 2023, including but not limited to the investigation into Entergy Services costs billed to Entergy Louisiana. As discussed in Note 3 to the financial statements, a $38 million regulatory liability was recorded in 2023 in connection with the 2016-2018 IRS audit;
•$75.5 million of customer rate credits, as provided for in the System Energy global settlement, to be credited over three years subject to and conditioned upon FERC approval of the System Energy global settlement, which was approved in November 2024. See “Complaints Against System Energy – System Energy Settlement with the LPSC” below for further details of the System Energy global settlement;
•$5.8 million of customer rate credits provided for in the Entergy Louisiana formula rate plan global settlement agreement approved by the LPSC in November 2023 credited over one year. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement;
•an increase in the allowed midpoint return on common equity from 9.5% to 9.7%, with a bandwidth of 40 basis points above and below the midpoint, for the extended term of the formula rate plan, except that for test year 2023 in which the authorized return on common equity shall have no bearing on the change in base formula rate plan revenue described above and, for test year 2024, any earnings above the authorized return on common equity shall be returned to customers through a credit;
•an increase in nuclear depreciation rates by $15 million in each of the 2023, 2024, and 2025 test years outside of the formula rate plan bandwidth calculation; and
•for the transmission recovery mechanism and the distribution recovery mechanism, no change to the existing floors, but the caps for both would be $350 million for test year 2023, $375 million for test year 2024, and $400 million for test year 2025. Transmission projects filed with the LPSC will be exempt from the transmission recovery mechanism cap.

The global stipulated settlement agreement was unanimously approved by the LPSC in August 2024 and an order was issued by the LPSC in September 2024 reflecting the approval of the settlement.

Based on the July 2024 agreement in principle, in second quarter 2024 Entergy Louisiana recorded expenses of $151 million ($112 million net-of-tax) primarily consisting of regulatory charges to reflect the effects of the agreement in principle.

Formula Rate Plan Global Settlement

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

2023 Formula Rate Plan Filing

In August 2024, pursuant to the global stipulated settlement agreement, Entergy Louisiana filed its formula rate plan evaluation report for its 2023 calendar year operations. Consistent with the global stipulated settlement agreement, the filing reflected a 9.7% allowed return on common equity with a bandwidth of 40 basis points above and below the midpoint. For the 2023 test year, however, the bandwidth provisions of the formula rate plan were
temporarily suspended and, pursuant to the terms of the global stipulated settlement agreement, Entergy Louisiana implemented the September 2024 formula rate plan rate adjustments effective with the first billing cycle of September 2024. Those adjustments included a $120 million increase in base rider formula rate plan revenue and a $101.8 million one-time incremental net decrease consistent with the terms of the global stipulated settlement. The formula rate plan rate adjustments reflected in the evaluation report also include a redetermination of the transmission recovery mechanism, the distribution recovery mechanism, the additional capacity mechanism, the tax adjustment mechanism, the MISO cost recovery mechanism, and other one-time adjustments. In January 2025, Entergy Louisiana and the LPSC filed a joint report indicating that no disputed issues remained in the proceeding and requesting that the LPSC issue an order accepting Entergy Louisiana’s evaluation report and, ultimately, resolving this matter. Entergy Louisiana expects a decision on the joint report in first quarter 2025.

Investigation of Costs Billed by Entergy Services

In November 2018 the LPSC issued a notice of proceeding initiating an investigation into costs incurred by Entergy Services that are included in the retail rates of Entergy Louisiana. As stated in the notice of proceeding, the LPSC observed an increase in capital construction-related costs incurred by Entergy Services. Discovery was issued and included efforts to seek highly detailed information on a broad range of matters unrelated to the scope of the audit. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” above for further discussion.

COVID-19 Orders

In April 2020 the LPSC issued an order authorizing utilities to record as a regulatory asset expenses incurred from the suspension of disconnections and collection of late fees imposed by LPSC orders associated with the COVID-19 pandemic. In April 2023, Entergy Louisiana filed an application proposing to utilize approximately $1.6 billion in certain low interest debt to generate earnings to apply toward the reduction of the COVID-19 regulatory asset, as well as to conduct additional outside right-of-way vegetation management activities and fund the minor storm reserve account. In that filing, Entergy Louisiana proposed to delay repayment of certain shorter-term first mortgage bonds that were issued to finance storm restoration costs until the costs could be securitized, and to invest the funds that otherwise would be used to repay those bonds in the money pool to take advantage of the spread between prevailing interest rates on investments in the money pool and the interest rates on the bonds. The LPSC approved Entergy Louisiana’s requested relief in June 2023. In November 2024, Entergy Louisiana submitted a filing to the LPSC requesting that the LPSC review Entergy Louisiana’s computation of the COVID-19 regulatory asset as well as Entergy Louisiana’s proposal to offset the regulatory asset against the interest earned on the short-term debt funds, resulting in no increased costs to customers. At the time of the filing, Entergy Louisiana had a regulatory asset of $47.8 million for costs associated with the COVID-19 pandemic. As of December 31, 2024, Entergy Louisiana had a regulatory liability of $48.9 million for the deferred earnings related to the approximately $1.6 billion in low interest debt, which had been fully repaid by August 2024. In granting Entergy Louisiana’s requested relief in June 2023, the LPSC ordered that any amount of earnings exceeding the amount of the COVID-19 regulatory asset be transferred to Entergy Louisiana’s storm reserve escrow account.

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 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.

Filings with the MPSC (Entergy Mississippi)

Retail Rates

2022 Formula Rate Plan Filing

In March 2022, Entergy Mississippi submitted its formula rate plan 2022 test year filing and 2021 look-back filing showing Entergy Mississippi’s earned return for the historical 2021 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2022 calendar year to be below the formula rate plan bandwidth. The 2022 test year filing showed a $69 million rate increase was necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.70% return on rate base, within the formula rate plan bandwidth. The change in formula rate plan revenues, however, was capped at 4% of retail revenues, which equated to a revenue change of $48.6 million. The 2021 look-back filing compared actual 2021 results to the approved benchmark return on rate base and reflected the need for a $34.5 million interim increase in formula rate plan revenues. In fourth quarter 2021, Entergy Mississippi recorded a regulatory asset of $19 million to reflect the then-current estimate in connection with the look-back feature of the formula rate plan. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $24.3 million interim rate increase, reflecting a cap equal to 2% of 2021 retail revenues, effective in April 2022. With the implementation of the interim formula rate plan rates, Entergy Mississippi began recovery of the bad debt expense deferral resulting from the COVID-19 pandemic over a three-year period.

In June 2022, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed the 2022 test year filing that resulted in a total rate increase of $48.6 million. Pursuant to the joint stipulation, Entergy Mississippi’s 2021 look-back filing reflected an earned return on rate base of 5.99% in calendar year 2021, which was below the look-back bandwidth, resulting in a $34.3 million increase in the formula rate plan revenues on an interim basis through June 2023. In July 2022 the MPSC approved the joint stipulation with rates effective in August 2022. In July 2022, Entergy Mississippi recorded regulatory credits of $22.6 million to reflect the effects of the joint stipulation.
In July 2022 the MPSC directed Entergy Mississippi to flow $14.1 million of the power management rider over-recovery balance to customers beginning in August 2022 through December 2022 to mitigate the bill impact of the increase in formula rate plan revenues.

2023 Formula Rate Plan Filing

In March 2023, Entergy Mississippi submitted its formula rate plan 2023 test year filing and 2022 look-back filing showing Entergy Mississippi’s earned return on rate base for the historical 2022 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2023 calendar year to be below the formula rate plan bandwidth. The 2023 test year filing showed a $39.8 million rate increase was necessary to reset Entergy Mississippi’s earned return on rate base to the specified point of adjustment of 6.67%, within the formula rate plan bandwidth. The 2022 look-back filing compared actual 2022 results to the approved benchmark return on rate base and reflected the need for a $19.8 million temporary increase in formula rate plan revenues, including the refund of a $1.3 million over-recovery resulting from the demand-side management costs true-up for 2022. In fourth quarter 2022, Entergy Mississippi recorded a regulatory asset of $18.2 million in connection with the look-back feature of the formula rate plan to reflect that the 2022 estimated earned return was below the formula rate plan bandwidth. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $27.9 million interim rate increase, reflecting a cap equal to 2% of 2022 retail revenues, effective in April 2023.

In May 2023, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed a 2023 test year filing resulting in a total revenue increase of $26.5 million for 2023. Pursuant to the joint stipulation, Entergy Mississippi’s 2022 look-back filing reflected an earned return on rate base of 6.10% in calendar year 2022, which was below the look-back bandwidth, resulting in a $19.0 million increase in the formula rate plan revenues on an interim basis through June 2024. Entergy Mississippi recorded a regulatory credit of $0.8 million in June 2023 to reflect the increase in the look-back regulatory asset. In addition, certain long-term service agreement and conductor handling costs were authorized for realignment from the formula rate plan to the annual power management and grid modernization riders effective January 2023, resulting in regulatory credits recorded in June 2023 of $4.1 million and $4.3 million, respectively. Also, the amortization of Entergy Mississippi’s COVID-19 bad debt expense deferral was suspended for calendar year 2023, but resumed in July 2024. In June 2023 the MPSC approved the joint stipulation with rates effective in July 2023.

2024 Formula Rate Plan Filing

In March 2024, Entergy Mississippi submitted its formula rate plan 2024 test year filing and 2023 look-back filing showing Entergy Mississippi’s earned return on rate base for the historical 2023 calendar year to be within the formula rate plan bandwidth and projected earned return for the 2024 calendar year to be below the formula rate plan bandwidth. The 2024 test year filing showed a $63.4 million rate increase was necessary to reset Entergy Mississippi’s earned return on rate base to the specified point of adjustment of 7.10%, within the formula rate plan bandwidth. The 2023 look-back filing compared actual 2023 results to the approved benchmark return on rate base and reflected no change in formula rate plan revenues. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $32.6 million interim rate increase, reflecting a cap equal to 2% of 2023 retail revenues, effective April 2024.

In December 2014 the MPSC ordered Entergy Mississippi to file an updated depreciation study at least once every four years. Pursuant to this order and Entergy Mississippi’s filing cycle, Entergy Mississippi would have filed an updated depreciation report with its formula rate plan filing in 2023. However, in July 2022 the MPSC directed Entergy Mississippi to file its next depreciation study in connection with its 2024 formula rate plan filing notwithstanding the MPSC’s prior order. Accordingly, Entergy Mississippi filed a depreciation study in February 2024. The study showed a need for an increase in annual depreciation expense of $55.2 million. The calculated increase in annual depreciation expense was excluded from Entergy Mississippi’s 2024 formula rate plan revenue increase request because the MPSC had not yet approved the proposed depreciation rates.
In June 2024, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed the 2024 test year filing, with the exception of immaterial adjustments to certain operation and maintenance expenses. After performance adjustments, the formula rate plan reflected an earned return on rate base of 6.08% for calendar year 2024, which resulted in a total revenue increase of $64.6 million for 2024. The joint stipulation also recommended approval of a revised customer charge of $31.82 per month for residential customers and $53.10 per month for general service customers. Pursuant to the stipulation, Entergy Mississippi’s 2023 look-back filing reflected an earned return on rate base of 6.81%, resulting in an increase of $0.3 million in the formula rate plan revenues for 2023. Finally, the stipulation recommended approval of Entergy Mississippi’s proposed depreciation rates with those rates to be implemented upon request and approval at a later date. In June 2024 the MPSC approved the joint stipulation with rates effective in July 2024. The approval also included a reduction to the energy cost factor, resulting in a net bill decrease for a typical residential customer using 1,000 kWh per month. Also in June 2024, Entergy Mississippi recorded regulatory credits of $7.3 million to reflect the difference between interim rates placed in effect in April 2024 and the rates reflected in the joint stipulation.

In May 2024, Entergy Mississippi received approval from the MPSC for formula rate plan revisions that were necessary for Entergy Mississippi to comply with state legislation passed in January 2024. The legislation allows Entergy Mississippi to make interim rate adjustments 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 filed the first of its annual interim facilities rate adjustment reports in May 2024 to recover approximately $8.7 million of these costs over a six-month period with rates effective beginning in July 2024. Entergy Mississippi filed its second annual interim facilities rate adjustment report in December 2024 to recover approximately $46.7 million of these costs over a 12-month period with rates effective beginning in January 2025.

Grand Gulf Capacity Filing

In September 2024, Entergy Mississippi filed a notice of intent with the MPSC to implement revisions to its unit power cost recovery rider that would allow Entergy Mississippi to recover the first year of costs associated with the transfer of Entergy Louisiana’s entitlements to Grand Gulf capacity and energy, which consists of Energy Louisiana’s interest in and purchases of Grand Gulf capacity and energy under the revised rider schedule, effective by January 1, 2025. This notice filing related to the divestiture of Entergy Louisiana’s 14% share of Grand Gulf capacity and energy under the Unit Power Sales Agreement and 2.43% share of capacity and energy from Entergy Arkansas under the MSS-4 replacement tariff. This divestiture is being effectuated initially through Entergy Mississippi’s purchases from Entergy Louisiana pursuant to a PPA governed by the MSS-4 replacement tariff, a tariff governing the sales of energy and capacity among the Utility operating companies as described in the System Energy global settlement with the LPSC and Entergy Louisiana. The MSS-4 replacement PPA to effectuate this divestiture was approved by the FERC in November 2024. In February 2025 the MPSC approved Entergy Mississippi’s notice of intent, finding that it was just and reasonable for Entergy Mississippi to obtain Entergy Louisiana’s entitlements to Grand Gulf capacity and energy and that Entergy Mississippi should be allowed to recover the costs associated with the transfer of such entitlements to Grand Gulf capacity and energy, as described above. The MPSC approved the MSS-4 replacement PPA, effective as of January 1, 2025. See “Complaints Against System Energy – System Energy Settlement with the LPSC” below for further details of the System Energy global settlement with the LPSC and Note 8 to the financial statements for discussion of the Unit Power Sales Agreement.

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.

Filings with the City Council (Entergy New Orleans)

Retail Rates

2022 Formula Rate Plan Filing

In April 2022, Entergy New Orleans submitted to the City Council its formula rate plan 2021 test year filing. The 2021 test year evaluation report, subsequently updated in a July 2022 filing, produced an earned return on equity of 6.88% compared to the authorized return on equity of 9.35%. Entergy New Orleans sought approval of a $42.1 million rate increase based on the formula set by the City Council in the 2018 rate case. The formula resulted in an increase in authorized electric revenues of $34.1 million and an increase in authorized gas revenues of $3.3 million. Entergy New Orleans also sought to commence collecting $4.7 million in electric revenues that were previously approved by the City Council for collection through the formula rate plan. In July 2022 the City Council’s advisors issued a report seeking a reduction to Entergy New Orleans’s proposed increase of approximately $17.1 million in total for electric and gas revenues. Effective with the first billing cycle of September 2022, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council including adjustments filed in the City Council’s advisors’ report, per the approved process for formula rate plan implementation. The total formula rate plan increase implemented was $24.7 million, which includes an increase of $18.2 million in electric revenues, $4.7 million in previously approved electric revenues, and an increase of $1.8 million in gas revenues. Additionally, credits of $13.9 million funded by certain regulatory liabilities currently held by Entergy New Orleans for customers were issued over an eight-month period beginning September 2022.

2023 Formula Rate Plan Filing

In April 2023, Entergy New Orleans submitted to the City Council its formula rate plan 2022 test year filing. The 2022 test year evaluation report produced an electric earned return on equity of 7.34% and a gas earned return on equity of 3.52% compared to the authorized return on equity for each of 9.35%. Entergy New Orleans sought approval of a $25.6 million rate increase based on the formula set by the City Council in the 2018 rate case. The formula would result in an increase in authorized electric revenues of $17.4 million and an increase in authorized gas revenues of $8.2 million. Entergy New Orleans also sought to commence collecting $3.4 million in electric revenues that were previously approved by the City Council for collection through the formula rate plan. In July 2023, Entergy New Orleans filed a report to decrease its requested formula rate plan revenues by approximately $0.5 million to account for minor errors discovered after the filing. The City Council advisors issued a report seeking a reduction in the requested formula rate plan revenues of approximately $8.3 million, combined for electric and gas, due to alleged errors. The City Council advisors proposed additional rate mitigation in the amount of $12 million through offsets to the formula rate plan rate increase by certain regulatory liabilities. In September 2023 the City Council approved an agreement to settle the 2023 formula rate plan filing. Effective with the first billing cycle of September 2023, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council, per the approved process for formula rate plan implementation. The agreement provides for a total increase in electric revenues of $10.5 million and a total increase in gas revenues of
$6.9 million. The agreement also provides for a minor storm accrual of $0.5 million per year and the distribution of $8.9 million of currently held customer credits to implement the City Council advisors’ mitigation recommendations.

Request for Extension and Modification of Formula Rate Plan

In September 2023, Entergy New Orleans filed a motion seeking City Council approval of a three-year extension of Entergy New Orleans’s electric and gas formula rate plans. In October 2023 the City Council granted Entergy New Orleans’s request for an extension, subject to minor modifications which included a 55% equity ratio for rate setting purposes.

2024 Formula Rate Plan Filing

In April 2024, Entergy New Orleans submitted to the City Council its formula rate plan 2023 test year filing. Without the requested rate change in 2024, the 2023 test year evaluation report produced an electric earned return on equity of 8.66% and a gas earned return on equity of 5.87% compared to the authorized return on equity for each of 9.35%. Entergy New Orleans sought approval of a $12.6 million rate increase based on the formula set by the City Council in the 2018 rate case and approved again by the City Council in 2023. The formula would result in an increase in authorized electric revenues of $7.0 million and an increase in authorized gas revenues of $5.6 million. Following City Council review, the City Council’s advisors issued a report in July 2024 seeking a reduction in Entergy New Orleans’s requested formula rate plan revenues in an aggregate amount of approximately $1.6 million for electric and gas together due to alleged errors. Effective with the first billing cycle of September 2024, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council, per the approved process for formula rate plan implementation. The total formula rate plan increase implemented was $11.2 million, which includes an increase of $5.8 million in electric revenues and an increase of $5.4 million in gas revenues.

Filings with the PUCT and Texas Cities (Entergy Texas)

Retail Rates

2022 Base Rate Case

In July 2022, Entergy Texas filed a base rate case with the PUCT seeking a net increase in base rates of approximately $131.4 million. The base rate case was based on a 12-month test year ending December 31, 2021. Key drivers of the requested increase were changes in depreciation rates as the result of a depreciation study and an increase in the return on equity. In addition, Entergy Texas included capital additions placed into service for the period of January 1, 2018 through December 31, 2021, including those additions reflected in the then-effective distribution and transmission cost recovery factor riders and the generation cost recovery rider, all of which were reset to zero in June 2023 as a result of this proceeding. In July 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In October 2022 intervenors filed direct testimony challenging and supporting various aspects of Entergy Texas’s rate case application. The key issues addressed included the appropriate return on equity, generation plant deactivations, depreciation rates, and proposed tariffs related to electric vehicles. In November 2022 the PUCT staff filed direct testimony addressing a similar set of issues and recommending a reduction of $50.7 million to Entergy Texas’s overall cost of service associated with the requested net increase in base rates of approximately $131.4 million. Entergy Texas filed rebuttal testimony in November 2022.

In May 2023, Entergy Texas filed on behalf of the parties an unopposed settlement resolving all issues in the proceeding, except for issues related to electric vehicle charging infrastructure which were eventually severed to a separate proceeding and resolved in October 2024, and Entergy Texas filed an agreed motion for interim rates, subject to refund or surcharge to the extent that the interim rates differ from the final approved rates. The unopposed settlement reflected a net base rate increase to be effective and relate back to December 2022 of
$54 million, exclusive of, and incremental to, the costs being realigned from the distribution and transmission cost recovery factor riders and the generation cost recovery rider and $4.8 million of rate case expenses to be recovered through a rider over a period of 36 months. The net base rate increase of $54 million includes updated depreciation rates and a total annual revenue requirement of $14.5 million for the accrual of a self-insured storm reserve and the recovery of the regulatory assets for the pension and postretirement benefits expense deferral, costs associated with the COVID-19 pandemic, and retired non-advanced metering system electric meters. In May 2023 the ALJ with the State Office of Administrative Hearings granted the motion for interim rates, which became effective in June 2023. Additionally, the ALJ remanded the proceeding to the PUCT to consider the settlement. In August 2023 the PUCT issued an order approving the unopposed settlement. Concurrently, Entergy Texas recorded the reversal of $21.9 million of regulatory liabilities to reflect the recognition of certain receipts by Entergy Texas under affiliated PPAs that have been resolved.

Following the PUCT’s approval of the unopposed settlement in August 2023, Entergy Texas recorded a regulatory liability of $10.3 million, which reflected the net effects of higher depreciation and amortizations for the relate back period, partially offset by the relate back of base rate revenues that would have been collected had the approved rates been in effect for the period from December 2022 through June 2023, the date the new base rates were implemented on an interim basis. In October 2023, Entergy Texas filed a relate back surcharge rider to collect over six months beginning in January 2024 an additional approximately $24.6 million, which was the revenue requirement associated with the relate back of rates from December 2022 through June 2023, including carrying costs, as authorized by the PUCT’s August 2023 order. In November 2023, Entergy Texas filed an amended relate back surcharge rider to collect approximately $24.1 million based on a revised carrying cost rate. The amended relate back surcharge rider was approved by the PUCT in December 2023. The higher depreciation and amortizations for the relate back period were also recognized over the six months beginning in January 2024, resulting in no effect on net income from the collection of the relate back surcharge rider.

Distribution Cost Recovery Factor (DCRF) Rider

In June 2024, Entergy Texas filed with the PUCT a request to set a new DCRF rider. The new rider was designed to collect from Entergy Texas’s retail customers approximately $40.3 million annually based on its capital invested in distribution between January 1, 2022 and March 31, 2024. In September 2024 the PUCT approved the DCRF rider, consistent with Entergy Texas’s as-filed request, and rates became effective with the first billing cycle in October 2024.

In September 2024, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $48.9 million annually, or $8.6 million in incremental annual revenues beyond Entergy Texas’s then-effective DCRF rider based on its capital invested in distribution between April 1, 2024 and June 30, 2024. In December 2024, Entergy Texas filed an errata to revise its DCRF application for minor corrections, which decreased the requested annual revenue requirement to $48.5 million. The amended request represented an incremental increase of $8.2 million in annual revenues beyond Entergy Texas’s then-effective DCRF rider. Also in December 2024 the PUCT approved the DCRF rider, consistent with Entergy Texas’s filed errata, and rates became effective on December 20, 2024.

Transmission Cost Recovery Factor (TCRF) Rider

In December 2018, Entergy Texas filed with the PUCT a request to set a new TCRF rider. The new TCRF rider was designed to collect approximately $2.7 million annually from Entergy Texas’s retail customers based on its capital invested in transmission between January 1, 2018 and September 30, 2018. In April 2019 parties filed testimony proposing a load growth adjustment, which would fully offset Entergy Texas’s proposed TCRF revenue requirement. In July 2019 the PUCT granted Entergy Texas’s application as filed to begin recovery of the requested $2.7 million annual revenue requirement, rejecting opposing parties’ proposed adjustment; however, the PUCT found that the question of prudence of the actual investment costs should be determined in Entergy Texas’s next rate case similar to the procedure used for the costs recovered through the DCRF rider. In October 2019 the PUCT
issued an order on a motion for rehearing, clarifying and affirming its prior order granting Entergy Texas’s application as filed. Also in October 2019 a second motion for rehearing was filed, and Entergy Texas filed a response in opposition to the motion. The second motion for rehearing was overruled by operation of law. In December 2019, Texas Industrial Energy Consumers filed an appeal to the PUCT order in district court alleging that the PUCT erred in declining to apply a load growth adjustment.

In October 2021, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $66.1 million annually, or $15.1 million in incremental annual revenues beyond Entergy Texas’s then-effective TCRF rider based on its capital invested in transmission between September 1, 2020 and July 31, 2021 and changes in approved transmission charges. In January 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In February 2022 the parties filed an unopposed settlement recommending that Entergy Texas be allowed to collect its full requested TCRF revenue requirement with interim rates effective March 2022. In February 2022 the ALJ granted the motion for interim rates, admitted evidence, and remanded the case to the PUCT for consideration of a final order at a future open meeting. In June 2022 the PUCT issued an order approving the settlement.

In October 2024, Entergy Texas filed with the PUCT a request to amend its TCRF rider, which was previously reset to zero in June 2023 as a result of the 2022 base rate case. The proposed rider is designed to collect from Entergy Texas’s retail customers approximately $9.7 million annually based on its capital invested in transmission between January 1, 2022 and June 30, 2024 and changes in other transmission charges. In December 2024 the PUCT staff filed a recommendation that the PUCT approve Entergy Texas’s as-filed application. In February 2025 the PUCT staff issued a proposed order that, if approved by the PUCT, would approve Entergy Texas’s TCRF rider as filed.

Generation Cost Recovery Rider

In October 2020, Entergy Texas filed an application to establish a generation cost recovery rider to begin recovering a return of and on its generation capital investment in the Montgomery County Power Station. Entergy Texas filed an unopposed settlement agreement in December 2020, and the PUCT approved the generation cost recovery rider settlement rates on an interim basis in January 2021. In March 2021, Entergy Texas filed to update its generation cost recovery rider, and an unopposed settlement agreement filed by Entergy Texas on behalf of the parties in October 2021 was approved by the PUCT in January 2022. In February 2022, Entergy Texas filed a relate-back rider to collect over five months an additional approximately $5 million, which was the difference between the interim revenue requirement approved in January 2021 and the revenue requirement approved in January 2022 reflecting Entergy Texas’s full generation capital investment and ownership in Montgomery County Power Station on January 1, 2021, plus carrying costs from January 2021 through January 2022 when the updated revenue requirement took effect. The PUCT approved the relate-back rider consistent with Entergy Texas’s as-filed request, and rates became effective over a five-month period, in August 2022.

In December 2020, Entergy Texas also filed an application to amend its generation cost recovery rider to reflect its acquisition of the Hardin County Peaking Facility, which closed in June 2021. Because Hardin was to be acquired in the future, the initial generation cost recovery rider rates proposed in the application represented no change from the generation cost recovery rider rates established in Entergy Texas’s previous generation cost recovery rider proceeding. In July 2021 the PUCT issued an order approving the application. In August 2021, Entergy Texas filed an update application to recover its actual investment in the acquisition of the Hardin County Peaking Facility, and in January 2022, Entergy Texas filed an update to its application to align the requested revenue requirement with the terms of the generation cost recovery rider settlement approved by the PUCT in January 2022. In April 2022, Entergy Texas filed on behalf of the parties a unanimous settlement agreement that would adjust its generation cost recovery rider to recover an annual revenue requirement of approximately $92.8 million, which was $4.5 million in incremental annual revenue above the revenue requirement approved in January 2022 described above and related to Entergy Texas’s investment in the Montgomery County Power Station. The PUCT approved the settlement agreement and rates became effective in August 2022. In September 2022,
Entergy Texas filed a relate-back rider designed to collect over three months an additional approximately $5.7 million, which is the revenue requirement, plus carrying costs, associated with Entergy Texas’s acquisition of Hardin County Peaking Facility from June 2021 through August 2022 when the updated revenue requirement took effect. In April 2023 the PUCT approved Entergy Texas’s as-filed request with rates effective over three months beginning in May 2023.
Entergy Arkansas Opportunity Sales Proceeding

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

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

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

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

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

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

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

In October 2018 the FERC issued an order addressing the ALJ’s July 2017 initial decision. The FERC reversed the ALJ’s decision to cap the reduction in Entergy Arkansas’s payment to account for the increased bandwidth payments that Entergy Arkansas made to the other operating companies. The FERC also reversed the ALJ’s decision that Grand Gulf sales from January through September 2000 should be included in the calculation of Entergy Arkansas’s payment. The FERC affirmed on other grounds the ALJ’s rejection of the LPSC’s claim that certain joint account sales should be accounted for as part of the calculation of Entergy Arkansas’s payment. In November 2018 the LPSC requested rehearing of the FERC’s October 2018 decision. In December 2019 the FERC denied the LPSC’s request for rehearing. In January 2020 the LPSC appealed the December 2019 decision to the D.C. Circuit.
In December 2018, Entergy made a compliance filing in response to the FERC’s October 2018 order. The compliance filing provided a final calculation of Entergy Arkansas’s payments to the other Utility operating companies, including interest. No protests were filed in response to the December 2018 compliance filing. Refunds and interest in the following amounts were paid by Entergy Arkansas to the other operating companies in December 2018:
 Total refunds including interest
Payment/(Receipt)
 (In Millions)
PrincipalInterestTotal
Entergy Arkansas$68$67$135
Entergy Louisiana($30)($29)($59)
Entergy Mississippi($18)($18)($36)
Entergy New Orleans($3)($4)($7)
Entergy Texas($17)($16)($33)

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

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

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

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

In July 2020 the APSC issued a decision finding that Entergy Arkansas’s application is not in the public interest. The order also directed Entergy Arkansas to refund to its retail customers within 30 days of the order the FERC-determined over-collection of $13.7 million, plus interest, associated with a recalculated bandwidth remedy. In addition to these primary findings, the order also denied the Attorney General’s request for Entergy Arkansas to prepare a compliance filing detailing all of the retail impacts from the opportunity sales and denied a request by the Arkansas Electric Energy Consumers to recalculate all costs using the revised responsibility ratio. Entergy Arkansas filed a motion for temporary stay of the 30-day requirement to allow Entergy Arkansas a reasonable opportunity to seek rehearing of the APSC order, but in July 2020 the APSC denied Entergy Arkansas’s request for a stay and directed Entergy Arkansas to refund to its retail customers the component of the total FERC-determined opportunity sales payment that was associated with increased bandwidth remedy payments of $13.7 million, plus interest. The refunds were issued in the August 2020 billing cycle. While the APSC denied Entergy Arkansas’s stay request, Entergy Arkansas believes its actions were prudent and, therefore, the costs, including the $13.7 million, plus interest, are recoverable. In July 2020, Entergy Arkansas requested rehearing of the APSC order, which rehearing was denied by the APSC in August 2020. In September 2020, Entergy Arkansas filed a complaint in the U.S. District Court for the Eastern District of Arkansas challenging the APSC’s order denying Entergy Arkansas’s request to recover the costs of these payments. In October 2020 the APSC filed a motion to dismiss Entergy Arkansas’s complaint, to which Entergy Arkansas responded. Also in December 2020, Entergy Arkansas and the APSC held a pre-trial conference, and filed a report with the court in January 2021. The court held a hearing in February 2021 regarding issues addressed in the pre-trial conference report, and in June 2021 the court stayed all discovery until it rules on pending motions, after which the court will issue an amended schedule if necessary. In March 2022 the court denied the APSC’s motion to dismiss, and, in April 2022, issued a scheduling order including a trial date in February 2023. In June 2022, Entergy Arkansas filed a motion asserting that it is entitled to summary judgment because Entergy Arkansas’s position that the APSC’s order is pre-empted by the filed rate doctrine and violates the Dormant Commerce Clause is premised on facts that are not subject to genuine dispute. In July 2022, Arkansas Electric Energy Consumers, Inc., an industrial customer association, filed a motion to intervene and to hold Entergy Arkansas’s motion for summary judgment in abeyance pending a ruling on the motion to intervene. Entergy Arkansas filed a consolidated opposition to both motions. In August 2022 the APSC filed a motion for summary judgment arguing that there is no genuine issue as to any material fact and the APSC is entitled to judgment as a matter of law. In September 2022, Entergy Arkansas filed an opposition to the motion. In October 2022 the APSC filed a motion asking the court to hold further proceedings in abeyance pending a decision on the motions for summary judgment filed by Entergy Arkansas and the APSC. Also in October 2022, Entergy Arkansas filed an opposition to the motion, and the APSC filed a reply in support of its motion for summary judgment. In January 2023 the judge assigned to the case, on her own motion, identified facts that may present a conflict and recused herself; a new judge was assigned to the case, but he also recused due to a conflict. The case again was reassigned to a new judge. In January 2023 the court denied all pending motions (including those described above) except for a motion by the APSC to exclude certain testimony and further ruled that the matter would proceed to trial. In January 2023, Arkansas Electric Energy Consumers, Inc. filed a notice of appeal of the court’s order denying its motion to intervene to the United States Court of Appeals for the Eighth Circuit and a motion with the district court to stay the proceedings pending the appeal, which was denied. In February 2023, Arkansas Electric Energy Consumers, Inc. filed a motion with the United States Court of Appeals for the Eighth Circuit to stay the proceedings pending the appeal, which also was denied. The trial was held in February 2023. Following the trial, Entergy Arkansas filed a motion with the United States Court of Appeals for the Eighth Circuit to expedite the appeal filed by Arkansas Electric Energy Consumers, Inc. The United States Court of Appeals for
the Eighth Circuit granted Entergy Arkansas’s request, and oral arguments were held in June 2023. In August 2023 the United States Court of Appeals for the Eighth Circuit affirmed the order of the court denying Arkansas Electric Energy Consumers, Inc.’s motion to intervene.

In March 2024 the U.S. District Court for the Eastern District of Arkansas issued a judgment in favor of the APSC and against Entergy Arkansas. In March 2024 Entergy Arkansas filed a notice of appeal and a motion to expedite oral arguments with the United States Court of Appeals for the Eighth Circuit and the court granted the motion to expedite. Briefing to the United States Court of Appeals for the Eighth Circuit concluded in July 2024 and oral arguments concluded in September 2024. As a result of the adverse decision by the U.S. District Court for the Eastern District of Arkansas, Entergy Arkansas concluded that it could no longer support the recognition of its $131.8 million regulatory asset reflecting the previously-expected recovery of a portion of the costs at issue in the opportunity sales proceeding and recorded a $131.8 million ($99.1 million net-of-tax) charge to earnings in first quarter 2024. In December 2024 the United States Court of Appeals for the Eighth Circuit affirmed the decision of the U.S. District Court for the Eastern District of Arkansas, and Entergy Arkansas filed a petition for rehearing en banc. In January 2025 the United States Court of Appeals for the Eighth Circuit denied Entergy Arkansas’s petition. Entergy Arkansas is evaluating a petition for certiorari with the United States Supreme Court.
MSS-4 Replacement Tariff – Net Operating Loss Carryforward Proceeding

In January 2021, pursuant to section 205 of the Federal Power Act, Entergy Services filed an amendment to the MSS-4 replacement tariff, a tariff governing the sales of energy and capacity among the Utility operating companies, in order to provide for the inclusion of specified accumulated deferred income taxes, including net operating loss carryforward accumulated deferred income taxes (NOLC ADIT), in the rate for sales of energy among the Utility operating companies on a prospective basis. In March 2021, the FERC accepted the filing, subject to refund and hearing procedures.

In October 2021 the LPSC filed a complaint with the FERC alleging that Entergy Services improperly excluded NOLC ADIT from MSS-4 replacement tariff rates in the period before March 20, 2021. The LPSC argued that sales from Entergy Louisiana to Entergy Texas and Entergy New Orleans were charged at rates lower than they otherwise should have been, and it accordingly seeks surcharges for the period prior to March 20, 2021. The FERC set the complaint for hearing procedures and subsequently the hearing for this complaint proceeding was consolidated with the hearing procedures for Entergy Services’ January 2021 NOLC ADIT filing.

Testimony was filed by parties in 2023, and the hearing before a FERC ALJ was concluded in February 2024. In June 2024, the FERC ALJ issued an initial decision addressing three major issues: (1) whether Entergy Services’ proposed prospective inclusion and allocation of NOLC ADIT in MSS-4 replacement tariff rates using a modified with-and-without methodology is just and reasonable; (2) whether Entergy Services correctly calculated excess and deficient accumulated deferred income taxes in accordance with the terms of a prior settlement; and (3) whether NOLC ADIT should have been included in MSS-4 replacement tariff rates prior to the effective date of the January 2021 MSS-4 replacement tariff filing.

With respect to issues (1) and (2), the presiding ALJ concluded that Entergy Services’ proposed methodology for allocating and including NOLC ADIT in MSS-4 replacement tariff rates was just and reasonable and that Entergy Services correctly performed the excess and deficient accumulated deferred income taxes calculations. With respect to issue (3), however, the presiding ALJ agreed with the LPSC that NOLC ADIT should have been included in MSS-4 replacement tariff rates since September 1, 2016, and as a result, the presiding ALJ ordered that Entergy Louisiana and Entergy Arkansas recalculate bills for the period of September 1, 2016 through November 11, 2023 with surcharges expected to be due to those operating companies from the purchasing operating companies, Entergy New Orleans, Entergy Texas, and Entergy Louisiana (for some Entergy Arkansas sales). The presiding ALJ also ordered Entergy Services to pay the interest owed to Entergy Louisiana on these surcharges.
The surcharge methodology that the presiding ALJ recommended in connection with issue (3) was not supported by any participant in the hearing. As part of their exceptions to the initial decision, all parties to the proceeding opposed the use of the ALJ’s methodology, except for the FERC trial staff, which took no position. During the hearing, the LPSC and the FERC trial staff advocated that the alleged tariff violation should be remedied by the application of Entergy Services’ January 2021 proposed methodology. All other parties, including the PUCT, the City Council, and Entergy Services, opposed any surcharges for the period prior to the March 20, 2021 effective date of the January 2021 filing.

Entergy Services disputes the presiding ALJ's rulings on issue (3) and filed exceptions to these rulings in July 2024. The ALJ's initial decision is not binding on the FERC and is an interim step in the hearing process. No refunds will be owed in connection with this proceeding unless and until the FERC requires them in a final order.
Complaints Against System Energy

System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf.  System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. System Energy and the Unit Power Sales Agreement have been the subject of several litigation proceedings at the FERC, including challenges with respect to System Energy’s authorized return on equity and capital structure, renewal of its sale-leaseback arrangement, treatment of uncertain tax positions, a broader investigation of rates under the Unit Power Sales Agreement, and two prudence complaints, one challenging the extended power uprate completed at Grand Gulf in 2012 and the operation and management of Grand Gulf, particularly in the 2016-2020 time period, and the second challenging the operation and management of Grand Gulf in the 2021-2022 time period. Settlements that resolve all significant aspects of these complaints have been reached with the MPSC, the APSC, the City Council, and the LPSC, and these settlements have been approved by the FERC. Following are discussions of the proceedings.

Return on Equity and Capital Structure Complaints

In January 2017 the APSC and the MPSC filed a complaint with the FERC against System Energy. The complaint sought a reduction in the return on equity component of the Unit Power Sales Agreement pursuant to which System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. Entergy Arkansas also sells some of its Grand Gulf capacity and energy to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under separate agreements. The return on equity under the Unit Power Sales Agreement at the time of the complaint was 10.94%, which was established in a rate proceeding that became final in July 2001.

The APSC and the MPSC complaint alleged that the return on equity was unjust and unreasonable because capital market and other considerations indicated that it was excessive. The complaint requested proceedings to investigate the return on equity and establish a lower return on equity, and also requested that the FERC establish January 23, 2017 as a refund effective date. The complaint included a return on equity analysis that purported to establish that the range of reasonable return on equity for System Energy was between 8.37% and 8.67%. System Energy answered the complaint in February 2017 and disputed that a return on equity of 8.37% to 8.67% was just and reasonable. The LPSC and the City Council intervened in the proceeding expressing support for the complaint. In September 2017 the FERC established a refund effective date of January 23, 2017 and directed the parties to engage in settlement proceedings before an ALJ. The parties were unable to settle the return on equity issue and a FERC hearing judge was assigned in July 2018. The 15-month refund period in connection with the APSC/MPSC complaint expired on April 23, 2018.

In April 2018 the LPSC filed a complaint with the FERC against System Energy seeking an additional 15-month refund period.  The LPSC complaint requested similar relief from the FERC with respect to System Energy’s
return on equity and also requested the FERC to investigate System Energy’s capital structure.  The APSC, the MPSC, and the City Council intervened in the proceeding, filed an answer expressing support for the complaint, and asked the FERC to consolidate this proceeding with the proceeding initiated by the complaint of the APSC and the MPSC in January 2017. System Energy answered the LPSC complaint in May 2018 and also filed a motion to dismiss the complaint. In August 2018 the FERC issued an order dismissing the LPSC’s request to investigate System Energy’s capital structure and setting for hearing the return on equity complaint, with a refund effective date of April 27, 2018. The 15-month refund period in connection with the LPSC return on equity complaint expired on July 26, 2019.

The portion of the LPSC’s complaint dealing with return on equity was subsequently consolidated with the APSC and the MPSC complaint for hearing. The parties also addressed an order (issued in a separate FERC proceeding involving New England transmission owners) that proposed modifying the FERC’s standard methodology for determining return on equity. In September 2018 the LPSC filed an amended complaint raising the same capital structure claim the FERC had earlier dismissed. The FERC initiated a new proceeding for the amended capital structure complaint, and System Energy answered the complaint in October 2018. In January 2019 the FERC set the amended complaint for settlement and hearing proceedings. Settlement proceedings in the capital structure proceeding commenced in February 2019, but were terminated in June 2019, and the amended capital structure complaint was consolidated with the ongoing return on equity proceeding. The 15-month refund period in connection with the capital structure complaint was from September 24, 2018 to December 23, 2019.

Several rounds of testimony were filed by the parties in these proceedings between January 2019 and August 2020. Some of these rounds of testimony were precipitated by developments in an unrelated proceeding in which the FERC issued orders addressing the methodology for determining the return on equity applicable to transmission owners in MISO (Opinion Nos. 569 and 569-A). The final positions of the parties, after the submission of all pre-filed testimony, were as follows. With regard to the return on equity complaints for the first refund period, based on their respective interpretations and applications of the Opinion No. 569-A methodology, the LPSC argued for an authorized return on equity for System Energy of 7.97%; the MPSC and the APSC argued for an authorized return on equity of 9.24%; and the FERC trial staff argued for an authorized return on equity of 9.49%. For the second refund period and on a prospective basis, based on their respective interpretations and applications of the Opinion No. 569-A methodology, the LPSC argued for an authorized return on equity for System Energy of 7.78%; the MPSC and the APSC argued that an authorized return on equity of 9.15% may be appropriate if the second complaint was not dismissed; and the FERC trial staff argued for an authorized return on equity of 9.09% if the second complaint was not dismissed. The LPSC also continued to support as its primary recommendation, based on an alternative analysis to the Opinion No. 569-A methodology, an authorized return on equity for System Energy as low as 7.56% for the first complaint refund period and as low as 7.18% for the second complaint refund period and prospectively. The MPSC and the APSC also continued to support as their primary recommendation, based on an alternative analysis to the Opinion No. 569-A methodology, an authorized return on equity for System Energy as low as 8.26% for the first complaint refund period and as low as 8.32% for the second complaint refund period and prospectively. System Energy argued that strict application of the Opinion No. 569-A methodology produces results inconsistent with investor requirements and does not provide a sound basis on which to evaluate System Energy’s authorized return on equity. Therefore, as its primary recommendation, System Energy argued for the use of a methodology that incorporates four separate financial models and, based on application of this recommended methodology, an authorized return on equity of 10.12% for the first refund period, which also fell within the presumptively just and reasonable range calculated for the second refund period and prospectively. Under the Opinion No. 569-A methodology, System Energy calculated an authorized return on equity of 9.44% for the first refund period, which also fell within the presumptively just and reasonable range calculated for the second refund period and prospectively.

With regard to the capital structure, the LPSC’s primary recommendation was that the FERC establish a hypothetical capital structure for System Energy for ratemaking purposes, according to which System Energy’s common equity ratio would be set to Entergy Corporation’s equity ratio of 37% equity and 63% debt. The APSC and the MPSC recommended that 35.98% be set as the common equity ratio for System Energy. The FERC trial
staff argued that the average capital structure of the proxy group used to develop System Energy’s return on equity should be used to establish the capital structure. Using this approach, the FERC trial staff calculated the average capital structure for its proposed proxy group of 46.74% common equity and 53.26% debt. System Energy disputed all of these recommendations and argued that the use of its actual capital structure was just and reasonable.

After conducting a hearing, in March 2021 the FERC ALJ issued an initial decision. With regard to System Energy’s authorized return on equity, the ALJ determined that the existing return on equity of 10.94% was no longer just and reasonable, and that the replacement authorized return on equity, based on application of the Opinion No. 569-A methodology, should be 9.32%. The ALJ further determined that System Energy should pay refunds for a fifteen-month refund period (January 2017-April 2018) based on the difference between the current return on equity and the replacement authorized return on equity. The ALJ determined that the April 2018 complaint concerning the authorized return on equity should be dismissed, and that no refunds for a second fifteen-month refund period should be due. With regard to System Energy’s capital structure, the ALJ determined that System Energy’s actual equity ratio was excessive and that the just and reasonable equity ratio was 48.15% equity, based on the average equity ratio of the proxy group used to evaluate the return on equity for the second complaint. The ALJ further determined that System Energy should pay refunds for a fifteen-month refund period (September 2018-December 2019) based on the difference between the actual equity ratio and the 48.15% equity ratio.

In April 2021, System Energy filed its brief on exceptions, in which it challenged the initial decision’s findings on both the return on equity and capital structure issues. Also in April 2021 the LPSC, the APSC, the MPSC, the City Council, and the FERC trial staff filed briefs on exceptions. Reply briefs opposing exceptions were filed in May 2021 by System Energy, the FERC trial staff, the LPSC, the APSC, the MPSC, and the City Council.

As discussed below in “System Energy Settlement with the MPSC,” “System Energy Settlement with the APSC,” “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the MPSC, the APSC, the City Council, and the LPSC have settled their claims related to these proceedings. As part of the settlements with their respective retail regulators, effective July 2022 for Entergy Mississippi, November 2023 for Entergy Arkansas, June 2024 for Entergy New Orleans, and September 2024 for Entergy Louisiana, bills issued under the Unit Power Sales Agreement reflect a return on equity of 9.65% and a capital structure not to exceed 52% equity.

In August 2022 the D.C. Circuit issued an order addressing appeals of FERC’s Opinion No. 569 and 569-A, which established the methodology applied in the ALJ’s initial decision in the proceeding against System Energy discussed above. The appellate order addressed the methodology for determining the return on equity applicable to transmission owners in MISO. The D.C. Circuit found the FERC’s use of the Risk Premium model as part of the methodology to be arbitrary and capricious, and remanded the case back to the FERC. In October 2024, after System Energy had reached settlements with each of the retail regulators involved in the return on equity and capital structure proceeding discussed above, the FERC issued a remand order in the MISO transmission owners’ return on equity case, concluding that the record supported the methodology that it originally directed in Opinion No. 569 utilizing an equal weighting of the two-step discounted cash flow model and capital asset pricing model. As a result, it determined that the just and reasonable return on equity for the MISO transmission owners is 9.98%. In light of the System Energy settlements detailed below, the FERC’s changes to its return on equity methodology in the decision on the MISO transmission owners’ return on equity will not have any immediate effect on System Energy’s return on equity because System Energy’s return on equity has been set at 9.65% through the global settlement through the end of June 2026.

Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue

In May 2018 the LPSC filed a complaint against System Energy and Entergy Services related to System Energy’s renewal of a sale-leaseback transaction originally entered into in December 1988 for an 11.5% undivided interest in Grand Gulf Unit 1. The complaint alleged that System Energy violated the filed rate and the FERC’s ratemaking and accounting requirements when it included in Unit Power Sales Agreement billings the cost of
capital additions associated with the sale-leaseback interest, and that System Energy was double-recovering costs by including both the lease payments and the capital additions in Unit Power Sales Agreement billings. The complaint also claimed that System Energy was imprudent in entering into the sale-leaseback renewal because the Utility operating companies that purchase Grand Gulf’s output from System Energy could have obtained cheaper capacity and energy in the MISO markets. The complaint further alleged that System Energy violated various other reporting and accounting requirements and should have sought prior FERC approval of the lease renewal. The complaint sought various forms of relief from the FERC, including refunds for capital addition costs for all years in which they were recorded in allegedly non-formula accounts or, alternatively, the disallowance of the return on equity for the capital additions in those years plus interest; a disallowance and refund of the lease costs of the sale-leaseback renewal on grounds of imprudence; an investigation into System Energy’s treatment of a DOE litigation payment; and the imposition of certain forward-looking procedural protections, including audit rights for retail regulators of the Unit Power Sales Agreement formula rates. The APSC, the MPSC, and the City Council intervened in the proceeding.

In June 2018, System Energy and Entergy Services filed a motion to dismiss and an answer to the LPSC complaint denying that System Energy’s treatment of the sale-leaseback renewal and capital additions violated the terms of the filed rate or any other FERC ratemaking, accounting, or legal requirements or otherwise constituted double recovery. The response also argued that the complaint was inconsistent with a FERC-approved settlement to which the LPSC is a party and that explicitly authorized System Energy to recover its lease payments. Finally, the response argued that both the capital additions and the sale-leaseback renewal were prudent investments and the LPSC complaint failed to justify any disallowance or refunds. The response also offered to submit formula rate protocols for the Unit Power Sales Agreement similar to the procedures used for reviewing transmission rates under the MISO tariff. In September 2018 the FERC issued an order setting the complaint for hearing and settlement proceedings and establishing a refund effective date of May 18, 2018.

In February 2019 the presiding ALJ ruled that the hearing ordered by the FERC includes the issue of whether specific subcategories of accumulated deferred income tax should be included in, or excluded from, System Energy’s formula rate. Testimony was filed by the LPSC, the MPSC, the APSC, the City Council, the FERC trial staff, and System Energy between March 2019 and October 2019. The final positions of the parties, after all pre-filed testimony was submitted, were as follows. The LPSC sought refunds that included the renewal lease payments (approximately $17.2 million per year since July 2015), rate base reductions for accumulated deferred income tax associated with uncertain tax positions (with a corresponding refund of approximately $512 million), and the cost of capital additions associated with the sale-leaseback interest, as well as interest on those amounts. The LPSC also argued that adjustments to depreciation rates should require retroactive depreciation expense refunds but only prospective rate base adjustments. The APSC, the MPSC, and the City Council generally agreed with the LPSC’s positions. The FERC trial staff argued for refunds for rate base reductions for liabilities associated with uncertain tax positions, and also argued that System Energy recovered $32 million more than it should have in depreciation expense for capital additions. System Energy filed testimony asking the FERC to reject all of the LPSC’s claims for refunds and opposing the FERC trial staff’s position regarding the uncertain tax position issue. System Energy also argued that the FERC trial staff’s position regarding depreciation rates for capital additions was not unreasonable, but any change in depreciation expense is only one element of a Unit Power Sales Agreement re-billing calculation. Adjustments to depreciation expense in any re-billing under the Unit Power Sales Agreement formula rate would also involve changes to accumulated depreciation, accumulated deferred income taxes, and other formula elements as needed.

After holding a hearing in November 2019, in April 2020 the FERC ALJ issued the initial decision. Among other things, the ALJ determined that refunds were due on three main issues. First, with regard to the lease renewal payments, the ALJ determined that System Energy was recovering an unjust acquisition premium through the lease renewal payments, and that System Energy’s recovery from customers through rates should be limited to the cost of service based on the remaining net book value of the leased assets, which was approximately $70 million. The ALJ found that the remedy for this issue should be the refund of lease payments (approximately $17.2 million per year since July 2015) with interest determined at the FERC quarterly interest rate, which would be offset by the addition
of the net book value of the leased assets in the cost of service. The ALJ did not calculate a value for the refund expected as a result of this remedy. In addition, System Energy would no longer recover the lease payments in rates prospectively. Second, with regard to the liabilities associated with uncertain tax positions, the ALJ determined that the liabilities are accumulated deferred income taxes and that System Energy’s rate base should have been reduced for those liabilities. The ALJ also found that System Energy should include liabilities associated with uncertain tax positions as a rate base reduction going forward. Third, with regard to the depreciation expense adjustments, the ALJ found that System Energy should correct for the error in re-billings retroactively and prospectively, but that System Energy should not be permitted to recover interest on any retroactive return on enhanced rate base resulting from such corrections.

In June 2020, System Energy, the LPSC, and the FERC trial staff filed briefs on exceptions, challenging several of the initial decision’s findings. System Energy’s brief on exceptions challenged the initial decision’s limitations on recovery of the lease renewal payments, its proposed rate base refund for the liabilities associated with uncertain tax positions, and its proposal to asymmetrically treat interest on bill corrections for depreciation expense adjustments. The LPSC’s and the FERC trial staff’s briefs on exceptions each challenged the initial decision’s allowance for recovery of the cost of service associated with the lease renewal based on the remaining net book value of the leased assets, its calculation of the remaining net book value of the leased assets, and the amount of the initial decision’s proposed rate base refund for the liabilities associated with uncertain tax positions. The LPSC’s brief on exceptions also challenged the initial decision’s proposal that depreciation expense adjustments include retroactive adjustments to rate base and its finding that section 203 of the Federal Power Act did not apply to the lease renewal. The FERC trial staff’s brief on exceptions also challenged the initial decision’s finding that the FERC need not institute a formal investigation into System Energy’s tariff. In October 2020, System Energy, the LPSC, the MPSC, the APSC, and the City Council filed briefs opposing exceptions. System Energy opposed the exceptions filed by the LPSC and the FERC trial staff. The LPSC, the MPSC, the APSC, the City Council, and the FERC trial staff opposed the exceptions filed by System Energy. Also in October 2020 the MPSC, the APSC, and the City Council filed briefs adopting the exceptions of the LPSC and the FERC trial staff.

In addition, in September 2020, the IRS issued a Notice of Proposed Adjustment (NOPA) and Entergy executed it. The NOPA memorialized the IRS’s decision to adjust the 2015 consolidated federal income tax return of Entergy Corporation and certain of its subsidiaries, including System Energy, with regard to the uncertain decommissioning tax position. Pursuant to the audit resolution documented in the NOPA, the IRS allowed System Energy’s inclusion of $102 million of future nuclear decommissioning costs in System Energy’s cost of goods sold for the 2015 tax year, roughly 10% of the requested deduction, but disallowed the balance of the position. In September 2020, System Energy filed a motion to lodge the NOPA into the record in the FERC proceeding. In October 2020 the LPSC, the APSC, the MPSC, the City Council, and the FERC trial staff filed oppositions to System Energy’s motion. As a result of the NOPA issued by the IRS in September 2020, System Energy filed, in October 2020, a new Federal Power Act section 205 filing at FERC to establish an ongoing rate base credit for the accumulated deferred income taxes resulting from the decommissioning uncertain tax position. On a prospective basis beginning with the October 2020 bill, System Energy proposed to include the accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position as a credit to rate base under the Unit Power Sales Agreement. In November 2020 the LPSC, the APSC, the MPSC, and the City Council filed a protest to the filing, and System Energy responded.

In November 2020 the IRS issued a Revenue Agent’s Report (RAR) for the 2014/2015 tax year and in December 2020 Entergy executed it. The RAR contained the same adjustment to the uncertain nuclear decommissioning tax position as that which the IRS had announced in the NOPA. In December 2020, System Energy filed a motion to lodge the RAR into the record in the FERC proceeding addressing the uncertain tax position rate base issue. In January 2021 the LPSC, the APSC, the MPSC, and the City Council filed a protest to the motion.

As a result of the RAR, in December 2020, System Energy filed amendments to its new Federal Power Act section 205 filings to establish an ongoing rate base credit for the accumulated deferred income taxes resulting from
the decommissioning uncertain tax position and to credit excess accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position. The amendments both proposed the inclusion of the RAR as support for the filings. In December 2020 the LPSC, the APSC, and the City Council filed protests to the amendments. In February 2021 the FERC issued an order accepting System Energy’s Federal Power Act section 205 filings subject to refund, setting them for hearing, and holding the hearing in abeyance.

In December 2020, System Energy filed a new Federal Power Act section 205 filing to provide a one-time, historical credit of $25.2 million for the accumulated deferred income taxes that would have been created by the decommissioning uncertain tax position if the IRS’s decision had been known in 2016. In January 2021 the LPSC, APSC, MPSC, and City Council filed a protest to the filing. In February 2021 the FERC issued an order accepting System Energy’s Federal Power Act section 205 filing subject to refund, setting it for hearing, and holding the hearing in abeyance. System Energy provided the one-time credit during the first quarter 2021.

In December 2022 the FERC issued an order on the ALJ’s initial decision, which affirmed it in part and modified it in part. The FERC’s order directed System Energy to calculate refunds on three issues, and to provide a compliance report detailing the calculations. The FERC’s order also disallowed the future recovery of sale-leaseback renewal costs, which is estimated at approximately $11.5 million annually for purchases from Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans through July 2036. The three refund issues were rental expenses related to the renewal of the sale-leaseback arrangements; refunds, if any, for the revenue requirement impact of including accumulated deferred income taxes resulting from the decommissioning uncertain tax positions from 2004 through the present; and refunds for the net effect of correcting the depreciation inputs for capital additions attributable to the portion of plant subject to the sale-leaseback.

As a result of the FERC order’s directives regarding the recovery of the sale-leaseback transaction, in December 2022 System Energy reduced the Grand Gulf sale-leaseback regulatory liability by $56 million, reduced the related accumulated deferred income tax asset by $94 million, and reduced the Grand Gulf sale-leaseback accumulated deferred income tax regulatory liability by $25 million, resulting in an increase in income tax expense of $13 million. In addition, the FERC determined that System Energy recognized excess depreciation expense related to property subject to the sale-leaseback. As a result, in December 2022, System Energy recorded a reduction in depreciation expense and the related accumulated depreciation of $33 million.

In January 2023, System Energy filed its compliance report with the FERC. With respect to the sale-leaseback renewal costs, System Energy calculated a refund of $89.8 million, which represented all of the sale-leaseback renewal rental costs that System Energy recovered in rates, with interest. With respect to the decommissioning uncertain tax position issue, System Energy calculated that no additional refunds were owed because it had already provided a one-time historical credit (for the period January 2016 through September 2020) of $25.2 million based on the accumulated deferred income taxes that resulted from the IRS’s partial acceptance of the decommissioning tax position, and because it has been providing an ongoing rate base credit for the accumulated deferred income taxes that resulted from the IRS’s partial acceptance of the decommissioning tax position since October 2020. With respect to the depreciation refund, System Energy calculated a refund of $13.7 million, which is the net total of a refund to customers for excess depreciation expense previously collected, plus interest, offset by the additional return on rate base that System Energy previously did not collect, without interest. See “System Energy Settlement with the MPSC” below for discussion of the regulatory charge and corresponding regulatory liability recorded in June 2022 related to these proceedings. In January 2023, System Energy paid the refunds of $103.5 million, which included refunds of $41.7 million to Entergy Arkansas, $27.8 million to Entergy Louisiana, and $34 million to Entergy New Orleans.

In February 2023 the LPSC, the APSC, and the City Council filed protests to System Energy’s January 2023 compliance report, in which they challenged System Energy’s calculation of the refunds associated with the decommissioning tax position but did not protest the other components of the compliance report. Each of them argued that System Energy should have paid additional refunds for the decommissioning tax position issue, and the City Council estimated the total additional refunds owed to customers of Entergy Louisiana, Entergy New Orleans,
and Entergy Arkansas for that issue as $493 million, including interest (and without factoring in the $25.2 million refund that System Energy already paid in 2021).

In January 2023, System Energy filed a request for rehearing of the FERC’s determinations in the December 2022 order on sale-leaseback refund issues and future lease cost disallowances, the FERC’s prospective policy on uncertain tax positions, and the proper accounting of System Energy’s accumulated deferred income taxes adjustment for the Tax Cuts and Jobs Act of 2017; and a motion for confirmation of its interpretation of the December 2022 order’s remedy concerning the decommissioning tax position. In January 2023 the retail regulators filed a motion for confirmation of their interpretation of the refund requirement in the December 2022 FERC order and a provisional request for rehearing. In February 2023 the FERC issued a notice that the rehearing requests were denied by operation of law. In March 2023, System Energy filed in the United States Court of Appeals for the Fifth Circuit a petition for review of the December 2022 order. In March 2023, System Energy also filed an unopposed motion to stay the proceeding in the Fifth Circuit pending the FERC’s disposition of the pending motions, and the court granted the motion to stay.

In February 2023, System Energy submitted a tariff compliance filing with the FERC to clarify that, consistent with the releases provided in the MPSC settlement, Entergy Mississippi will continue to be charged for its allocation of the sale-leaseback renewal costs under the Unit Power Sales Agreement. See “System Energy Settlement with the MPSC” below for discussion of the settlement. In March 2023 the MPSC filed a protest to System Energy’s tariff compliance filing. The MPSC argues that the settlement did not specifically address post-settlement sale-leaseback renewal costs and that the sale-leaseback renewal costs may not be recovered under the Unit Power Sales Agreement. Entergy Mississippi’s allocated sale-leaseback renewal costs are estimated at $5.7 million annually for the remaining term of the sale-leaseback renewal.

In August 2023 the FERC issued an order addressing arguments raised on rehearing and partially setting aside the prior order (rehearing order). The rehearing order addressed rehearing requests that were filed in January 2023 separately by System Energy and the LPSC, the APSC, and the City Council.

In the rehearing order, the FERC directed System Energy to recalculate refunds for two issues: (1) refunds of rental expenses related to the renewal of the sale-leaseback arrangements and (2) refunds for the net effect of correcting the depreciation inputs for capital additions associated with the sale-leaseback. With regard to the sale-leaseback renewal rental expenses, the rehearing order allowed System Energy to recover an implied return of and on the depreciated cost of the portion of the plant subject to the sale-leaseback as of the expiration of the initial lease term. With regard to the depreciation input issue, the rehearing order allowed System Energy to offset refunds so that System Energy may collect interest on the rate base recalculations that were part of the overall depreciation rate recalculations. The rehearing order further directed System Energy to submit within 60 days of the date of the rehearing order an additional compliance filing to revise the total refunds for these two issues. As discussed above, System Energy’s January 2023 compliance filing calculated $103.5 million in total refunds, and the refunds were paid in January 2023. In October 2023, System Energy filed its compliance report with the FERC as directed in the August 2023 rehearing order. The October 2023 compliance report reflected recalculated refunds totaling $35.7 million for the two issues resulting in $67.8 million in refunds that could be recouped by System Energy. As discussed below in “System Energy Settlement with the APSC,” System Energy reached a settlement in principle with the APSC to resolve several pending cases under the FERC’s jurisdiction, including this one, pursuant to which it agreed not to recoup the $27.3 million calculated for Entergy Arkansas in the compliance filing. As a result of the FERC’s rulings on the sale-leaseback and depreciation input issues in the August 2023 rehearing order, in third quarter 2023, System Energy recorded a regulatory asset and corresponding regulatory credit of $40 million to reflect the portion of the January 2023 refunds to be recouped from Entergy Louisiana and Entergy New Orleans. Consistent with the compliance filing, in October 2023, Entergy Louisiana and Entergy New Orleans paid recoupment amounts of $18.2 million and $22.3 million, respectively, to System Energy.
On the third refund issue identified in the rehearing requests, concerning the decommissioning uncertain tax positions, the rehearing order denied all rehearing requests, re-affirmed the remedy contained in the December 2022 order, and did not direct System Energy to recalculate refunds or to submit an additional compliance filing.

In September 2023, System Energy filed a protective appeal of the rehearing order with the United States Court of Appeals for the Fifth Circuit. The appeal was consolidated with System Energy’s prior appeal of the December 2022 order.

In September 2023 the LPSC filed with the FERC a request for rehearing and clarification of the rehearing order. The LPSC requested that the FERC reverse its determination in the rehearing order that System Energy may collect an implied return of and on the depreciated cost of the portion of the plant subject to the sale-leaseback, as of the expiration of the initial lease term, as well as its determination in the rehearing order that System Energy may offset the refunds for the depreciation rate input issue and collect interest on the rate base recalculations that were part of the overall depreciation rate recalculations. In addition, the LPSC requested that the FERC either confirm the LPSC’s interpretation of the refund associated with the decommissioning uncertain tax positions or explain why it is not doing so. In October 2023 the FERC issued a notice that the rehearing request was deemed denied by operation of law. In November 2023 the FERC issued a further notice stating that it would not issue any further order addressing the rehearing request. Also in November 2023 the LPSC filed with the United States Court of Appeals for the Fifth Circuit a petition for review of the FERC’s August 2023 rehearing order and denials of the September 2023 rehearing request.

In December 2023 the United States Court of Appeals for the Fifth Circuit lifted the abeyance on the consolidated System Energy appeals and it also consolidated the LPSC’s appeal with the System Energy appeals. Briefing of the appeals occurred between March 2024 and July 2024. In September 2024 the parties filed a joint motion to continue and stay oral argument, previously scheduled for October 2024, pending the FERC’s decision whether to approve the settlement between System Energy and the LPSC, and the United States Court of Appeals for the Fifth Circuit granted the motion. In November 2024, after the FERC issued the order approving the settlement between System Energy and the LPSC, System Energy, the LPSC, the APSC, and the FERC filed a joint stipulation to dismiss the pending appeals, which the United States Court of Appeals for the Fifth Circuit granted.

As discussed below in “System Energy Settlement with the MPSC,” “System Energy Settlement with the APSC,” “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the MPSC, the APSC, the City Council, and the LPSC have settled their claims related to this proceeding.

LPSC Additional Complaints

In May 2020 the LPSC authorized its staff to file additional complaints at the FERC related to the rates charged by System Energy for Grand Gulf energy and capacity supplied to Entergy Louisiana under the Unit Power Sales Agreement. The LPSC directive noted that the initial decision issued by the presiding ALJ in the Grand Gulf sale-leaseback complaint proceeding did not address, for procedural reasons, certain rate issues raised by the LPSC and declined to order further investigation of rates charged by System Energy.

Unit Power Sales Agreement Complaint

The first of the additional complaints was filed by the LPSC, the APSC, the MPSC, and the City Council in September 2020. The first complaint raised two sets of rate allegations: violations of the filed rate and a corresponding request for refunds for prior periods; and elements of the Unit Power Sales Agreement are unjust and unreasonable and a corresponding request for refunds for the 15-month refund period and changes to the Unit Power Sales Agreement prospectively. Several of the filed rate allegations overlapped with the previous complaints. The filed rate allegations not previously raised were that System Energy: failed to provide a rate base credit to customers for the “time value” of sale-leaseback lease payments collected from customers in advance of the time those payments were due to the owner-lessors; improperly included certain sale-leaseback transaction costs in rate base as
prepayments; improperly included nuclear refueling outage costs in rate base; wrongly included categories of accumulated deferred income taxes as increases to rate base; charged customers based on a higher equity ratio than would be appropriate due to excessive retained earnings; and did not correctly reflect money pool investments and imprudently invested cash into the money pool. The elements of the Unit Power Sales Agreement that the complaint alleged were unjust and unreasonable include: the current cash working capital allowance of zero, uncapped recovery of incentive and executive compensation, lack of an equity re-opener, and recovery of lobbying and private airplane travel expenses. The complaint also requested a rate investigation into the Unit Power Sales Agreement and System Energy’s billing practices pursuant to section 206 of the Federal Power Act, including any issue relevant to the Unit Power Sales Agreement and its inputs. System Energy filed its answer opposing the complaint in November 2020. In its answer, System Energy argued that all of the claims raised in the complaint should be dismissed and agreed that bill adjustment with respect to two discrete issues were justified. System Energy argued that dismissal was warranted because all claims fell into one or more of the following categories: the claims had been raised and were being litigated in another proceeding; the claims did not present a prima facie case and did not satisfy the threshold burden to establish a complaint proceeding; the claims were premised on a theory or request relief that is incompatible with federal law or FERC policy; the claims request relief that is inconsistent with the filed rate; the claims were barred or waived by the legal doctrine of laches; and/or the claims had been fully addressed and do not warrant further litigation. In December 2020, System Energy filed a bill adjustment report indicating that $3.4 million had been credited to customers in connection with the two discrete issues concerning the inclusion of certain accumulated deferred income taxes balances in rates.

In May 2021 the FERC issued an order addressing the complaint, establishing a refund effective date of September 21, 2020, establishing hearing procedures, and holding those procedures in abeyance pending the FERC’s review of the initial decision in the Grand Gulf sale-leaseback renewal complaint discussed above. System Energy agreed that the hearing should be held in abeyance but sought rehearing of FERC’s decision as related to matters set for hearing that were beyond the scope of FERC’s jurisdiction or authority. The complainants sought rehearing of FERC’s decision to hold the hearing in abeyance and filed a motion to proceed, which motion System Energy opposed. In June 2021, System Energy’s request for rehearing was denied by operation of law, and System Energy filed an appeal of FERC’s orders in the Court of Appeals for the Fifth Circuit. In November 2021 the Fifth Circuit dismissed the appeal as premature.

In August 2021 the FERC issued an order addressing System Energy’s and the complainants’ rehearing requests. The FERC dismissed part of the complaint seeking an equity re-opener, maintained the abeyance for issues related to the proceeding addressing the sale-leaseback renewal and uncertain tax positions, lifted the abeyance for issues unrelated to that proceeding, and clarified the scope of the hearing.

In November 2021 the LPSC, the APSC, and the City Council filed direct testimony and requested the FERC to order refunds for prior periods and prospective amendments to the Unit Power Sales Agreement. The LPSC’s refund claims included, among other things, allegations that: (1) System Energy should not have included certain sale-leaseback transaction costs in prepayments; (2) System Energy should have credited rate base to reflect the time value of money associated with the advance collection of lease payments; (3) System Energy incorrectly included refueling outage costs that were recorded in account 174 in rate base; and (4) System Energy should have excluded several accumulated deferred income tax balances in account 190 from rate base. The LPSC also sought a retroactive adjustment to retained earnings and capital structure in conjunction with the implementation of its proposed refunds. In addition, the LPSC sought amendments to the Unit Power Sales Agreement going forward to address below-the-line costs, incentive compensation, the working capital allowance, litigation expenses, and the 2019 termination of the capital funds agreement. The APSC argued that: (1) System Energy should have included borrowings from the Entergy system money pool in its determination of short-term debt in its cost of capital; and (2) System Energy should credit customers with System Energy’s allocation of earnings on money pool investments. The City Council alleged that System Energy has maintained excess cash on hand in the money pool and that retention of excess cash was imprudent. Based on this allegation, the City Council’s witness recommended a refund of approximately $98.8 million for the period 2004-September 2021 or other alternative relief. The City Council
further recommended that the FERC impose a hypothetical equity ratio such as 48.15% equity to capital on a prospective basis.

In January 2022, System Energy filed answering testimony arguing that the FERC should not order refunds for prior periods or any prospective amendments to the Unit Power Sales Agreement. In response to the LPSC’s refund claims, System Energy argued, among other things, that: (1) the inclusion of sale-leaseback transaction costs in prepayments was correct; (2) that the filed rate doctrine bars the request for a retroactive credit to rate base for the time value of money associated with the advance collection of lease payments; (3) that an accounting misclassification for deferred refueling outage costs had been corrected, caused no harm to customers, and requires no refunds; and (4) that its accounting and ratemaking treatment of specified accumulated deferred income tax balances in account 190 had been correct. System Energy further responded that no retroactive adjustment to retained earnings or capital structure should be ordered because there was no general policy requiring such a remedy, and there was no showing that the retained earnings element of the capital structure was incorrectly implemented. Further, System Energy presented evidence that all of the costs that were being challenged were long known to the retail regulators and were approved by them for inclusion in retail rates, and the attempt to retroactively challenge these costs, some of which had been included in rates for decades, was unjust and unreasonable. In response to the LPSC’s proposed going-forward adjustments, System Energy presented evidence to show that none of the proposed adjustments were needed. On the issue of below-the-line expenses, during discovery procedures System Energy identified a historical allocation error in certain months and agreed to provide a bill credit to customers to correct the error. In response to the APSC’s claims, System Energy argued that the Unit Power Sales Agreement did not include System Energy’s borrowings from the Entergy system money pool or earnings on deposits to the Entergy system money pool in the determination of the cost of capital; and accordingly, no refunds were appropriate on those issues. In response to the City Council’s claims, System Energy argued that it has reasonably managed its cash and that the City Council’s theory of cash management was defective because it failed to adequately consider the relevant cash needs of System Energy and it made faulty presumptions about the operation of the Entergy system money pool. System Energy further pointed out that the issue of its capital structure was already subject to pending FERC litigation.

In March 2022 the FERC trial staff filed direct and answering testimony in response to the LPSC, the APSC, and the City Council’s direct testimony. In its testimony, the FERC trial staff recommended refunds for two primary reasons: (1) it concluded that System Energy should have excluded specified accumulated deferred income tax balances in account 190 associated with rate refunds; and (2) it concluded that System Energy should have excluded specified accumulated deferred income tax balances in account 190 associated with a deemed contract satisfaction and reissuance that occurred in 2005. The FERC trial staff recommended refunds of $84.1 million, exclusive of any tax gross-up or FERC interest. In addition, the FERC trial staff recommended the following prospective modifications to the Unit Power Sales Agreement: (1) inclusion of a rate base credit to recognize the time value of money associated with the advance collection of lease payments; (2) exclusion of executive incentive compensation costs for members of the Office of the Chief Executive and long-term performance unit costs where awards are based solely or primarily on financial metrics; and (3) exclusion of unvested, accrued amounts for stock options, performance units, and restricted stock awards. With respect to issues that ultimately concerned the reasonableness of System Energy’s rate of return, the FERC trial staff stated that it was unnecessary to consider such issues in the proceeding, in light of the pending case concerning System Energy’s return on equity and capital structure. On all other material issues raised by the LPSC, the APSC, and the City Council, the FERC trial staff recommended either no refunds or no modification to the Unit Power Sales Agreement.

In April 2022, System Energy filed cross-answering testimony in response to the FERC trial staff’s recommendations of refunds for the accumulated deferred income taxes issues and proposed modifications to the Unit Power Sales Agreement for the executive incentive compensation issues. In June 2022 the FERC trial staff submitted revised answering testimony, in which it recommended additional refunds associated with the accumulated deferred income tax balances in account 190 associated with a deemed contract satisfaction and reissuance that occurred in 2005. Based on the testimony revisions, the FERC trial staff’s recommended refunds total $106.6 million, exclusive of any tax gross-up or FERC awarded interest. Also in June 2022, System Energy
filed revised and supplemental cross-answering testimony to respond to the FERC trial staff’s testimony and oppose its revised recommendation.

In May 2022 the LPSC, the APSC, and the City Council filed rebuttal testimony. The LPSC’s testimony asserted new claims, including that: (1) certain of the sale-leaseback transaction costs may have been imprudently incurred; (2) accumulated deferred income taxes associated with sale-leaseback transaction costs should have been included in rate base; (3) accumulated deferred income taxes associated with federal investment tax credits should have been excluded from rate base; (4) monthly net operating loss accumulated deferred income taxes should have been excluded from rate base; and (5) several categories of proposed rate changes, including executive incentive compensation, air travel, industry dues, and legal costs, also warranted historical refunds. The LPSC’s rebuttal testimony argued that refunds for the alleged tariff violations and other claims must be calculated by rerunning the Unit Power Sales Agreement formula rate; however, it included estimates of refunds associated with some, but not all, of its claims, totaling $286 million without interest. The City Council’s rebuttal testimony also proposed a new, alternate theory and claim for relief regarding System Energy’s participation in the Entergy system money pool, under which it calculates estimated refunds of approximately $51.7 million. The APSC’s rebuttal testimony agreed with the LPSC’s direct testimony that retained earnings should be adjusted in a comprehensive refund calculation. The testimony quantified the estimated impacts of three issues: (1) a $1.5 million reduction in the revenue requirement under the Unit Power Sales Agreement if System Energy’s borrowings from the money pool were included in short-term debt; (2) a $1.9 million reduction in the revenue requirement if System Energy’s allocated share of money pool earnings were credited through the Unit Power Sales Agreement; and (3) a $1.9 million reduction in the revenue requirement for every $50 million of refunds ordered in a given year, without interest. In total, excluding the settled issues noted below, the claims sought more than $700 million in refunds and interest, based on charges to all Unit Power Sales Agreement purchasers including Entergy Mississippi. The hearing before a FERC ALJ occurred between September and December 2022.

In November 2022, System Energy filed a partial settlement agreement with the APSC, the City Council, and the LPSC that resolved the following issues raised in the Unit Power Sales Agreement complaint: advance collection of lease payments, aircraft costs, executive incentive compensation, money pool borrowings, advertising expenses, deferred nuclear refueling outage costs, industry association dues, and termination of the capital funds agreement. The settlement provided that System Energy would provide a black box refund of $18 million (inclusive of interest), plus additional refund amounts with interest to be calculated for certain issues to be distributed to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans as the Utility operating companies other than Entergy Mississippi purchasing under the Unit Power Sales Agreement. The settlement further provided that if the APSC, the City Council, or the LPSC agreed to the global settlement System Energy entered into with the MPSC (discussed below), and such global settlement included a black box refund amount, then the black box refund for this settlement agreement would not be incremental or in addition to the global black box refund amount. The settlement agreement addressed other matters as well, including adjustments to rate base beginning in October 2022, exclusion of certain other costs, and inclusion of money pool borrowings, if any, in short-term debt within the cost of capital calculation used in the Unit Power Sales Agreement. In April 2023 the FERC approved the settlement agreement. The refund provided for in the settlement agreement was included in the May 2023 service month bills under the Unit Power Sales Agreement.

In May 2023 the presiding ALJ issued an initial decision finding that System Energy should have excluded multiple identified categories of accumulated deferred income taxes from rate base when calculating Unit Power Sales Agreement bills. The initial decision also found that the Unit Power Sales Agreement should be modified such that a cash working capital allowance of negative $36.4 million is applied prospectively. On the other non-settled issues for which the complainants sought refunds or changes to the Unit Power Sales Agreement, the initial decision ruled against the complainants.

System Energy disagreed with the ALJ’s findings concerning the accumulated deferred income taxes issues and cash working capital. In July 2023, System Energy filed a brief on exceptions to the initial decision’s accumulated deferred income taxes findings. Also in July 2023, the APSC, the LPSC, the City Council, and the
FERC trial staff filed separate briefs on exceptions. In August 2023 all parties filed separate briefs opposing exceptions.

As discussed below in “System Energy Settlement with the MPSC,” “System Energy Settlement with the APSC,” and “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the MPSC, the APSC, and the City Council, and the LPSC have settled their claims related to this proceeding.

Grand Gulf Prudence Complaints

The second of the additional complaints was filed at the FERC in March 2021 by the LPSC, the APSC, and the City Council against System Energy, Entergy Services, Entergy Operations, and Entergy Corporation. The second complaint contained two primary allegations. First, it alleged that, based on the plant’s capacity factor and alleged safety performance, System Energy and the other respondents imprudently operated Grand Gulf during the period 2016-2020, and it sought refunds of at least $360 million in alleged replacement energy costs, in addition to other costs, including those that could only be identified upon further investigation. Second, it alleged that the performance and/or management of the 2012 extended power uprate of Grand Gulf was imprudent, and it sought refunds of all costs of the 2012 uprate that were determined to result from imprudent planning or management of the project. In addition to the requested refunds, the complaint asked that the FERC modify the Unit Power Sales Agreement to provide for full cost recovery only if certain performance indicators were met and to require pre-authorization of capital improvement projects in excess of $125 million before related costs could be passed through to customers in rates. In April 2021, System Energy and the other respondents filed their motion to dismiss and answer to the complaint. System Energy requested that the FERC dismiss the claims within the complaint. With respect to the claim concerning operations, System Energy argued that the complaint did not meet its legal burden because, among other reasons, it failed to allege any specific imprudent conduct. With respect to the claim concerning the uprate, System Energy argued that the complaint failed because, among other reasons, the complainants’ own conduct prevented them from raising a serious doubt as to the prudence of the uprate. System Energy also requested that the FERC dismiss other elements of the complaint, including the proposed modifications to the Unit Power Sales Agreement, because they were not warranted. In February 2023 the FERC issued an order denying rehearing and thereby affirming its order setting the complaint for settlement and hearing procedures. In July 2023 the FERC chief ALJ terminated settlement procedures and appointed a presiding ALJ to oversee hearing procedures. In September 2023 a procedural schedule for hearing procedures was established. Also in September 2023 the LPSC authorized its staff to file an additional complaint concerning the prudence of System Energy’s operation and management of Grand Gulf in the year 2022. In October 2023 the LPSC, the APSC, and the City Council filed what they styled as an amended and supplemental complaint with the FERC against System Energy, Entergy Services, and Entergy Operations. In November 2023, System Energy answered the amended and supplemental complaint. Pursuant to the procedural schedule, the complainants’ testimony in the original complaint proceeding was filed in December 2023. System Energy’s answering testimony was filed in May 2024, and the FERC trial staff’s direct and answering testimony was filed in June 2024.

As discussed below in “System Energy Settlement with the APSC,” “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the APSC, the City Council, and the LPSC have settled all of their claims related to this proceeding.

System Energy Settlement with the MPSC

In June 2022, System Energy, Entergy Mississippi, and additional named Entergy parties involved in thirteen docketed proceedings before the FERC filed with the FERC a partial settlement agreement and offer of settlement. The settlement memorialized the Entergy parties’ agreement with the MPSC to globally resolve all actual and potential claims between the Entergy parties and the MPSC associated with those FERC proceedings and with System Energy’s past implementation of the Unit Power Sales Agreement. The Unit Power Sales Agreement is a FERC-jurisdictional formula rate tariff for sales of energy and capacity from System Energy’s owned and
leased share of Grand Gulf to Entergy Mississippi, Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans. Entergy Mississippi purchases the greatest single amount, nearly 40% of System Energy’s share of Grand Gulf, after its additional purchases from affiliates are considered.

The settlement provided for a black box refund of $235 million from System Energy to Entergy Mississippi. In addition, beginning with the July 2022 service month, the settlement provided for Entergy Mississippi’s bills from System Energy to be adjusted to reflect: an authorized rate of return on equity of 9.65%, a capital structure not to exceed 52% equity, a rate base reduction for the advance collection of sale-leaseback rental costs, and the exclusion of certain long-term incentive plan performance unit costs from rates. The settlement was approved by the MPSC in June 2022 and the FERC in November 2022.

System Energy had previously recorded a provision and associated liability of $37 million for elements of the applicable litigation. In June 2022, System Energy recorded a regulatory charge of $551 million ($413 million net-of-tax), increasing the regulatory liability to $588 million, which consisted of $235 million for the settlement with the MPSC and $353 million for potential future refunds to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans. System Energy paid the black box refund of $235 million to Entergy Mississippi in November 2022.

System Energy Settlement with the APSC

In October 2023, System Energy, Entergy Arkansas, and additional named Entergy parties involved in multiple docketed proceedings pending before the FERC reached a settlement in principle with the APSC to globally resolve all of their actual and potential claims in those dockets and with System Energy’s past implementation of the Unit Power Sales Agreement. The settlement also covered the amended and supplemental complaint, discussed above in “Grand Gulf Prudence Complaint,” filed at the FERC in October 2023. System Energy, Entergy Arkansas, additional Entergy parties, and the APSC filed the settlement agreement and supporting materials with the FERC in November 2023.

The terms of the settlement with the APSC aligned with the $588 million global black box settlement reached between System Energy and the MPSC in June 2022 and provided for Entergy Arkansas to receive a black box refund of $142 million from System Energy, inclusive of $49.5 million already received by Entergy Arkansas from System Energy. In addition, beginning with the November 2023 service month, the settlement provided for Entergy Arkansas’s bills from System Energy to be adjusted to reflect an authorized rate of return on equity of 9.65% and a capital structure not to exceed 52% equity. In March 2024 the FERC approved the settlement, and System Energy paid the remaining black box refund of $93 million to Entergy Arkansas in 2024.

System Energy Settlement with the City Council

In April 2024, System Energy, Entergy New Orleans, and additional named Entergy parties involved in multiple docketed proceedings pending before the FERC reached a settlement in principle with the City Council to globally resolve all of their actual and potential claims in those dockets and with System Energy’s past implementation of the Unit Power Sales Agreement. The settlement also covered the amended and supplemental complaint, discussed in “Grand Gulf Prudence Complaints” above, filed by the LPSC, the APSC, and the City Council at the FERC in October 2023. In May 2024, System Energy, Entergy New Orleans, additional named Entergy parties, and the City Council filed the settlement agreement and supporting materials with the FERC.

The terms of the settlement with the City Council aligned with the $588 million global black box settlement amount reflected in the prior settlements reached between System Energy and the MPSC in June 2022 and between System Energy and the APSC in November 2023. The settlement provided for Entergy New Orleans to receive a black box refund of $116 million from System Energy, inclusive of approximately $18 million already received by Entergy New Orleans from System Energy. In addition, beginning with the June 2024 service month, the settlement provided for Entergy New Orleans’s bills from System Energy to be adjusted to reflect an authorized rate of return on equity of 9.65% and a capital structure not to exceed 52% equity. In August 2024 the FERC approved the
settlement, and System Energy paid the remaining black box refund of $98 million to Entergy New Orleans in October 2024.

System Energy Settlement with the LPSC

In July 2024, System Energy and the LPSC staff reached a settlement in principle to globally resolve all of the LPSC’s actual and potential claims in multiple docketed proceedings pending before the FERC (including all docketed proceedings resolved by the MPSC, the APSC, and the City Council settlements) and with System Energy’s past implementation of the Unit Power Sales Agreement. The settlement also covered the amended and supplemental complaint, discussed above in “Grand Gulf Prudence Complaints,” filed by the LPSC, the APSC, and the City Council at the FERC in October 2023. In August 2024 the LPSC approved the settlement. In September 2024 the settling parties filed the settlement for approval by the FERC.

The terms of the settlement with the LPSC staff aligned with the $588 million global black box settlement amount reflected in the prior settlements reached between System Energy and the MPSC in June 2022, between System Energy and the APSC in November 2023, and between System Energy and the City Council in April 2024. The settlement in principle provided for Entergy Louisiana to receive a black box refund of $95 million from System Energy, inclusive of approximately $15 million already received by Entergy Louisiana from System Energy. In addition, beginning with the September 2024 service month, the settlement provided for Entergy Louisiana’s bills from System Energy to be adjusted to reflect an authorized rate of return on equity of 9.65% and a capital structure not to exceed 52% equity. In November 2024 the FERC approved the settlement, and System Energy paid the remaining black box refund of $80 million to Entergy Louisiana in December 2024.

The settlement also included an agreement that, subject to the receipt of necessary regulatory approvals, Entergy Louisiana will divest to Entergy Mississippi all of its interest in Grand Gulf capacity and energy under the Unit Power Sales Agreement and its purchases from Entergy Arkansas under the MSS-4 replacement tariff. In October 2024 Entergy Louisiana and Entergy Mississippi filed with the FERC a PPA under which Entergy Mississippi would purchase Entergy Louisiana’s purchases of Grand Gulf capacity and energy. The PPA is governed by the MSS-4 replacement tariff, a tariff governing the sales of energy and capacity among the Utility operating companies. The requisite approvals for the PPA were issued by the FERC in November 2024 and the MPSC in February 2025. The divestiture is effective as of January 1, 2025.

System Energy Regulatory Liability for Pending Complaints

Prior to June 2022, System Energy recorded a provision and associated liability of $37 million for elements of the complaints against System Energy. In June 2022, as discussed in “System Energy Settlement with the MPSC” above, System Energy recorded a regulatory charge of $551 million ($413 million net-of-tax), increasing System Energy’s regulatory liability to $588 million, which consisted of $235 million for the settlement with the MPSC and $353 million for potential future refunds to Entergy Arkansas, Entergy New Orleans, and Entergy Louisiana. System Energy paid the black box refund of $235 million to Entergy Mississippi in November 2022. As discussed above in “Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue,” in January 2023 System Energy paid refunds of $103.5 million as a result of the FERC’s order in December 2022 in that proceeding and recouped $40.5 million of the $103.5 million from Entergy Louisiana and Entergy New Orleans in October 2023. In addition, as discussed above in “Unit Power Sales Agreement Complaint,” a black box refund of $18 million was made by System Energy in 2023 in connection with a partial settlement in that proceeding. Based on analysis of the then-pending complaints against System Energy and potential future settlement negotiations with the LPSC and the City Council, in third quarter 2023, System Energy recorded a regulatory charge of $40 million to increase System Energy’s regulatory liability related to complaints against System Energy. In December 2023 the $93 million black box refund to Entergy Arkansas was reclassified from the regulatory liability to accounts payable - associated companies on System Energy’s balance sheet. System Energy paid the remaining black box refunds of $93 million to Entergy Arkansas, $98 million to Entergy New Orleans, and $80 million to Entergy Louisiana in 2024.
Unit Power Sales Agreement

System Energy Formula Rate Annual Protocols Formal Challenge Concerning 2020 Calendar Year Bills

System Energy’s Unit Power Sales Agreement includes formula rate protocols that provide for the disclosure of cost inputs, an opportunity for informal discovery procedures, and a challenge process. In February 2022, pursuant to the protocols procedures, the LPSC, the APSC, the MPSC, the City Council, and the Mississippi Public Utilities Staff filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2020. This formal challenge was ultimately settled as a result of System Energy’s global settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” above for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.

System Energy Formula Rate Annual Protocols Formal Challenge Concerning 2021 Calendar Year Bills

In March 2023, pursuant to the protocols procedures discussed above, the LPSC, the APSC, and the City Council filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2021. This formal challenge was ultimately settled as a result of System Energy’s global settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” above for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.

System Energy Formula Rate Annual Protocols Formal Challenge Concerning 2022 Calendar Year Bills

In February 2024, pursuant to the protocols procedures, the LPSC and the City Council filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2022. This formal challenge was ultimately settled as a result of System Energy’s global settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” above for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.

Depreciation Amendment Proceeding

In December 2021, System Energy submitted to the FERC proposed amendments to the Unit Power Sales Agreement to adopt updated rates for use in calculating Grand Gulf plant depreciation and amortization expenses. The proposed amendments would result in higher charges to the Utility operating companies that buy capacity and energy from System Energy under the Unit Power Sales Agreement. In February 2022 the FERC accepted System Energy’s proposed increased depreciation rates with an effective date of March 1, 2022, subject to refund pending the outcome of the settlement and/or hearing procedures. In June 2023 System Energy filed with the FERC an unopposed offer of settlement that it had negotiated with intervenors to the proceeding. In August 2023 the FERC approved the settlement, which resolves the proceeding. In third quarter 2023, System Energy recorded a reduction in depreciation expense of $41 million representing the cumulative difference in depreciation expense resulting from the depreciation rates used from March 2022 through June 2023 and the depreciation rates included in the settlement filing approved by the FERC. In October 2023, System Energy filed a refund report with the FERC. The refund provided for in the refund report was included in the September 2023 service month bills under the Unit Power Sales Agreement. No comments or protests to the refund report were filed.

Pension Costs Amendment Proceeding

In October 2021, System Energy submitted to the FERC proposed amendments to the Unit Power Sales Agreement to include in rate base the prepaid and accrued pension costs associated with System Energy’s qualified pension plans. Based on data ending in 2020, the increased annual revenue requirement associated with the filing is approximately $8.9 million. In March 2022 the FERC accepted System Energy’s proposed amendments with an
effective date of December 1, 2021, subject to refund pending the outcome of the settlement and/or hearing procedures. In August 2023 the FERC chief ALJ terminated settlement procedures and designated a presiding ALJ to oversee hearing procedures. Testimony was filed by the parties from October 2023 through April 2024, and the hearing concluded in June 2024.

In September 2024 the presiding ALJ issued an initial decision recommending that the FERC approve inclusion of a line item in rate base for prepaid and accrued pension costs; however, the presiding ALJ did not agree with System Energy’s proposed methodology to calculate the value of the prepaid and accrued pension cost input. Instead, the presiding ALJ recommended limiting System Energy’s recovery to the prepaid and accrued pension costs that were incurred beginning in 2015 and later.

System Energy disputes the presiding ALJ's determination concerning the methodology used to calculate the prepaid and accrued pension input, and System Energy filed exceptions to these rulings in October 2024. In October 2024, the LPSC, the APSC, and the FERC trial staff filed separate briefs on exceptions; these parties generally argue that the presiding ALJ should have rejected System Energy’s filing entirely, rather than limit System Energy’s recovery of the prepaid and accrued pension costs. Later in October 2024, System Energy, the LPSC, the APSC, and the FERC trial staff filed separate briefs opposing exceptions.

If the ALJ’s determination is affirmed by the FERC, System Energy estimates refunds, including interest through December 31, 2024, of approximately $16 million to $21 million would be owed. The ALJ's initial decision is not binding on the FERC and is an interim step in the hearing process. No refunds will be owed in connection with this proceeding and no changes to System Energy’s pension cost recovery methodology will be implemented unless and until the FERC requires them in a final order. This proceeding is not covered by the global settlements described above.
Storm Cost Recovery Filings with Retail Regulators

Entergy Louisiana

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.

In December 2024, and subsequently amended in an errata filed in February 2025, Entergy Louisiana submitted an application to the LPSC seeking a determination that approximately $183.6 million in storm restoration costs associated with Hurricane Francine were reasonable and necessary and, therefore, eligible for recovery from customers, as well as approval to recover approximately $3.6 million in certain carrying costs from customers. The $183.6 million includes approximately $152.8 million in distribution capital costs and approximately $29.8 million in non-capital costs; the balance consists of transmission and generation capital costs. Entergy Louisiana proposes in its application to recover its distribution-related capital costs of $152.8 million through the distribution recovery mechanism of its formula rate plan. Entergy Louisiana has further requested the LPSC to authorize recovery of these distribution-related capital expenses through an interim rate adjustment, subject to true-up and refund, that would begin with the first billing cycle of March 2025. Entergy Louisiana also requested to recover, from its storm reserve escrow account, $33.5 million, which consists of non-capital costs and certain carrying costs. Entergy Louisiana has also proposed to recover the transmission and generation capital costs through separate ratemaking proceedings. In February 2025, Entergy Louisiana withdrew the $33.5 million from its storm reserve escrow account. The period for intervention has expired, and a status conference for the purpose of establishing a procedural schedule has been set for March 2025.
Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida

In August 2020 and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of Entergy Louisiana’s service area. The storms resulted in widespread outages, significant damage to distribution and transmission infrastructure, and the loss of sales during the outages. Additionally, as a result of Hurricane Laura’s extensive damage to the grid infrastructure serving the impacted area, large portions of the underlying transmission system required nearly a complete rebuild.

In October 2020, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments in connection with the issuance of shorter-term mortgage bonds to provide interim financing for restoration costs associated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta. Subsequently, Entergy Louisiana and the LPSC staff filed a joint motion seeking approval to exclude from the derivation of Entergy Louisiana’s capital structure and cost rate of debt for ratemaking purposes, including the allowance for funds used during construction, shorter-term debt up to $1.1 billion issued by Entergy Louisiana to fund costs associated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta costs on an interim basis. In November 2020 the LPSC issued an order approving the joint motion, and Entergy Louisiana issued $1.1 billion of 0.62% Series mortgage bonds due November 2023. Also in November 2020, Entergy Louisiana withdrew $257 million from its funded storm reserves.

In February 2021 two winter storms (collectively, Winter Storm Uri) brought freezing rain and ice to Louisiana. Ice accumulation sagged or downed trees, limbs, and power lines, causing damage to Entergy Louisiana’s transmission and distribution systems. The additional weight of ice caused trees and limbs to fall into power lines and other electric equipment. When the ice melted, it affected vegetation and electrical equipment, causing additional outages. Entergy Louisiana recovered the incremental fuel costs associated with Winter Storm Uri over a five-month period from April 2021 through August 2021.

In April 2021, Entergy Louisiana filed an application with the LPSC relating to Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri restoration costs and in July 2021, Entergy Louisiana made a supplemental filing updating the total restoration costs. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by these storms were estimated to be approximately $2.06 billion, including approximately $1.68 billion in capital costs and approximately $380 million in non-capital costs. Including carrying costs through January 2022, Entergy Louisiana sought an LPSC determination that $2.11 billion was prudently incurred and, therefore, was eligible for recovery from customers. Additionally, Entergy Louisiana requested that the LPSC determine that re-establishment of a storm escrow account to the previously authorized amount of $290 million was appropriate. In July 2021, Entergy Louisiana supplemented the application with a request regarding the financing and recovery of the recoverable storm restoration costs. Specifically, Entergy Louisiana requested approval to securitize its restoration costs pursuant to Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021.

In August 2021, Hurricane Ida caused extensive damage to Entergy Louisiana’s distribution and, to a lesser extent, transmission systems resulting in widespread power outages. In September 2021, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments in connection with the issuance of approximately $1 billion of shorter-term mortgage bonds to provide interim financing for restoration costs associated with Hurricane Ida, which bonds were issued in October 2021. Also in September 2021, Entergy Louisiana sought approval for the creation and funding of a $1 billion restricted escrow account for Hurricane Ida related restoration costs, subject to a subsequent prudence review.

After filing of testimony by the LPSC staff and intervenors, which generally supported or did not oppose Entergy Louisiana’s requests in regard to Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida, the parties negotiated and executed an uncontested stipulated settlement which was filed with the LPSC in February 2022. The settlement agreement contained the following key terms: $2.1 billion of restoration costs from Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri were prudently incurred and
eligible for recovery; carrying costs of $51 million were recoverable; a $290 million cash storm reserve should be re-established; a $1 billion reserve should be established to partially pay for Hurricane Ida restoration costs; and Entergy Louisiana was authorized to finance $3.186 billion utilizing the securitization process authorized by Act 55, as supplemented by Act 293. The LPSC issued an order approving the settlement in March 2022. As a result of the financing order, Entergy Louisiana reclassified $1.942 billion from utility plant to other regulatory assets.

In May 2022 the securitization financing closed, resulting in the issuance of $3.194 billion principal amount of bonds by Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA), a political subdivision of the State of Louisiana. The securitization was authorized pursuant to the Louisiana Utilities Restoration Corporation Act, Part VIII of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana legislature approved in 2021. The LCDA loaned the proceeds to the LURC. Pursuant to Act 293, the LURC contributed the net bond proceeds to a State legislatively authorized and LURC-sponsored trust, Restoration Law Trust I (the storm trust I).

Pursuant to Act 293, the net proceeds of the bonds were used by the storm trust I to purchase 31,635,718.7221 Class A preferred, non-voting membership interest units (the preferred membership interests) issued by Entergy Finance Company. Entergy Finance Company is required to make annual distributions (dividends) commencing on December 15, 2022 on the preferred membership interests issued to the storm trust I. These annual dividends received by the storm trust I will be distributed to Entergy Louisiana and the LURC, as beneficiaries of the storm trust I. Specifically, 1% of the annual dividends received by the storm trust I will be distributed to the LURC, for the benefit of customers, and 99% will be distributed to Entergy Louisiana, net of storm trust expenses. The preferred membership interests have a stated annual cumulative cash dividend rate of 7% and a liquidation price of $100 per unit. The terms of the preferred membership interests include certain financial covenants to which Entergy Finance Company is subject. Semi-annual redemptions of the preferred membership interests, subject to certain conditions, are expected to occur over the next 15 years.

Entergy and Entergy Louisiana do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA. The bonds are secured by system restoration property, which is the right granted by law to the LURC to collect a system restoration charge from customers. The system restoration charge is adjusted at least semi-annually to ensure that it is sufficient to service the bonds. Entergy Louisiana collects the system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee. Entergy Louisiana began collecting the system restoration charge effective with the first billing cycle of June 2022 and the system restoration charge is expected to remain in place for up to 15 years. Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as a billing and collection agent for the LCDA and the LURC. In the remote possibility that the system restoration charge, as well as any funds in the excess subaccount and funds in the debt service reserve account, are insufficient to service the bonds resulting in a payment default, the storm trust I is required to liquidate Entergy Finance Company preferred membership interests in an amount equal to what would be required to cure the default. The estimated value of this indirect guarantee is immaterial.

From the proceeds from the issuance of the preferred membership interests, Entergy Finance Company distributed $1.4 billion to its parent, Entergy Holdings Company, LLC, a company wholly-owned and consolidated by Entergy. Subsequently, Entergy Holdings Company liquidated, distributing the $1.4 billion it received from Entergy Finance Company to Entergy Louisiana as holder of 6,843,780.24 units of Class A, 4,126,940.15 units of Class B, and 2,935,152.69 units of Class C preferred membership interests. Entergy Louisiana had acquired these preferred membership interests with proceeds from previous securitizations of storm restoration costs. Entergy Finance Company loaned the remaining $1.7 billion from the preferred membership interests proceeds to Entergy which used the cash to redeem $650 million of 4.00% Series senior notes due July 2022 and indirectly contributed $1 billion to Entergy Louisiana as a capital contribution.

Entergy Louisiana used the $1 billion capital contribution to fund its Hurricane Ida escrow account and subsequently withdrew the $1 billion from the escrow account. With a portion of the $1 billion withdrawn from the
escrow account and the $1.4 billion from the Entergy Holdings Company liquidation, Entergy Louisiana deposited $290 million in a restricted escrow account as a storm damage reserve for future storms, used $1.2 billion to repay its unsecured term loan due June 2023, and used $435 million to redeem a portion of its 0.62% Series mortgage bonds due November 2023.

As discussed in Note 3 to the financial statements, the securitization resulted in recognition of a reduction of income tax expense of approximately $290 million by Entergy Louisiana. Entergy’s recognition of reduced income tax expense was partially offset by other tax charges resulting in a net reduction of income tax expense of $283 million. In recognition of obligations described in an LPSC ancillary order issued as part of the securitization regulatory proceeding, Entergy Louisiana recorded a $224 million ($165 million net-of-tax) regulatory charge and a corresponding regulatory liability to reflect its obligation to provide credits to its customers.

As discussed in Note 6 and Note 17 to the financial statements, Entergy Louisiana consolidates the storm trust I as a variable interest entity and the LURC’s 1% beneficial interest is presented as noncontrolling interest in the financial statements. In second quarter 2022, Entergy Louisiana recorded a charge of $31.6 million in other income to reflect the LURC’s beneficial interest in the storm trust I.

In April 2022, Entergy Louisiana filed an application with the LPSC relating to Hurricane Ida restoration costs. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by Hurricane Ida were estimated to be approximately $2.54 billion, including approximately $1.96 billion in capital costs and approximately $586 million in non-capital costs. Including carrying costs of $57 million through December 2022, Entergy Louisiana was seeking an LPSC determination that $2.60 billion was prudently incurred and, therefore, eligible for recovery from customers. As part of this filing, Entergy Louisiana also was seeking an LPSC determination that an additional $32 million in costs associated with the restoration of Entergy Louisiana’s electric facilities damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta as well as Winter Storm Uri was prudently incurred. This amount was exclusive of the requested $3 million in carrying costs through December 2022. In total, Entergy Louisiana was requesting an LPSC determination that $2.64 billion was prudently incurred and, therefore, eligible for recovery from customers. As discussed above, in March 2022 the LPSC approved financing of a $1 billion storm escrow account from which funds were withdrawn to finance costs associated with Hurricane Ida restoration. In June 2022, Entergy Louisiana supplemented the application with a request regarding the financing and recovery of the recoverable storm restoration costs. Specifically, Entergy Louisiana requested approval to securitize its restoration costs pursuant to Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021. In October 2022 the LPSC staff recommended a finding that the requested storm restoration costs of $2.64 billion, including associated carrying costs of $59.1 million, were prudently incurred and eligible for recovery from customers. The LPSC staff further recommended approval of Entergy Louisiana’s plans to securitize these costs, net of the $1 billion in funds withdrawn from the storm escrow account described above. The parties negotiated and executed an uncontested stipulated settlement which was filed with the LPSC in December 2022. The settlement agreement contains the following key terms: $2.57 billion of restoration costs from Hurricane Ida, Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri were prudently incurred and eligible for recovery; carrying costs of $59.2 million were recoverable; and Entergy Louisiana was authorized to finance $1.657 billion utilizing the securitization process authorized by Act 55, as supplemented by Act 293. A procedural motion to consider the uncontested settlement at the December 2022 LPSC meeting did not pass and the settlement was not voted on. In January 2023 an ALJ with the LPSC conducted a settlement hearing to receive the uncontested settlement and supporting testimony into evidence and issued a report of proceedings, which allows the LPSC to consider the uncontested settlement without the procedural motion that did not pass in December. In January 2023 the LPSC approved the stipulated settlement subject to certain modifications. These modifications include the recognition of accumulated deferred income tax benefits related to damaged assets and system restoration costs as a reduction of the amount authorized to be financed utilizing the securitization process authorized by Act 55, as supplemented by Act 293, from $1.657 billion to $1.491 billion. These modifications did not affect the LPSC’s conclusion that all system restoration costs sought by Entergy Louisiana were reasonable and prudent. In February 2023 the Louisiana Bond Commission voted to authorize the LCDA to issue the bonds authorized in the LPSC’s financing order.
In March 2023 the Hurricane Ida securitization financing closed, resulting in the issuance of approximately $1.491 billion principal amount of bonds by the LCDA and a remaining regulatory asset of $180 million to be recovered through the exclusion of the accumulated deferred income taxes related to damaged assets and system restoration costs from the determination of future rates. The securitization was authorized pursuant to the Louisiana Utilities Restoration Corporation Act, Part VIII of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021. The LCDA loaned the proceeds to the LURC. Pursuant to Act 293, the LURC contributed the net bond proceeds to a State legislatively authorized and LURC-sponsored trust, Restoration Law Trust II (the storm trust II).

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

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

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

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

As discussed in Note 6 and Note 17 to the financial statements, Entergy Louisiana consolidates the storm trust II as a variable interest entity and the LURC’s 1% beneficial interest is presented as noncontrolling interest in
the financial statements. In first quarter 2023, Entergy Louisiana recorded a charge of $14.6 million in other income to reflect the LURC’s beneficial interest in the storm trust II.

Hurricane Isaac

In August 2012, Hurricane Isaac caused extensive damage to Entergy Louisiana’s service area.  In June 2014 the LPSC authorized Entergy Louisiana to utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs.  Entergy Louisiana committed to pass on to customers a minimum of $30.8 million of customer benefits through annual customer credits of approximately $6.2 million for five years. Approvals for the Act 55 financings were obtained from the LURC and the Louisiana State Bond Commission.

In August 2014 the LCDA issued $314.85 million in bonds under Louisiana Act 55.  From the $309 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $16 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $293 million directly to Entergy Louisiana.  Entergy Louisiana used the $293 million received from the LURC to acquire 2,935,152.69 Class C preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 7.5% annual distribution rate. Distributions were payable quarterly commencing on September 15, 2014, and the membership interests had a liquidation price of $100 per unit. The preferred membership interests were callable at the option of Entergy Holdings Company after ten years under the terms of the LLC agreement. The terms of the membership interests included certain financial covenants to which Entergy Holdings Company was subject, including the requirement to maintain a net worth of at least $1.75 billion. As discussed above in “Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida”, in May 2022, Entergy Holdings Company liquidated and distributed cash to Entergy Louisiana as holder of the 2,935,152.69 units of Class C preferred membership interests.

Entergy and Entergy Louisiana do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA and there is no recourse against Entergy or Entergy Louisiana in the event of a bond default.  To service the bonds, Entergy Louisiana collects a system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee.  Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as the billing and collection agent for the state.

Hurricane Gustav and Hurricane Ike

In September 2008, Hurricane Gustav and Hurricane Ike caused catastrophic damage to Entergy Louisiana’s service territory.  In December 2009, Entergy Louisiana entered into a stipulation agreement with the LPSC staff regarding its storm costs.  In March and April 2010, Entergy Louisiana and other parties to the proceeding filed with the LPSC an uncontested stipulated settlement that included Entergy Louisiana’s proposal to utilize Act 55 financing, which included a commitment to pass on to customers a minimum of $43.3 million of customer benefits through a prospective annual rate reduction of $8.7 million for five years.  In April 2010 the LPSC approved the settlement and subsequently issued financing orders and a ratemaking order intended to facilitate the implementation of the Act 55 financings.  In June 2010 the Louisiana State Bond Commission approved the Act 55 financing. The settlement agreement allowed for an adjustment to the credits if there was a change in the applicable federal or state income tax rate. As a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, and the lowering of the federal corporate income tax rate from 35% to 21%, the Louisiana Act 55 financing savings obligation regulatory liability related to Hurricane Gustav and Hurricane Ike was reduced by $2.7 million, with a corresponding increase to Other regulatory credits on the income statement. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.

In July 2010 the LCDA issued two series of bonds totaling $713.0 million under Act 55.  From the $702.7 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $290 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $412.7 million directly to Entergy Louisiana.  From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana
used $412.7 million to acquire 4,126,940.15 Class B preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 9% annual distribution rate. Distributions were payable quarterly commencing on September 15, 2010, and the membership interests had a liquidation price of $100 per unit. The preferred membership interests were callable at the option of Entergy Holdings Company after ten years under the terms of the LLC agreement.  The terms of the membership interests included certain financial covenants to which Entergy Holdings Company was subject, including the requirement to maintain a net worth of at least $1 billion. As discussed above in “Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida”, in May 2022, Entergy Holdings Company liquidated and distributed cash to Entergy Louisiana as holder of the 4,126,940.15 units of Class B preferred membership interests.

The bonds were repaid in 2022. Entergy and Entergy Louisiana did not report the bonds issued by the LCDA on their balance sheets because the bonds were the obligation of the LCDA, and there was no recourse against Entergy or Entergy Louisiana in the event of a bond default.  To service the bonds, Entergy Louisiana collected a system restoration charge on behalf of the LURC and remitted the collections to the bond indenture trustee.  Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as the billing and collection agent for the state.

Hurricane Katrina and Hurricane Rita

In August and September 2005, Hurricanes Katrina and Rita caused catastrophic damage to Entergy Louisiana’s service territory. In March 2008, Entergy Louisiana and the LURC filed at the LPSC an application requesting that the LPSC grant a financing order authorizing the financing of Entergy Louisiana storm costs, storm reserves, and issuance costs pursuant to Louisiana Act 55.  Entergy Louisiana also filed an application requesting LPSC approval for ancillary issues including the mechanism to flow charges and savings to customers via a storm cost offset rider.  In April 2008 the Louisiana Public Facilities Authority (LPFA), which is the issuer of the bonds pursuant to the Act 55 financing, approved requests for the Act 55 financing.  Also in April 2008, Entergy Louisiana and the LPSC staff filed with the LPSC an uncontested stipulated settlement that included Entergy Louisiana’s proposal under the Act 55 financing, which included a commitment to pass on to customers a minimum of $40 million of customer benefits through a prospective annual rate reduction of $8 million for five years.  The LPSC subsequently approved the settlement and issued two financing orders and one ratemaking order intended to facilitate implementation of the Act 55 financing.  In May 2008 the Louisiana State Bond Commission granted final approval of the Act 55 financing. The settlement agreement allowed for an adjustment to the credits if there was a change in the applicable federal or state income tax rate. As a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, and the lowering of the federal corporate income tax rate from 35% to 21%, the Louisiana Act 55 financing savings obligation regulatory liability related to Hurricanes Katrina and Rita was reduced by $22.3 million, with a corresponding increase to Other regulatory credits on the income statement. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.

In July 2008 the LPFA issued $687.7 million in bonds under the aforementioned Act 55.  From the $679 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $152 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $527 million directly to Entergy Louisiana.  From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $545 million, including $17.8 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 5,449,861.85 Class A preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 10% annual distribution rate.  In August 2008 the LPFA issued $278.4 million in bonds under the aforementioned Act 55.  From the $274.7 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $87 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $187.7 million directly to Entergy Louisiana.  From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $189.4 million, including $1.7 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 1,893,918.39 Class A preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 10% annual distribution rate.  Distributions were payable quarterly commencing on September 15, 2008 and had a
liquidation price of $100 per unit.  The preferred membership interests were callable at the option of Entergy Holdings Company after ten years under the terms of the LLC agreement.  The terms of the membership interests included certain financial covenants to which Entergy Holdings Company was subject, including the requirement to maintain a net worth of at least $1 billion.  In February 2012, Entergy Louisiana sold 500,000 of its Class A preferred membership units in Entergy Holdings Company to a third party. Those preferred membership units were subsequently repurchased by Entergy Holdings Company in March 2019. As discussed above in “Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida”, in May 2022, Entergy Holdings Company liquidated and distributed cash to Entergy Louisiana as holder of the remaining 6,843,780.24 units of Class A preferred membership interests.

The bonds were repaid in 2018. Entergy and Entergy Louisiana did not report the bonds issued by the LPFA on their balance sheets because the bonds were the obligation of the LPFA, and there was no recourse against Entergy or Entergy Louisiana in the event of a bond default.  To service the bonds, Entergy Louisiana collected a system restoration charge on behalf of the LURC and remitted the collections to the bond indenture trustee.  Entergy and Entergy Louisiana did not report the collections as revenue because Entergy Louisiana was merely acting as the billing and collection agent for the state.

Entergy Mississippi

Prior to June 2024, Entergy Mississippi had approval from the MPSC to collect a storm damage provision of $1.75 million per month. If Entergy Mississippi’s accumulated storm damage provision balance exceeded $15 million, the collection of the storm damage provision ceased until such time that the accumulated storm damage provision became less than $10 million. Entergy Mississippi’s storm damage provision balance had been less than $10 million since May 2019, and Entergy Mississippi had been billing the monthly storm damage provision since July 2019.

In December 2023, Entergy Mississippi filed a Notice of Storm Escrow Disbursement and Request for Interim Relief notifying the MPSC that Entergy Mississippi had requested disbursement of approximately $34.5 million of storm escrow funds from its restricted storm escrow account. The filing also requested authorization from the MPSC, on a temporary basis, that the $34.5 million of storm escrow funds be credited to Entergy Mississippi’s storm damage provision, pending the MPSC’s review of Entergy Mississippi’s storm-related costs, and that Entergy Mississippi continue to bill its monthly storm damage provision without suspension in the event the storm damage provision balance exceeded $15 million, in anticipation of a subsequent filing by Entergy Mississippi in this proceeding. The storm damage provision exceeded $15 million upon receipt of the storm escrow funds. Because the MPSC had not entered an order on Entergy Mississippi’s filing on the requested relief to continue billing this provision, Entergy Mississippi suspended billing the monthly storm damage provision effective with February 2024 bills.

In March 2024, Entergy Mississippi made a combined dual filing which included a notice of intent to make routine change in rates and schedules and a motion for determination relating to the above-described notice of storm escrow disbursement. The notice of intent proposed a new storm damage mitigation and restoration rider to supersede both the then-current storm damage rate schedule and the vegetation management rider schedule, in which the collection of both expenses would be combined. The proposal requested that the MPSC authorize Entergy Mississippi to collect approximately $5.2 million per month for vegetation management and a storm damage provision. Furthermore, if Entergy Mississippi’s accumulated vegetation management and storm damage provision balance were to exceed $70 million, collection under the storm damage mitigation and restoration rider would cease until such time that the accumulated vegetation management and storm damage provision would become less than $60 million.

The Mississippi Public Utilities Staff reviewed the storm-related costs submitted by Entergy Mississippi and found them prudent. In June 2024 the MPSC considered and unanimously granted the relief sought by Entergy Mississippi, including authorization to credit any remaining funds in the storm escrow account to Entergy
Mississippi’s storm damage provision and to close the storm escrow account and approving the new storm damage mitigation and restoration rider. Entergy Mississippi’s storm escrow account was liquidated in July 2024, and the new combined storm damage mitigation and restoration rider became effective with the July 2024 billing cycle. Additionally, Entergy Mississippi made a compliance filing to cease billing under the existing vegetation management rider schedule as of the same billing cycle.

Entergy New Orleans

Hurricane Ida

In August 2021, Hurricane Ida caused significant damage to Entergy New Orleans’s service area, including Entergy’s electrical grid. The storm resulted in widespread power outages, including the loss of 100% of Entergy New Orleans’s load and damage to distribution and transmission infrastructure, including the loss of connectivity to the eastern interconnection. In September 2021, Entergy New Orleans withdrew $39 million from its funded storm reserves. In June 2022, Entergy New Orleans filed an application with the City Council requesting approval and certification that storm restoration costs associated with Hurricane Ida of approximately $170 million, which included $11 million in estimated costs, were reasonable, necessary, and prudently incurred to enable Entergy New Orleans to restore electric service to its customers and to repair Entergy New Orleans’s electric utility infrastructure. In addition, estimated carrying costs through December 2022 related to Hurricane Ida restoration costs were $9 million. Also, Entergy New Orleans requested approval that the $39 million withdrawal from its funded storm reserve in September 2021 and $7 million in excess storm reserve escrow withdrawals related to Hurricane Zeta in October 2020 and prior miscellaneous storms were properly applied to Hurricane Ida storm restoration costs, the application of which reduced the amount to be recovered from Entergy New Orleans customers by $46 million.

Additionally, in February 2022, Entergy New Orleans and the LURC filed with the City Council a securitization application requesting that the City Council review Entergy New Orleans’s storm reserve and increase the storm reserve funding level to $150 million, to be funded through securitization. In August 2022 the City Council’s advisors recommended that the City Council authorize a single securitization bond issuance to fund Entergy New Orleans’s storm recovery reserves to an amount sufficient to: (1) allow recovery of all of Entergy New Orleans’s unrecovered storm recovery costs following Hurricane Ida, subject to City Council review and certification; (2) provide initial funding of storm recovery reserves for future storms to a level of $75 million; and (3) fund the storm recovery bonds’ upfront financing costs. In September 2022, Entergy New Orleans and the City Council’s advisors entered into an agreement in principle, which was approved by the City Council along with a financing order in October 2022, which authorized Entergy New Orleans and the LURC to proceed with a single securitization bond issuance of approximately $206 million (subject to further adjustment and review pursuant to the Final Issuance Advice Letter process set forth in the financing order), with $125 million of that total to be used for interim recovery, subject to City Council review and certification, to be allocated to unrecovered Hurricane Ida storm recovery costs; $75 million of that total to provide for a storm recovery reserve for future storms; and the remainder to fund the recovery of the storm recovery bonds’ upfront financing costs.

In December 2022, Entergy New Orleans and the LURC filed with the City Council the Final Issuance Advice Letter for a securitization bond issuance in the amount of $209.3 million, the final structuring, terms, and pricing of which were approved by the City Council in accordance with the financing order. Also in December 2022 the LCDA issued $209.3 million in bonds pursuant to the Louisiana Electric Utility Storm Recovery Securitization Act, Part V-B of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana Regular Session of 2021. The LCDA loaned $201.8 million of bond proceeds, net of certain debt service and issuance costs, to the LURC. The LURC used the proceeds to purchase from Entergy New Orleans the storm recovery property, which is the right to collect storm recovery charges sufficient to pay the storm recovery bonds and associated financing costs, and Entergy New Orleans deposited $200 million in a restricted storm reserve escrow account as a storm damage reserve for Entergy New Orleans and received directly $1.8 million in estimated upfront financing costs. Subsequently, Entergy New Orleans withdrew $125 million from the newly securitized
storm reserve to cover Hurricane Ida storm recovery costs, subject to a final determination from the City Council regarding the prudency of the storm recovery costs.

Entergy and Entergy New Orleans do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA, and there is no recourse against Entergy or Entergy New Orleans in the event of a bond default. To service the bonds, Entergy New Orleans collects a storm recovery charge on behalf of the LURC and remits the collections to the bond indenture trustee. Entergy and Entergy New Orleans do not report the collections as revenue because Entergy New Orleans is merely acting as the billing and collection agent for the LURC.

In August 2023 the City Council advisors issued a report recommending that the City Council find that Entergy New Orleans prudently incurred approximately $164.1 million in storm restoration costs and $7.5 million in carrying charges and that such costs have already been properly recovered by Entergy New Orleans through withdrawals from the storm reserve escrow account. The City Council advisors also recommended that the City Council find that approximately $1.2 million in storm restoration costs had already been recovered through Entergy New Orleans’s base rates and that approximately $0.9 million in unused credits be applied against future storm costs. In August 2023 the City Council hearing officer certified the evidentiary record. In December 2023 the City Council approved a resolution adopting the advisors’ report and recommendations.

Entergy Texas

Hurricane Laura, Hurricane Delta, and Winter Storm Uri

In August 2020 and October 2020, Hurricane Laura and Hurricane Delta caused extensive damage to Entergy Texas’s service area. In February 2021, Winter Storm Uri also caused damage to Entergy Texas’s service area. The storms resulted in widespread power outages, significant damage primarily to distribution and transmission infrastructure, and the loss of sales during the power outages. In April 2021, Entergy Texas filed an application with the PUCT requesting a determination that approximately $250 million of system restoration costs associated with Hurricane Laura, Hurricane Delta, and Winter Storm Uri, including approximately $200 million in capital costs and approximately $50 million in non-capital costs, were reasonable and necessary to enable Entergy Texas to restore electric service to its customers and Entergy Texas’s electric utility infrastructure. The filing also included the projected balance of approximately $13 million of a regulatory asset containing previously approved system restoration costs related to Hurricane Harvey. In September 2021 the parties filed an unopposed settlement agreement, pursuant to which Entergy Texas removed from the amount to be securitized approximately $4.3 million that will instead be charged to its storm reserve, $5 million related to no particular issue, of which Entergy Texas would be permitted to seek recovery in a future proceeding, and approximately $300 thousand related to attestation costs. In December 2021 the PUCT issued an order approving the unopposed settlement and determining system restoration costs of $243 million related to Hurricane Laura, Hurricane Delta, and Winter Storm Uri and the $13 million projected remaining balance of the Hurricane Harvey system restoration costs were eligible for securitization. The order also determines that Entergy Texas can recover carrying costs on the system restoration costs related to Hurricane Laura, Hurricane Delta, and Winter Storm Uri.

In July 2021, Entergy Texas filed with the PUCT an application for a financing order to approve the securitization of the system restoration costs that are the subject of the April 2021 application. In November 2021 the parties filed an unopposed settlement agreement supporting the issuance of a financing order consistent with Entergy Texas’s application and with minor adjustments to certain upfront and ongoing costs to be incurred to facilitate the issuance and serving of system restoration bonds. In January 2022 the PUCT issued a financing order consistent with the unopposed settlement. As a result of the financing order, Entergy Texas reclassified $153 million from utility plant to other regulatory assets.

In April 2022, Entergy Texas Restoration Funding II, LLC, a company wholly-owned and consolidated by Entergy Texas, issued $290.85 million of senior secured system restoration bonds (securitization bonds). With the
proceeds, Entergy Texas Restoration Funding II purchased from Entergy Texas the transition property, which is the right to recover from customers through a system restoration charge amounts sufficient to service the securitization bonds. Entergy Texas began cost recovery through the system restoration charge effective with the first billing cycle of May 2022 and the system restoration charge is expected to remain in place up to 15 years. See Note 5 to the financial statements for a discussion of the April 2022 issuance of the securitization bonds.
Entergy Mississippi [Member]  
Public Utilities Disclosure [Text Block] RATE AND REGULATORY MATTERS (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Regulatory Assets and Regulatory 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. In addition to the regulatory assets and liabilities that are specifically disclosed on the face of the balance sheets, the tables below provide detail of “Other regulatory assets” and “Other regulatory liabilities” that are included on Entergy’s and the Registrant Subsidiaries’ balance sheets as of December 31, 2024 and 2023 (as noted in footnotes to the tables, a portion of these regulatory assets and regulatory liabilities is classified as held for sale in the balance sheets as of December 31, 2024):

Other Regulatory Assets

Entergy
20242023
 (In Millions)
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
$1,387.6 $1,655.5 
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or shutdown of non-nuclear power plants and solar facilities (Note 9) (a)
1,358.7 1,285.0 
Removal costs (Note 9)
1,107.6 1,010.7 
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators and Note 5 - Securitization Bonds)
547.3 536.9 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
227.1 250.9 
Retail rate deferrals - recovered through formula rates or rate riders as rates are redetermined by retail regulators
195.1 248.6 
Retired electric and gas meters - recovered through retail rates as determined by retail regulators (Note 2 - Retail Rate Proceedings)
135.7 153.8 
Deferred COVID-19 costs - recovered through retail rates as determined by retail regulators (Note 2 - Retail Rate Proceedings)
104.0 118.0 
Unamortized loss on reacquired debt - recovered over term of debt
57.9 63.1 
Advanced metering system surcharge for residential customers - recovered through December 2029
39.7 20.2 
Formula rate plan historical year rate adjustment (Note 2 - Retail Rate Proceedings) (b)
15.5 — 
Pension & postretirement benefits expense deferral - recovered through retail rates (Note 2 - Retail Rate Proceedings and Note 11 - Entergy Texas Reserve)
15.0 32.7 
Rate case depreciation relate back deferral - recovered over a six-month period beginning January 2024 (Note 2 - Retail Rate Proceedings)
— 27.6 
Opportunity sales - (Note 2 - Entergy Arkansas Opportunity Sales Proceeding) (b)
— 131.8 
Other99.7 134.6 
Entergy Total (c)
$5,290.9 $5,669.4 
Entergy Arkansas
 20242023
 (In Millions)
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or shutdown of non-nuclear power plants and solar facilities (Note 9) (a)
$693.0 $639.1 
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
433.3 536.6 
Removal costs (Note 9)
337.9 319.7 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
75.8 84.1 
Deferred COVID-19 costs - recovered over a 10-year period through December 2033
35.1 39.0 
Retired electric meters - recovered over a 15-year period through March 2034
32.8 36.3 
Storm damage costs - recovered through retail rates
29.8 33.1 
Unamortized loss on reacquired debt - recovered over term of debt
18.6 19.9 
Formula rate plan historical year rate adjustment (Note 2 - Retail Rate Proceedings) (b)
15.5 — 
Retail rate deferrals - recovered through rate riders as rates are redetermined annually (b)
13.6 24.9 
ANO Fukushima and Flood Barrier costs - recovered through retail rates through February 2026 (b)
2.1 3.8 
Opportunity sales - (Note 2 - Entergy Arkansas Opportunity Sales Proceeding) (b)
— 131.8 
Other12.6 17.1 
Entergy Arkansas Total$1,700.1 $1,885.4 

Entergy Louisiana
 20242023
 (In Millions)
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or shutdown of non-nuclear power plants (Note 9) (a)
$421.5 $408.7 
Pension & postretirement costs (Note 11 - Qualified Pension Plans and Non-Qualified Pension Plans) (a)
367.7 412.0 
Removal costs (Note 9)
323.2 262.3 
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)
226.6 202.6 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
111.4 123.0 
Retired electric and gas meters - recovered over a 22-year period through July 2041
78.5 83.2 
Deferred COVID-19 costs - recovery period to be determined (Note 2 - Retail Rate Proceedings) (a)
47.8 47.8 
Unamortized loss on reacquired debt - recovered over term of debt
21.7 23.4 
Other48.5 85.9 
Entergy Louisiana Total (c)
$1,646.9 $1,648.9 
Entergy Mississippi
 20242023
(In Millions)
Removal costs (Note 9)
$184.8 $188.0 
Retail rate deferrals - recovered through formula rates or rate riders as rates are redetermined annually
162.5 192.8 
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
112.1 127.6 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
29.1 32.0 
Asset retirement obligation - recovery dependent upon timing of shutdown of non-nuclear power plants and solar facility (Note 9) (a)
9.4 6.8 
Unamortized loss on reacquired debt - recovered over term of debt
9.1 10.0 
Attorney General litigation costs - recovered over a six-year period through March 2026 (b)
6.0 10.9 
Other12.8 11.0 
Entergy Mississippi Total$525.8 $579.1 

Entergy New Orleans
 20242023
 (In Millions)
Removal costs (Note 9)
$62.5 $61.1 
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
22.9 41.4 
Retired electric and gas meters - recovered over a 12-year period through July 2031 (b)
13.5 15.5 
Gas cross-boring costs - recovered through formula rates as rates are redetermined by retail regulators
11.9 10.9 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
10.8 11.8 
Deferred COVID-19 costs - recovered over a five-year period through August 2028 (b)
10.2 13.0 
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators and Note 5 - Entergy New Orleans Securitization Bonds - Hurricane Isaac)
4.0 3.9 
Unamortized loss on reacquired debt - recovered over term of debt
0.5 0.8 
Other20.7 24.0 
Entergy New Orleans Total (c)
$157.0 $182.4 
Entergy Texas
 20242023
 (In Millions)
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators and Note 5 - Entergy Texas Securitization Bonds - Hurricane Laura, Hurricane Delta, and Winter Storm Uri)
$286.5 $297.3 
Removal costs (Note 9)
102.3 77.5 
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
62.9 85.6 
Advanced metering system surcharge for residential customers - recovered through December 2029
39.7 20.2 
Pension & postretirement benefits expense deferral - recovered through retail rates (Note 2 - Retail Rate Proceedings and Note 11 - Entergy Texas Reserve)
15.0 32.7 
Retired electric meters - recovered through retail rates (Note 2 - Retail Rate Proceedings)
10.9 18.8 
Neches and Sabine costs - recovered over a 10-year period through September 2028
9.2 11.6 
Unamortized loss on reacquired debt - recovered over term of debt
7.6 8.3 
Rate case depreciation relate back deferral - recovered over a six-month period beginning January 2024 (Note 2 - Retail Rate Proceedings)
— 27.6 
Other15.6 17.0 
Entergy Texas Total$549.7 $596.6 

System Energy
 20242023
 (In Millions)
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear unit (Note 9) (b)
$224.8 $222.0 
Pension & postretirement costs (Note 11 - Qualified Pension Plans and Other Postretirement Benefits) (a)
104.4 121.6 
Removal costs - recovered through depreciation rates (Note 9)
96.9 102.1 
Unamortized loss on reacquired debt - recovered over term of debt
0.4 0.7 
System Energy Total$426.5 $446.4 

(a)Does not earn a return on investment, but is offset by related liabilities.
(b)Does not earn a return on investment.
(c)Includes $35.4 million at Entergy, $8.9 million at Entergy Louisiana, and $23.7 million at Entergy New Orleans as of December 31, 2024 of regulatory assets related to the respective natural gas distribution businesses classified as held for sale and included within “Non-current assets held for sale” on the respective consolidated balance sheets. See Note 14 to the financial statements for further discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses and the classification as held for sale.
Other Regulatory Liabilities

Entergy
20242023
(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)
$2,262.5 $1,826.2 
Securitization financing savings obligation (Note 3)
371.3 405.2 
Retail rate rider over-recovery - refunded through formula rate or rate riders as rates are redetermined by retail regulators
164.9 142.7 
Credits from resolution of the 2016-2018 IRS audit (Note 3)
163.3 98.0 
Customer rate credits from global stipulated settlement with the LPSC - returned to customers September 2024 through August 2026 (Note 2)
121.7 — 
Refund from System Energy settlement with the LPSC - to be returned to customers January 2025 through August 2027 (Note 2)
75.8 — 
Deferred tax equity partnership earnings (Note 1)
69.9 57.9 
Vidalia purchased power agreement (Note 8)
67.4 82.5 
Refund from System Energy settlement with the City Council - returned to customers over a 25-year period beginning September 2024 (Note 2)
64.7 — 
Shorter-term financing interest earnings (Note 2 - Retail Rate Proceedings) (a)
48.9 36.8 
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and the FERC
44.4 44.4 
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)
40.9 44.3 
Refund from System Energy settlement with the City Council - return to customers to be determined (Note 2)
32.0 — 
Refund from System Energy settlement with the APSC - refunded through a rate rider as rates are re-determined periodically (Note 2)
8.2 93.0 
Complaints against System Energy - potential future refunds (Note 2)
— 177.9 
Other75.2 108.0 
Entergy Total (b)
$3,611.1 $3,116.9 

Entergy Arkansas
 20242023
 (In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)
$761.3 $621.6 
Deferred tax equity partnership earnings (Note 1)
32.4 27.4 
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually
27.9 10.6 
Refund from System Energy settlement with the APSC - refunded through a rate rider as rates are re-determined periodically (Note 2)
8.2 93.0 
Internal restructuring guaranteed customer credits - returned to customers over a six-year period through December 2024
— 6.6 
Other1.4 — 
Entergy Arkansas Total$831.2 $759.2 
Entergy Louisiana
 20242023
 (In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)
$798.4 $644.0 
Securitization financing savings obligation (Note 3)
371.3 405.2 
Customer rate credits from global stipulated settlement with the LPSC - returned to customers September 2024 through August 2026 (Note 2)
121.7 — 
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually
96.3 86.4 
Refund from System Energy settlement with the LPSC - to be returned to customers January 2025 through August 2027 (Note 2)
75.8 — 
Vidalia purchased power agreement (Note 8)
67.4 82.5 
Shorter-term financing interest earnings (Note 2 - Retail Rate Proceedings) (a)
48.9 36.8 
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)
40.9 44.3 
Hurricane Ida insurance proceeds - returned to customers August 2024 to July 2025
26.0 32.3 
Credits from resolution of the 2016-2018 IRS audit - returned to customers September 2024 through August 2025 (Note 3)
25.3 38.0 
Sale-leaseback and depreciation refunds - returned to customers September 2023 through August 2024
— 14.1 
Other21.7 24.1 
Entergy Louisiana Total (b)
$1,693.7 $1,407.7 

Entergy Mississippi
20242023
 (In Millions)
Deferred tax equity partnership earnings (Note 1)
$37.5 $30.5 
Retail rate rider over-recovery - refunded through formula rate or rate riders as rates are redetermined annually
12.2 2.4 
Other postretirement benefits (Note 11 - Entergy Mississippi Other Postretirement Benefits)
7.4 — 
Other2.4 0.8 
Entergy Mississippi Total$59.5 $33.7 
Entergy New Orleans
20242023
 (In Millions)
Credits from resolution of the 2016-2018 IRS audit - to be returned to customers over a 25-year period beginning January 2025 (Note 3)
$138.0 $60.0 
Refund from System Energy settlement with the City Council - returned to customers over a 25-year period beginning September 2024 (Note 2)
64.7 — 
Refund from System Energy settlement with the City Council - return to customers to be determined (Note 2)
32.0 — 
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually
16.3 20.1 
Sale-leaseback and depreciation refunds - returned to customers over a 10-year period beginning September 2023 (Note 2)
5.2 9.8 
Other4.5 0.5 
Entergy New Orleans Total (b)
$260.7 $90.4 

Entergy Texas
 20242023
 (In Millions)
Retail rate rider over-recovery - return to customers to be determined
$12.2 $23.8 
Retail refunds - return to customers to be determined
6.2 6.2 
Rate case settlement relate back - amortized over a six-month period beginning January 2024 (Note 2 - Retail Rate Proceedings)
— 10.3 
Other 0.3 2.7 
Entergy Texas Total$18.7 $43.0 

System Energy
 20242023
 (In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)
$702.8 $560.6 
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and the FERC
44.4 44.4 
Complaints against System Energy - potential future refunds (Note 2)
— 177.9 
System Energy Total$747.2 $782.9 

(a)Offset by related asset.
(b)Includes $1.6 million at Entergy, $1.2 million at Entergy Louisiana, and $0.4 million at Entergy New Orleans as of December 31, 2024 of regulatory liabilities related to the respective natural gas distribution businesses classified as held for sale and included within other non-current liabilities on the respective consolidated balance sheets. See Note 14 to the financial statements for further discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses and the classification as held for sale.
Regulatory activity regarding the Tax Cuts and Jobs Act

See the “Other Tax Matters - Tax Cuts and Jobs Act” section in Note 3 to the financial statements for discussion of the effects of the December 2017 enactment of the Tax Cuts and Jobs Act (Tax Act), including its effects on Entergy’s and the Registrant Subsidiaries’ regulatory asset/liability for income taxes.

Entergy Louisiana

In an electric formula rate plan settlement approved by the LPSC in April 2018, the parties agreed that Entergy Louisiana would return to customers one-half of its eligible unprotected excess deferred income taxes from May 2018 through December 2018 and return to customers the other half from January 2019 through August 2022. In addition, the settlement provided that in order to flow back to customers certain other tax benefits created by the Tax Act, Entergy Louisiana established a regulatory liability effective January 1, 2018 in the amount of $9.1 million per month to reflect these tax benefits already included in retail rates until new base rates under the formula rate plan were established in September 2018, and this regulatory liability was returned to customers over the September 2018 through August 2019 formula rate plan rate-effective period. The LPSC staff and intervenors in the settlement reserved the right to obtain data from Entergy Louisiana to confirm the determination of excess accumulated deferred income taxes resulting from the Tax Act and the analysis thereof as part of the formula rate plan review proceeding for the 2017 test year filing. As discussed below in “Retail Rate Proceedings - Filings with the LPSC (Entergy Louisiana) - Retail Rates - Electric - Formula Rate Plan Global Settlement”, a global settlement resolving the outstanding issues related to the 2017 formula rate plan filing was reached in October 2023 and approved by the LPSC in November 2023.

System Energy

In a filing made with the FERC in March 2018, System Energy proposed revisions to the Unit Power Sales Agreement to reflect the effects of the Tax Act. In the filing System Energy proposed to return identified quantities of unprotected excess accumulated deferred income taxes to its customers by the end of 2018. In May 2018 the FERC accepted System Energy’s proposed tax revisions with an effective date of June 1, 2018, subject to refund and the outcome of settlement and hearing procedures. Settlement discussions were terminated in April 2019, and a hearing was held in March 2020. In December 2022 the FERC issued an order requiring System Energy to compute the amount of excess accumulated deferred income taxes associated with a previously uncertain decommissioning tax position with consideration for the resolution of the tax position by the IRS. In February 2023, System Energy submitted its compliance filing. This matter was ultimately settled as a result of System Energy’s settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” below for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.
Fuel and purchased power cost recovery

The Utility operating companies are allowed to recover fuel and purchased power costs through fuel mechanisms included in electric and gas rates that are recorded as fuel cost recovery revenues.  The difference between revenues collected and the current fuel and purchased power costs is generally recorded as “Deferred fuel costs” on the Utility operating companies’ financial statements.  The table below shows the amount of deferred fuel costs as of December 31, 2024 and 2023 that each Utility operating company expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.

 20242023
 (In Millions)
Entergy Arkansas
($45.2)($88.3)
Entergy Louisiana (a) (b)$163.4 $192.9 
Entergy Mississippi($126.3)($130.6)
Entergy New Orleans (a) (b)$8.0 $10.2 
Entergy Texas($59.3)$139.0 

(a)Includes $168.1 million in both years for Entergy Louisiana and $4.1 million in both years for Entergy New Orleans of fuel, purchased power, and capacity costs, which do not currently earn a return on investment and whose recovery periods are indeterminate but are expected to be recovered over a period greater than twelve months.
(b)Includes $0.7 million at Entergy Louisiana and $4.9 million at Entergy New Orleans as of December 31, 2024 of deferred fuel assets related to the respective natural gas distribution businesses classified as held for sale and included within “Current assets held for sale” on the respective consolidated balance sheets. See Note 14 to the financial statements for further discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses and the classification as held for sale.

Entergy Arkansas

Energy Cost Recovery Rider

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

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

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

In March 2018, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01547 per kWh to $0.01882 per kWh. The Arkansas Attorney General filed a response to Entergy Arkansas’s annual redetermination filing requesting that the APSC suspend the proposed tariff to investigate the amount of the redetermination or, alternatively, to allow recovery subject to refund. Among the reasons the Attorney General cited for suspension were questions pertaining to how Entergy Arkansas forecasted sales and potential implications of the Tax Cuts and Jobs Act. Entergy Arkansas replied to the Attorney General’s filing and stated that, to the extent there are questions pertaining to its load forecasting or the operation of the energy cost recovery rider, those issues exceed the scope of the instant rate redetermination. Entergy Arkansas also stated that potential effects of the Tax Cuts and Jobs Act are appropriately considered in the APSC’s separate proceeding regarding potential implications of the tax law. The APSC general staff filed a reply to the Attorney General’s filing and agreed that Entergy Arkansas’s filing complied with the terms of the energy cost recovery rider. The redetermined rate became effective with the first billing cycle of April 2018. Subsequently in April 2018 the APSC issued an order declining to suspend Entergy Arkansas’s energy cost recovery rider rate and declining to require further investigation at that time of the issues suggested by the Attorney General in the proceeding. Following a period of discovery, the Attorney General filed a supplemental response in October 2018 raising new issues with Entergy Arkansas’s March 2018 rate redetermination and asserting that $45.7 million of the increase should be collected subject to refund pending further investigation. Entergy Arkansas filed to dismiss the Attorney General’s supplemental response, the APSC general staff filed a motion to strike the Attorney General’s filing, and the Attorney General filed a supplemental response disputing Entergy Arkansas and the APSC staff’s filing. Applicable APSC rules and processes authorize its general staff to initiate periodic audits of Entergy Arkansas’s energy cost recovery rider. In late-2018 the APSC general staff notified Entergy Arkansas it initiated an audit of the 2017 fuel costs. The time in which the audit will be complete is uncertain at this time.

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

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

In March 2024, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease in the rate from $0.01883 per kWh to $0.00882 per kWh. Due to a change in law in the State of Arkansas, the annual redetermination included $9 million, recorded as a credit to fuel expense in first quarter 2024, for recovery attributed to net metering costs in 2023. The primary reason for the rate decrease is a large over-recovered balance as a result of lower natural gas prices in 2023. To mitigate the effect of projected increases in natural gas prices in 2024, Entergy Arkansas adjusted the over-recovered balance included in the March 2024 annual redetermination filing by $43.7 million. This adjustment is expected to reduce the rate change that will be reflected in the 2025 energy cost rate redetermination. The redetermined rate of $0.00882 per kWh became effective with the first billing cycle in April 2024 through the normal operation of the tariff.

Entergy Louisiana

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

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

In March 2020 the LPSC staff provided notice of an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2016 through 2019. The LPSC staff issued its audit report in September 2021, and although certain internal record keeping recommendations were made, the LPSC staff did not recommend any disallowances. The next step is for the LPSC to review the report, but there is not a deadline for the review.

In January 2023 the LPSC staff provided notice of an audit of Entergy Louisiana’s purchased gas adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s purchased gas adjustment clause for the period from 2021 through 2022. Discovery is ongoing, and no audit report has been filed.
In January 2023 the LPSC staff provided notice of an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2020 through 2022. Discovery is ongoing, and no audit report has been filed.

Entergy Mississippi

Entergy Mississippi’s rate schedules include an energy cost recovery rider and a power management rider, both of which are adjusted annually to reflect accumulated over- or under-recoveries. Entergy Mississippi recovers fuel and purchased energy costs through its energy cost recovery rider and recovers costs associated with natural gas hedging and capacity payments through its power management rider. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.

In November 2021, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an under-recovery of approximately $80.6 million as of September 30, 2021. In December 2021, at the request of the MPSC, Entergy Mississippi submitted a proposal to mitigate the impact of rising fuel costs on customer bills during 2022. Entergy Mississippi proposed that the deferred fuel balance as of December 31, 2021, which was $121.9 million, be amortized over three years and that the MPSC authorize Entergy Mississippi to apply its weighted-average cost of capital as the carrying cost for the unamortized fuel balance. In January 2022 the MPSC approved the amortization of $100 million of the deferred fuel balance over two years and authorized Entergy Mississippi to apply its weighted-average cost of capital as the carrying cost for the unamortized fuel balance. The MPSC approved the proposed energy cost factor effective for February 2022 bills.

See “Complaints Against System Energy - System Energy Settlement with the MPSC” below for discussion of the settlement agreement filed with the FERC in June 2022. The settlement, which was approved by the FERC in November 2022, provided for a refund of $235 million from System Energy to Entergy Mississippi. In July 2022 the MPSC directed the disbursement of settlement proceeds, ordering Entergy Mississippi to provide a one-time $80 bill credit to each of its approximately 460,000 retail customers to be effective during the September 2022 billing cycle and to apply the remaining proceeds to Entergy Mississippi’s under-recovered deferred fuel balance. In accordance with the MPSC’s directive, Entergy Mississippi provided approximately $36.7 million in customer bill credits as a result of the settlement. In November 2022, Entergy Mississippi applied the remaining settlement proceeds in the amount of approximately $198.3 million to Entergy Mississippi’s under-recovered deferred fuel balance.

Entergy Mississippi had a deferred fuel balance of approximately $291.7 million under the energy cost recovery rider as of July 31, 2022, along with an over-recovery balance of $51.1 million under the power management rider. Without further action, Entergy Mississippi anticipated a year-end deferred fuel balance of approximately $200 million after application of a portion of the System Energy settlement proceeds, as discussed above. In September 2022, Entergy Mississippi filed for interim adjustments under both the energy cost recovery rider and the power management rider. Entergy Mississippi proposed five monthly incremental adjustments to the net energy cost factor designed to collect the under-recovered fuel balance as of July 31, 2022 and to reflect the recovery of a higher natural gas price. Entergy Mississippi also proposed five monthly incremental adjustments to the power management adjustment factor designed to flow through to customers the over-recovered power management rider balance as of July 31, 2022. In October 2022 the MPSC approved modified interim adjustments to Entergy Mississippi’s energy cost recovery rider and power management rider. The MPSC approved dividing the energy cost recovery rider interim adjustment into two components that would allow Entergy Mississippi to (1) recover a natural gas fuel rate that is better aligned with current prices; and (2) recover the estimated under-recovered deferred fuel balance as of September 30, 2022 over a period of 20 months. The MPSC approved six monthly incremental adjustments to the net energy cost factor designed to reflect the recovery of a higher natural gas price. The MPSC also approved six monthly incremental adjustments to the power management adjustment factor designed to flow through to customers the over-recovered power management rider balance. In accordance
with the order of the MPSC, Entergy Mississippi did not file an annual redetermination of the energy cost recovery rider or the power management rider in November 2022.

In June 2023 the MPSC approved the joint stipulation agreement between Entergy Mississippi and the Mississippi Public Utilities Staff for Entergy Mississippi’s 2023 formula rate plan filing. The stipulation directed Entergy Mississippi to make a compliance filing to revise its power management cost adjustment factor, to revise its grid modernization cost adjustment factor, and to include a revision to reduce the net energy cost factor to a level necessary to reflect an average natural gas price of $4.50 per MMBtu. The MPSC approved the compliance filing in June 2023, effective for July 2023 bills. See “Retail Rate Proceedings - Filings with the MPSC (Entergy Mississippi) - Retail Rates - 2023 Formula Rate Plan Filing” below for further discussion of the 2023 formula rate plan filing and the joint stipulation agreement.

In November 2023 Entergy Mississippi filed its annual redeterminations of the energy cost factor and the power management cost adjustment factor. The calculation of the annual factor for the energy cost recovery rider included a projected over-recovery balance of approximately $142 million at the end of January 2024. The calculation of the annual factor for the power management rider included a projected under-recovery of $47 million at the end of January 2024. In January 2024 the MPSC approved the proposed energy cost factor and the proposed power management cost factor effective for February 2024 bills.

In June 2024 the MPSC approved the joint stipulation agreement between Entergy Mississippi and the Mississippi Public Utilities Staff for Entergy Mississippi’s 2024 formula rate plan filing. The 2024 formula rate plan filing included the conclusion of the modified interim adjustments to Entergy Mississippi’s energy cost recovery rider and power management rider, which were approved in October 2022 and allowed Entergy Mississippi to recover certain under-collected fuel balances, effective for July 2024 bills. The stipulation provided for Entergy Mississippi to reduce its net energy cost factor. See “Retail Rate Proceedings - Filings with the MPSC (Entergy Mississippi) - Retail Rates - 2024 Formula Rate Plan Filing” below for further discussion of the 2024 formula rate plan filing and the joint stipulation agreement.

In November 2024, Entergy Mississippi filed its annual redeterminations of the energy cost factor and the power management cost adjustment factor. The calculation of the annual factor for the energy cost recovery rider included a projected over-recovery balance of approximately $144.6 million as of September 2024. The calculation of the annual factor for the power management rider included a projected under-recovery of $60.1 million as of September 2024. In January 2025 the MPSC approved a revised energy cost factor, effective for February 2025 bills, that did not reflect the fuel savings associated with Entergy Mississippi’s incremental increase in its share of capacity and energy in connection with Entergy Mississippi’s assumption of Entergy Louisiana’s entitlements to Grand Gulf capacity and energy, which was subject to the MPSC’s review at such time. In February 2025 the MPSC approved Entergy Mississippi’s notice of intent for Entergy Mississippi’s assumption of Entergy Louisiana’s entitlements to Grand Gulf capacity and energy, with associated fuel savings to be reflected in Entergy Mississippi’s energy cost recovery rider, effective for March 2025 bills. Additionally, in February 2025 the MPSC approved the proposed power management cost adjustment factor, effective for March 2025 bills.

Entergy New Orleans

Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.

Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.
Entergy Texas

Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, not recovered in base rates.  Historically, semi-annual revisions of the fixed fuel factor have been made in March and September based on the market price of natural gas and changes in fuel mix.  The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. In 2023 the Texas legislature modified the Texas Utilities Code to provide that material over- and under-recovered fuel balances are to be refunded or surcharged through interim fuel adjustments and that fuel reconciliations must be filed at least once every two years. Entergy Texas expects the PUCT to undertake a rulemaking to effectuate the new legislation in 2025.

In May 2022, Entergy Texas filed an application with the PUCT to implement an interim fuel surcharge to collect the cumulative under-recovery of approximately $51.7 million, including interest, of fuel and purchased power costs incurred from May 1, 2020 through December 31, 2021. The under-recovery balance was primarily attributable to the impacts of Winter Storm Uri, including historically high natural gas prices, partially offset by settlements received by Entergy Texas from MISO related to Hurricane Laura. Entergy Texas proposed that the interim fuel surcharge be assessed over a period of six months beginning with the first billing cycle after the PUCT issues a final order, but no later than the first billing cycle of September 2022. Also in May 2022, the PUCT referred the proceeding to the State Office of Administrative Hearings. In July 2022, Entergy Texas filed on behalf of the parties an unopposed settlement resolving all issues in the proceeding. In addition, Entergy Texas filed on behalf of the parties a motion to admit evidence, to approve interim rates as requested in the initial application, and to remand the proceeding to the PUCT to consider the unopposed settlement. In August 2022 the ALJ with the State Office of Administrative Hearings issued an order granting Entergy Texas’s motion, approving interim rates effective with the first billing cycle of September 2022, and remanding the case to the PUCT for final approval. The interim fuel surcharge was approved by the PUCT in January 2023.

In September 2022, Entergy Texas filed an application with the PUCT to reconcile its fuel and purchased power costs for the period from April 2019 through March 2022. During the reconciliation period, Entergy Texas incurred approximately $1.7 billion in eligible fuel and purchased power expenses, net of certain revenues credited to such expenses and other adjustments. As of the end of the reconciliation period, Entergy Texas’s cumulative under-recovery balance was approximately $103.1 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning April 2022, pending future surcharges or refunds as approved by the PUCT. In November 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In July 2023, Entergy Texas filed an unopposed settlement, supporting testimony, and an agreed motion to admit evidence and remand the proceeding to the PUCT. Pursuant to the unopposed settlement, Entergy Texas would receive no disallowance of fuel costs incurred over the three-year reconciliation period and retain $9.3 million in margins from off-system sales made during the reconciliation period, resulting in a cumulative under-recovery balance of approximately $99.7 million, including interest, as of the end of the reconciliation period. In July 2023 the ALJ with the State Office of Administrative Hearings granted the motion to admit evidence and remanded the proceeding to the PUCT for consideration of the unopposed settlement. The PUCT approved the settlement in September 2023.

In September 2024, Entergy Texas filed an application with the PUCT to reconcile its fuel and purchased power costs for the period from April 2022 through March 2024. During the reconciliation period, Entergy Texas incurred approximately $1.6 billion in eligible fuel and purchased power expenses to generate and purchase electricity to serve its customers, net of certain revenues credited to such expenses and other adjustments. Entergy Texas’s cumulative under-recovery balance for the reconciliation period was approximately $30 million, including interest, which Entergy Texas requested authority to carry over as part of the cumulative fuel balance for the subsequent reconciliation period beginning April 2024. In November 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 procedural schedule, with a hearing on the merits scheduled for May 2025. A PUCT decision is expected in third quarter 2025.
In December 2024, Entergy Texas filed an application with the PUCT to implement an interim fuel refund of $45.5 million, including interest. Entergy Texas proposed that the interim fuel refund be implemented over a three-month period beginning with the first billing cycle in February 2025 for residential and other small customers and through a one-time credit, or surcharge depending on historical usage for the respective customer, for certain transmission voltage level and seasonal agricultural customers in February 2025. Also in December 2024 the PUCT referred the proceeding to the State Office of Administrative Hearings. In January 2025 the ALJ with the State Office of Administrative Hearings issued an order approving the interim fuel refund consistent with Entergy Texas’s application and, because no hearing was requested in the proceeding, dismissing the case from the State Office of Administrative Hearings and the PUCT.
Retail Rate Proceedings

Filings with the APSC (Entergy Arkansas)

Retail Rates

2022 Formula Rate Plan Filing

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

2023 Formula Rate Plan Filing

In July 2023, Entergy Arkansas filed with the APSC its 2023 formula rate plan filing to set its formula rate for the 2024 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2024 and a netting adjustment for the historical year 2022. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2024 projected year was 8.11% resulting in a revenue deficiency of $80.5 million. The earned rate of return on common equity for the 2022 historical year was 7.29% resulting in a $49.8 million netting adjustment. The total proposed revenue change for the 2024 projected year and 2022 historical year netting adjustment was $130.3 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $88.6 million. The APSC general staff and intervenors filed their errors and objections in October 2023, proposing certain adjustments, including the APSC general staff’s update to annual filing year revenues which lowers the constraint to $87.7 million. Entergy Arkansas filed its rebuttal in October 2023. In October 2023, Entergy
Arkansas filed with the APSC a settlement agreement reached with other parties resolving all issues in the proceeding, none of which affected Entergy Arkansas’s requested recovery up to the constraint of $87.7 million. The settlement agreement provided for amortization of the approximately $39 million regulatory asset for costs associated with the COVID-19 pandemic over a 10-year period as well as recovery of $34.9 million related to the resolution of the 2016 and 2017 IRS audits from previous tax positions that are no longer uncertain, partially offset by $24.7 million in excess accumulated deferred income taxes from reductions in state income tax rates, each before consideration of their respective tax gross-up. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit and the State of Arkansas corporate income tax rate changes. In December 2023 the APSC approved the settlement agreement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2024.

2024 Formula Rate Plan Filing

In July 2024, Entergy Arkansas filed with the APSC its 2024 formula rate plan filing to set its formula rate for the 2025 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the 2025 projected year and a netting adjustment for the 2023 historical year. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2025 projected year was 8.43% resulting in a revenue deficiency of $69.5 million. The earned rate of return on common equity for the 2023 historical year was 7.48% resulting in a $33.1 million netting adjustment. The total proposed revenue change for the 2025 projected year and 2023 historical year netting adjustment is $102.6 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $82.6 million. The APSC general staff and intervenors filed their errors and objections in October 2024, proposing certain adjustments, including the APSC general staff’s update to annual filing year revenues that increases the constraint to $83.5 million. Entergy Arkansas filed its rebuttal in October 2024, and later in October 2024 the parties submitted a joint issues list and stipulations setting forth the disputed issues and the noncontested issues. In December 2024 the APSC approved the parties’ stipulations without modification, approved Entergy Arkansas’s adjustment with respect to storm costs, directed Entergy Arkansas to adjust its projected year distribution reliability capital closings, and deferred the recoverability of Entergy Arkansas’s opportunity sales legal fees until the next general rate case. Also in December 2024 the APSC approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2025. As a result of the proceeding, the total revenue change was $82.7 million, including a $63.7 million increase for the 2025 projected year and a $31.4 million netting adjustment for the 2023 historical year. In fourth quarter 2024, Entergy Arkansas recorded a regulatory asset of $15.5 million to reflect the amount of the 2023 historical year netting adjustment that it expects to collect from its customers during the 2025 rate effective period. Pursuant to the terms of the parties’ stipulations, Entergy Arkansas made a filing with the APSC in January 2025 to refund customers $30.1 million in excess accumulated deferred income taxes resulting from the reduction in the State of Arkansas’s income tax rate from 4.8% to 4.3% in 2024. Entergy Arkansas will make this refund over a 24-month period effective with the first billing cycle of February 2025.

Grand Gulf Credit Rider

In June 2024, Entergy Arkansas filed with the APSC a tariff to provide retail customers a credit resulting from the terms of the settlement agreement between Entergy Arkansas, System Energy, additional named Entergy parties, and the APSC pertaining to System Energy’s billings for wholesale sales of energy and capacity from the Grand Gulf nuclear plant. See “Complaints Against System Energy - System Energy Settlement with the APSC” below for discussion of the settlement. In July 2024 the APSC approved the tariff, under which Entergy Arkansas will refund to retail customers a total of $100.6 million. To date, Entergy Arkansas has refunded $92.3 million of the total through one-time bill credits during the August 2024 billing cycle and is finalizing plans for the refund of the remaining regulatory liability balance.
Filings with the LPSC (Entergy Louisiana)

Retail Rates - Electric

2020 Formula Rate Plan Filing

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

In November 2023 the LPSC approved a global settlement which resolved all outstanding issues related to the 2017, 2018, and 2019 formula rate plan filings and resolved certain issues with respect to the 2020 and 2021 formula rate plan filings. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” below for further discussion.

2021 Formula Rate Plan Filing

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

In November 2023 the LPSC approved a global settlement which resolved all outstanding issues related to the 2017, 2018, and 2019 formula rate plan filings and resolved certain issues with respect to the 2020 and 2021
formula rate plan filings. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” below for further discussion.

2022 Formula Rate Plan Filing

In May 2023, Entergy Louisiana filed its formula rate plan evaluation report for its 2022 calendar year operations. The 2022 test year evaluation report produced an earned return on common equity of 8.33%, requiring an approximately $70.7 million increase to base rider revenue. Due to a cap for the 2021 and 2022 test years, however, base rider formula rate plan revenues were only increased by approximately $4.9 million, resulting in a revenue deficiency of approximately $65.9 million and providing for prospective return on common equity opportunity of approximately 8.38%. Other changes in formula rate plan revenue driven by increases in capacity costs, primarily legacy capacity costs, additions eligible for recovery through the transmission recovery mechanism and distribution recovery mechanism, and higher sales during the test period were offset by reductions in net MISO costs as well as credits for FERC-ordered refunds. Also included in the 2022 test year distribution recovery mechanism revenue requirement was a $6 million credit relating to the distribution recovery mechanism performance accountability standards and requirements. In total, the net increase in formula rate plan revenues, including base formula rate plan revenues inside the formula rate plan bandwidth and subject to the cap, as well as other formula rate plan revenues outside of the bandwidth, was $85.2 million. In August 2023 the LPSC staff filed a list of objections/reservations, including outstanding issues from the test years 2017-2021 formula rate plan filings, the calculation of certain refunds from System Energy, and certain calculations relating to the tax reform adjustment mechanism. Subject to LPSC review, the resulting net increase in formula rate plan revenues of $85.2 million became effective for bills rendered during the first billing cycle of September 2023, subject to refund. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” below for further discussion.

2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request

In August 2023, Entergy Louisiana filed an application for approval of a regulatory blueprint necessary for it to strengthen the electric grid for the State of Louisiana, which contained a dual-path request to update rates through either: (1) extension of Entergy Louisiana’s current formula rate plan (with certain modifications) for three years (the Rate Mitigation Proposal), which is Entergy Louisiana’s recommended path; or (2) implementation of rates resulting from a cost-of-service study (the Rate Case path). The application complied with Entergy Louisiana’s previous formula rate plan extension order requiring that for Entergy Louisiana to obtain another extension of its formula rate plan that included a rate reset, Entergy Louisiana would need to submit a full cost-of-service rate case. Entergy Louisiana’s filing supported the need to extend Entergy Louisiana’s formula rate plan with credit supportive mechanisms needed to facilitate investment in the distribution, transmission, and generation functions.

In July 2024, Entergy Louisiana reached an agreement in principle with the LPSC staff and the intervenors in the proceeding and filed with the LPSC a joint motion to suspend the procedural schedule to allow for all parties to finalize a stipulated settlement agreement.

In August 2024, Entergy Louisiana and the LPSC staff jointly filed a global stipulated settlement agreement for consideration by the LPSC with key terms as follows:

•continuation of the formula rate plan for 2024-2026 (test years 2023-2025);
•a base formula rate plan revenue increase of $120 million for test year 2023, effective for rates beginning September 2024;
•a $140 million cumulative cap on base formula rate plan revenue increases, if needed, for test years 2024 and 2025, excluding outside the bandwidth items;
•$184 million of customer rate credits to be given over two years, including increasing customer sharing of income tax benefits resulting from the 2016-2018 IRS audit, to resolve any remaining disputed issues stemming from formula rate plan test years prior to test year 2023, including but not limited to the investigation into Entergy Services costs billed to Entergy Louisiana. As discussed in Note 3 to the financial statements, a $38 million regulatory liability was recorded in 2023 in connection with the 2016-2018 IRS audit;
•$75.5 million of customer rate credits, as provided for in the System Energy global settlement, to be credited over three years subject to and conditioned upon FERC approval of the System Energy global settlement, which was approved in November 2024. See “Complaints Against System Energy – System Energy Settlement with the LPSC” below for further details of the System Energy global settlement;
•$5.8 million of customer rate credits provided for in the Entergy Louisiana formula rate plan global settlement agreement approved by the LPSC in November 2023 credited over one year. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement;
•an increase in the allowed midpoint return on common equity from 9.5% to 9.7%, with a bandwidth of 40 basis points above and below the midpoint, for the extended term of the formula rate plan, except that for test year 2023 in which the authorized return on common equity shall have no bearing on the change in base formula rate plan revenue described above and, for test year 2024, any earnings above the authorized return on common equity shall be returned to customers through a credit;
•an increase in nuclear depreciation rates by $15 million in each of the 2023, 2024, and 2025 test years outside of the formula rate plan bandwidth calculation; and
•for the transmission recovery mechanism and the distribution recovery mechanism, no change to the existing floors, but the caps for both would be $350 million for test year 2023, $375 million for test year 2024, and $400 million for test year 2025. Transmission projects filed with the LPSC will be exempt from the transmission recovery mechanism cap.

The global stipulated settlement agreement was unanimously approved by the LPSC in August 2024 and an order was issued by the LPSC in September 2024 reflecting the approval of the settlement.

Based on the July 2024 agreement in principle, in second quarter 2024 Entergy Louisiana recorded expenses of $151 million ($112 million net-of-tax) primarily consisting of regulatory charges to reflect the effects of the agreement in principle.

Formula Rate Plan Global Settlement

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

2023 Formula Rate Plan Filing

In August 2024, pursuant to the global stipulated settlement agreement, Entergy Louisiana filed its formula rate plan evaluation report for its 2023 calendar year operations. Consistent with the global stipulated settlement agreement, the filing reflected a 9.7% allowed return on common equity with a bandwidth of 40 basis points above and below the midpoint. For the 2023 test year, however, the bandwidth provisions of the formula rate plan were
temporarily suspended and, pursuant to the terms of the global stipulated settlement agreement, Entergy Louisiana implemented the September 2024 formula rate plan rate adjustments effective with the first billing cycle of September 2024. Those adjustments included a $120 million increase in base rider formula rate plan revenue and a $101.8 million one-time incremental net decrease consistent with the terms of the global stipulated settlement. The formula rate plan rate adjustments reflected in the evaluation report also include a redetermination of the transmission recovery mechanism, the distribution recovery mechanism, the additional capacity mechanism, the tax adjustment mechanism, the MISO cost recovery mechanism, and other one-time adjustments. In January 2025, Entergy Louisiana and the LPSC filed a joint report indicating that no disputed issues remained in the proceeding and requesting that the LPSC issue an order accepting Entergy Louisiana’s evaluation report and, ultimately, resolving this matter. Entergy Louisiana expects a decision on the joint report in first quarter 2025.

Investigation of Costs Billed by Entergy Services

In November 2018 the LPSC issued a notice of proceeding initiating an investigation into costs incurred by Entergy Services that are included in the retail rates of Entergy Louisiana. As stated in the notice of proceeding, the LPSC observed an increase in capital construction-related costs incurred by Entergy Services. Discovery was issued and included efforts to seek highly detailed information on a broad range of matters unrelated to the scope of the audit. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” above for further discussion.

COVID-19 Orders

In April 2020 the LPSC issued an order authorizing utilities to record as a regulatory asset expenses incurred from the suspension of disconnections and collection of late fees imposed by LPSC orders associated with the COVID-19 pandemic. In April 2023, Entergy Louisiana filed an application proposing to utilize approximately $1.6 billion in certain low interest debt to generate earnings to apply toward the reduction of the COVID-19 regulatory asset, as well as to conduct additional outside right-of-way vegetation management activities and fund the minor storm reserve account. In that filing, Entergy Louisiana proposed to delay repayment of certain shorter-term first mortgage bonds that were issued to finance storm restoration costs until the costs could be securitized, and to invest the funds that otherwise would be used to repay those bonds in the money pool to take advantage of the spread between prevailing interest rates on investments in the money pool and the interest rates on the bonds. The LPSC approved Entergy Louisiana’s requested relief in June 2023. In November 2024, Entergy Louisiana submitted a filing to the LPSC requesting that the LPSC review Entergy Louisiana’s computation of the COVID-19 regulatory asset as well as Entergy Louisiana’s proposal to offset the regulatory asset against the interest earned on the short-term debt funds, resulting in no increased costs to customers. At the time of the filing, Entergy Louisiana had a regulatory asset of $47.8 million for costs associated with the COVID-19 pandemic. As of December 31, 2024, Entergy Louisiana had a regulatory liability of $48.9 million for the deferred earnings related to the approximately $1.6 billion in low interest debt, which had been fully repaid by August 2024. In granting Entergy Louisiana’s requested relief in June 2023, the LPSC ordered that any amount of earnings exceeding the amount of the COVID-19 regulatory asset be transferred to Entergy Louisiana’s storm reserve escrow account.

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 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.

Filings with the MPSC (Entergy Mississippi)

Retail Rates

2022 Formula Rate Plan Filing

In March 2022, Entergy Mississippi submitted its formula rate plan 2022 test year filing and 2021 look-back filing showing Entergy Mississippi’s earned return for the historical 2021 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2022 calendar year to be below the formula rate plan bandwidth. The 2022 test year filing showed a $69 million rate increase was necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.70% return on rate base, within the formula rate plan bandwidth. The change in formula rate plan revenues, however, was capped at 4% of retail revenues, which equated to a revenue change of $48.6 million. The 2021 look-back filing compared actual 2021 results to the approved benchmark return on rate base and reflected the need for a $34.5 million interim increase in formula rate plan revenues. In fourth quarter 2021, Entergy Mississippi recorded a regulatory asset of $19 million to reflect the then-current estimate in connection with the look-back feature of the formula rate plan. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $24.3 million interim rate increase, reflecting a cap equal to 2% of 2021 retail revenues, effective in April 2022. With the implementation of the interim formula rate plan rates, Entergy Mississippi began recovery of the bad debt expense deferral resulting from the COVID-19 pandemic over a three-year period.

In June 2022, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed the 2022 test year filing that resulted in a total rate increase of $48.6 million. Pursuant to the joint stipulation, Entergy Mississippi’s 2021 look-back filing reflected an earned return on rate base of 5.99% in calendar year 2021, which was below the look-back bandwidth, resulting in a $34.3 million increase in the formula rate plan revenues on an interim basis through June 2023. In July 2022 the MPSC approved the joint stipulation with rates effective in August 2022. In July 2022, Entergy Mississippi recorded regulatory credits of $22.6 million to reflect the effects of the joint stipulation.
In July 2022 the MPSC directed Entergy Mississippi to flow $14.1 million of the power management rider over-recovery balance to customers beginning in August 2022 through December 2022 to mitigate the bill impact of the increase in formula rate plan revenues.

2023 Formula Rate Plan Filing

In March 2023, Entergy Mississippi submitted its formula rate plan 2023 test year filing and 2022 look-back filing showing Entergy Mississippi’s earned return on rate base for the historical 2022 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2023 calendar year to be below the formula rate plan bandwidth. The 2023 test year filing showed a $39.8 million rate increase was necessary to reset Entergy Mississippi’s earned return on rate base to the specified point of adjustment of 6.67%, within the formula rate plan bandwidth. The 2022 look-back filing compared actual 2022 results to the approved benchmark return on rate base and reflected the need for a $19.8 million temporary increase in formula rate plan revenues, including the refund of a $1.3 million over-recovery resulting from the demand-side management costs true-up for 2022. In fourth quarter 2022, Entergy Mississippi recorded a regulatory asset of $18.2 million in connection with the look-back feature of the formula rate plan to reflect that the 2022 estimated earned return was below the formula rate plan bandwidth. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $27.9 million interim rate increase, reflecting a cap equal to 2% of 2022 retail revenues, effective in April 2023.

In May 2023, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed a 2023 test year filing resulting in a total revenue increase of $26.5 million for 2023. Pursuant to the joint stipulation, Entergy Mississippi’s 2022 look-back filing reflected an earned return on rate base of 6.10% in calendar year 2022, which was below the look-back bandwidth, resulting in a $19.0 million increase in the formula rate plan revenues on an interim basis through June 2024. Entergy Mississippi recorded a regulatory credit of $0.8 million in June 2023 to reflect the increase in the look-back regulatory asset. In addition, certain long-term service agreement and conductor handling costs were authorized for realignment from the formula rate plan to the annual power management and grid modernization riders effective January 2023, resulting in regulatory credits recorded in June 2023 of $4.1 million and $4.3 million, respectively. Also, the amortization of Entergy Mississippi’s COVID-19 bad debt expense deferral was suspended for calendar year 2023, but resumed in July 2024. In June 2023 the MPSC approved the joint stipulation with rates effective in July 2023.

2024 Formula Rate Plan Filing

In March 2024, Entergy Mississippi submitted its formula rate plan 2024 test year filing and 2023 look-back filing showing Entergy Mississippi’s earned return on rate base for the historical 2023 calendar year to be within the formula rate plan bandwidth and projected earned return for the 2024 calendar year to be below the formula rate plan bandwidth. The 2024 test year filing showed a $63.4 million rate increase was necessary to reset Entergy Mississippi’s earned return on rate base to the specified point of adjustment of 7.10%, within the formula rate plan bandwidth. The 2023 look-back filing compared actual 2023 results to the approved benchmark return on rate base and reflected no change in formula rate plan revenues. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $32.6 million interim rate increase, reflecting a cap equal to 2% of 2023 retail revenues, effective April 2024.

In December 2014 the MPSC ordered Entergy Mississippi to file an updated depreciation study at least once every four years. Pursuant to this order and Entergy Mississippi’s filing cycle, Entergy Mississippi would have filed an updated depreciation report with its formula rate plan filing in 2023. However, in July 2022 the MPSC directed Entergy Mississippi to file its next depreciation study in connection with its 2024 formula rate plan filing notwithstanding the MPSC’s prior order. Accordingly, Entergy Mississippi filed a depreciation study in February 2024. The study showed a need for an increase in annual depreciation expense of $55.2 million. The calculated increase in annual depreciation expense was excluded from Entergy Mississippi’s 2024 formula rate plan revenue increase request because the MPSC had not yet approved the proposed depreciation rates.
In June 2024, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed the 2024 test year filing, with the exception of immaterial adjustments to certain operation and maintenance expenses. After performance adjustments, the formula rate plan reflected an earned return on rate base of 6.08% for calendar year 2024, which resulted in a total revenue increase of $64.6 million for 2024. The joint stipulation also recommended approval of a revised customer charge of $31.82 per month for residential customers and $53.10 per month for general service customers. Pursuant to the stipulation, Entergy Mississippi’s 2023 look-back filing reflected an earned return on rate base of 6.81%, resulting in an increase of $0.3 million in the formula rate plan revenues for 2023. Finally, the stipulation recommended approval of Entergy Mississippi’s proposed depreciation rates with those rates to be implemented upon request and approval at a later date. In June 2024 the MPSC approved the joint stipulation with rates effective in July 2024. The approval also included a reduction to the energy cost factor, resulting in a net bill decrease for a typical residential customer using 1,000 kWh per month. Also in June 2024, Entergy Mississippi recorded regulatory credits of $7.3 million to reflect the difference between interim rates placed in effect in April 2024 and the rates reflected in the joint stipulation.

In May 2024, Entergy Mississippi received approval from the MPSC for formula rate plan revisions that were necessary for Entergy Mississippi to comply with state legislation passed in January 2024. The legislation allows Entergy Mississippi to make interim rate adjustments 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 filed the first of its annual interim facilities rate adjustment reports in May 2024 to recover approximately $8.7 million of these costs over a six-month period with rates effective beginning in July 2024. Entergy Mississippi filed its second annual interim facilities rate adjustment report in December 2024 to recover approximately $46.7 million of these costs over a 12-month period with rates effective beginning in January 2025.

Grand Gulf Capacity Filing

In September 2024, Entergy Mississippi filed a notice of intent with the MPSC to implement revisions to its unit power cost recovery rider that would allow Entergy Mississippi to recover the first year of costs associated with the transfer of Entergy Louisiana’s entitlements to Grand Gulf capacity and energy, which consists of Energy Louisiana’s interest in and purchases of Grand Gulf capacity and energy under the revised rider schedule, effective by January 1, 2025. This notice filing related to the divestiture of Entergy Louisiana’s 14% share of Grand Gulf capacity and energy under the Unit Power Sales Agreement and 2.43% share of capacity and energy from Entergy Arkansas under the MSS-4 replacement tariff. This divestiture is being effectuated initially through Entergy Mississippi’s purchases from Entergy Louisiana pursuant to a PPA governed by the MSS-4 replacement tariff, a tariff governing the sales of energy and capacity among the Utility operating companies as described in the System Energy global settlement with the LPSC and Entergy Louisiana. The MSS-4 replacement PPA to effectuate this divestiture was approved by the FERC in November 2024. In February 2025 the MPSC approved Entergy Mississippi’s notice of intent, finding that it was just and reasonable for Entergy Mississippi to obtain Entergy Louisiana’s entitlements to Grand Gulf capacity and energy and that Entergy Mississippi should be allowed to recover the costs associated with the transfer of such entitlements to Grand Gulf capacity and energy, as described above. The MPSC approved the MSS-4 replacement PPA, effective as of January 1, 2025. See “Complaints Against System Energy – System Energy Settlement with the LPSC” below for further details of the System Energy global settlement with the LPSC and Note 8 to the financial statements for discussion of the Unit Power Sales Agreement.

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.

Filings with the City Council (Entergy New Orleans)

Retail Rates

2022 Formula Rate Plan Filing

In April 2022, Entergy New Orleans submitted to the City Council its formula rate plan 2021 test year filing. The 2021 test year evaluation report, subsequently updated in a July 2022 filing, produced an earned return on equity of 6.88% compared to the authorized return on equity of 9.35%. Entergy New Orleans sought approval of a $42.1 million rate increase based on the formula set by the City Council in the 2018 rate case. The formula resulted in an increase in authorized electric revenues of $34.1 million and an increase in authorized gas revenues of $3.3 million. Entergy New Orleans also sought to commence collecting $4.7 million in electric revenues that were previously approved by the City Council for collection through the formula rate plan. In July 2022 the City Council’s advisors issued a report seeking a reduction to Entergy New Orleans’s proposed increase of approximately $17.1 million in total for electric and gas revenues. Effective with the first billing cycle of September 2022, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council including adjustments filed in the City Council’s advisors’ report, per the approved process for formula rate plan implementation. The total formula rate plan increase implemented was $24.7 million, which includes an increase of $18.2 million in electric revenues, $4.7 million in previously approved electric revenues, and an increase of $1.8 million in gas revenues. Additionally, credits of $13.9 million funded by certain regulatory liabilities currently held by Entergy New Orleans for customers were issued over an eight-month period beginning September 2022.

2023 Formula Rate Plan Filing

In April 2023, Entergy New Orleans submitted to the City Council its formula rate plan 2022 test year filing. The 2022 test year evaluation report produced an electric earned return on equity of 7.34% and a gas earned return on equity of 3.52% compared to the authorized return on equity for each of 9.35%. Entergy New Orleans sought approval of a $25.6 million rate increase based on the formula set by the City Council in the 2018 rate case. The formula would result in an increase in authorized electric revenues of $17.4 million and an increase in authorized gas revenues of $8.2 million. Entergy New Orleans also sought to commence collecting $3.4 million in electric revenues that were previously approved by the City Council for collection through the formula rate plan. In July 2023, Entergy New Orleans filed a report to decrease its requested formula rate plan revenues by approximately $0.5 million to account for minor errors discovered after the filing. The City Council advisors issued a report seeking a reduction in the requested formula rate plan revenues of approximately $8.3 million, combined for electric and gas, due to alleged errors. The City Council advisors proposed additional rate mitigation in the amount of $12 million through offsets to the formula rate plan rate increase by certain regulatory liabilities. In September 2023 the City Council approved an agreement to settle the 2023 formula rate plan filing. Effective with the first billing cycle of September 2023, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council, per the approved process for formula rate plan implementation. The agreement provides for a total increase in electric revenues of $10.5 million and a total increase in gas revenues of
$6.9 million. The agreement also provides for a minor storm accrual of $0.5 million per year and the distribution of $8.9 million of currently held customer credits to implement the City Council advisors’ mitigation recommendations.

Request for Extension and Modification of Formula Rate Plan

In September 2023, Entergy New Orleans filed a motion seeking City Council approval of a three-year extension of Entergy New Orleans’s electric and gas formula rate plans. In October 2023 the City Council granted Entergy New Orleans’s request for an extension, subject to minor modifications which included a 55% equity ratio for rate setting purposes.

2024 Formula Rate Plan Filing

In April 2024, Entergy New Orleans submitted to the City Council its formula rate plan 2023 test year filing. Without the requested rate change in 2024, the 2023 test year evaluation report produced an electric earned return on equity of 8.66% and a gas earned return on equity of 5.87% compared to the authorized return on equity for each of 9.35%. Entergy New Orleans sought approval of a $12.6 million rate increase based on the formula set by the City Council in the 2018 rate case and approved again by the City Council in 2023. The formula would result in an increase in authorized electric revenues of $7.0 million and an increase in authorized gas revenues of $5.6 million. Following City Council review, the City Council’s advisors issued a report in July 2024 seeking a reduction in Entergy New Orleans’s requested formula rate plan revenues in an aggregate amount of approximately $1.6 million for electric and gas together due to alleged errors. Effective with the first billing cycle of September 2024, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council, per the approved process for formula rate plan implementation. The total formula rate plan increase implemented was $11.2 million, which includes an increase of $5.8 million in electric revenues and an increase of $5.4 million in gas revenues.

Filings with the PUCT and Texas Cities (Entergy Texas)

Retail Rates

2022 Base Rate Case

In July 2022, Entergy Texas filed a base rate case with the PUCT seeking a net increase in base rates of approximately $131.4 million. The base rate case was based on a 12-month test year ending December 31, 2021. Key drivers of the requested increase were changes in depreciation rates as the result of a depreciation study and an increase in the return on equity. In addition, Entergy Texas included capital additions placed into service for the period of January 1, 2018 through December 31, 2021, including those additions reflected in the then-effective distribution and transmission cost recovery factor riders and the generation cost recovery rider, all of which were reset to zero in June 2023 as a result of this proceeding. In July 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In October 2022 intervenors filed direct testimony challenging and supporting various aspects of Entergy Texas’s rate case application. The key issues addressed included the appropriate return on equity, generation plant deactivations, depreciation rates, and proposed tariffs related to electric vehicles. In November 2022 the PUCT staff filed direct testimony addressing a similar set of issues and recommending a reduction of $50.7 million to Entergy Texas’s overall cost of service associated with the requested net increase in base rates of approximately $131.4 million. Entergy Texas filed rebuttal testimony in November 2022.

In May 2023, Entergy Texas filed on behalf of the parties an unopposed settlement resolving all issues in the proceeding, except for issues related to electric vehicle charging infrastructure which were eventually severed to a separate proceeding and resolved in October 2024, and Entergy Texas filed an agreed motion for interim rates, subject to refund or surcharge to the extent that the interim rates differ from the final approved rates. The unopposed settlement reflected a net base rate increase to be effective and relate back to December 2022 of
$54 million, exclusive of, and incremental to, the costs being realigned from the distribution and transmission cost recovery factor riders and the generation cost recovery rider and $4.8 million of rate case expenses to be recovered through a rider over a period of 36 months. The net base rate increase of $54 million includes updated depreciation rates and a total annual revenue requirement of $14.5 million for the accrual of a self-insured storm reserve and the recovery of the regulatory assets for the pension and postretirement benefits expense deferral, costs associated with the COVID-19 pandemic, and retired non-advanced metering system electric meters. In May 2023 the ALJ with the State Office of Administrative Hearings granted the motion for interim rates, which became effective in June 2023. Additionally, the ALJ remanded the proceeding to the PUCT to consider the settlement. In August 2023 the PUCT issued an order approving the unopposed settlement. Concurrently, Entergy Texas recorded the reversal of $21.9 million of regulatory liabilities to reflect the recognition of certain receipts by Entergy Texas under affiliated PPAs that have been resolved.

Following the PUCT’s approval of the unopposed settlement in August 2023, Entergy Texas recorded a regulatory liability of $10.3 million, which reflected the net effects of higher depreciation and amortizations for the relate back period, partially offset by the relate back of base rate revenues that would have been collected had the approved rates been in effect for the period from December 2022 through June 2023, the date the new base rates were implemented on an interim basis. In October 2023, Entergy Texas filed a relate back surcharge rider to collect over six months beginning in January 2024 an additional approximately $24.6 million, which was the revenue requirement associated with the relate back of rates from December 2022 through June 2023, including carrying costs, as authorized by the PUCT’s August 2023 order. In November 2023, Entergy Texas filed an amended relate back surcharge rider to collect approximately $24.1 million based on a revised carrying cost rate. The amended relate back surcharge rider was approved by the PUCT in December 2023. The higher depreciation and amortizations for the relate back period were also recognized over the six months beginning in January 2024, resulting in no effect on net income from the collection of the relate back surcharge rider.

Distribution Cost Recovery Factor (DCRF) Rider

In June 2024, Entergy Texas filed with the PUCT a request to set a new DCRF rider. The new rider was designed to collect from Entergy Texas’s retail customers approximately $40.3 million annually based on its capital invested in distribution between January 1, 2022 and March 31, 2024. In September 2024 the PUCT approved the DCRF rider, consistent with Entergy Texas’s as-filed request, and rates became effective with the first billing cycle in October 2024.

In September 2024, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $48.9 million annually, or $8.6 million in incremental annual revenues beyond Entergy Texas’s then-effective DCRF rider based on its capital invested in distribution between April 1, 2024 and June 30, 2024. In December 2024, Entergy Texas filed an errata to revise its DCRF application for minor corrections, which decreased the requested annual revenue requirement to $48.5 million. The amended request represented an incremental increase of $8.2 million in annual revenues beyond Entergy Texas’s then-effective DCRF rider. Also in December 2024 the PUCT approved the DCRF rider, consistent with Entergy Texas’s filed errata, and rates became effective on December 20, 2024.

Transmission Cost Recovery Factor (TCRF) Rider

In December 2018, Entergy Texas filed with the PUCT a request to set a new TCRF rider. The new TCRF rider was designed to collect approximately $2.7 million annually from Entergy Texas’s retail customers based on its capital invested in transmission between January 1, 2018 and September 30, 2018. In April 2019 parties filed testimony proposing a load growth adjustment, which would fully offset Entergy Texas’s proposed TCRF revenue requirement. In July 2019 the PUCT granted Entergy Texas’s application as filed to begin recovery of the requested $2.7 million annual revenue requirement, rejecting opposing parties’ proposed adjustment; however, the PUCT found that the question of prudence of the actual investment costs should be determined in Entergy Texas’s next rate case similar to the procedure used for the costs recovered through the DCRF rider. In October 2019 the PUCT
issued an order on a motion for rehearing, clarifying and affirming its prior order granting Entergy Texas’s application as filed. Also in October 2019 a second motion for rehearing was filed, and Entergy Texas filed a response in opposition to the motion. The second motion for rehearing was overruled by operation of law. In December 2019, Texas Industrial Energy Consumers filed an appeal to the PUCT order in district court alleging that the PUCT erred in declining to apply a load growth adjustment.

In October 2021, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $66.1 million annually, or $15.1 million in incremental annual revenues beyond Entergy Texas’s then-effective TCRF rider based on its capital invested in transmission between September 1, 2020 and July 31, 2021 and changes in approved transmission charges. In January 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In February 2022 the parties filed an unopposed settlement recommending that Entergy Texas be allowed to collect its full requested TCRF revenue requirement with interim rates effective March 2022. In February 2022 the ALJ granted the motion for interim rates, admitted evidence, and remanded the case to the PUCT for consideration of a final order at a future open meeting. In June 2022 the PUCT issued an order approving the settlement.

In October 2024, Entergy Texas filed with the PUCT a request to amend its TCRF rider, which was previously reset to zero in June 2023 as a result of the 2022 base rate case. The proposed rider is designed to collect from Entergy Texas’s retail customers approximately $9.7 million annually based on its capital invested in transmission between January 1, 2022 and June 30, 2024 and changes in other transmission charges. In December 2024 the PUCT staff filed a recommendation that the PUCT approve Entergy Texas’s as-filed application. In February 2025 the PUCT staff issued a proposed order that, if approved by the PUCT, would approve Entergy Texas’s TCRF rider as filed.

Generation Cost Recovery Rider

In October 2020, Entergy Texas filed an application to establish a generation cost recovery rider to begin recovering a return of and on its generation capital investment in the Montgomery County Power Station. Entergy Texas filed an unopposed settlement agreement in December 2020, and the PUCT approved the generation cost recovery rider settlement rates on an interim basis in January 2021. In March 2021, Entergy Texas filed to update its generation cost recovery rider, and an unopposed settlement agreement filed by Entergy Texas on behalf of the parties in October 2021 was approved by the PUCT in January 2022. In February 2022, Entergy Texas filed a relate-back rider to collect over five months an additional approximately $5 million, which was the difference between the interim revenue requirement approved in January 2021 and the revenue requirement approved in January 2022 reflecting Entergy Texas’s full generation capital investment and ownership in Montgomery County Power Station on January 1, 2021, plus carrying costs from January 2021 through January 2022 when the updated revenue requirement took effect. The PUCT approved the relate-back rider consistent with Entergy Texas’s as-filed request, and rates became effective over a five-month period, in August 2022.

In December 2020, Entergy Texas also filed an application to amend its generation cost recovery rider to reflect its acquisition of the Hardin County Peaking Facility, which closed in June 2021. Because Hardin was to be acquired in the future, the initial generation cost recovery rider rates proposed in the application represented no change from the generation cost recovery rider rates established in Entergy Texas’s previous generation cost recovery rider proceeding. In July 2021 the PUCT issued an order approving the application. In August 2021, Entergy Texas filed an update application to recover its actual investment in the acquisition of the Hardin County Peaking Facility, and in January 2022, Entergy Texas filed an update to its application to align the requested revenue requirement with the terms of the generation cost recovery rider settlement approved by the PUCT in January 2022. In April 2022, Entergy Texas filed on behalf of the parties a unanimous settlement agreement that would adjust its generation cost recovery rider to recover an annual revenue requirement of approximately $92.8 million, which was $4.5 million in incremental annual revenue above the revenue requirement approved in January 2022 described above and related to Entergy Texas’s investment in the Montgomery County Power Station. The PUCT approved the settlement agreement and rates became effective in August 2022. In September 2022,
Entergy Texas filed a relate-back rider designed to collect over three months an additional approximately $5.7 million, which is the revenue requirement, plus carrying costs, associated with Entergy Texas’s acquisition of Hardin County Peaking Facility from June 2021 through August 2022 when the updated revenue requirement took effect. In April 2023 the PUCT approved Entergy Texas’s as-filed request with rates effective over three months beginning in May 2023.
Entergy Arkansas Opportunity Sales Proceeding

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

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

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

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

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

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

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

In October 2018 the FERC issued an order addressing the ALJ’s July 2017 initial decision. The FERC reversed the ALJ’s decision to cap the reduction in Entergy Arkansas’s payment to account for the increased bandwidth payments that Entergy Arkansas made to the other operating companies. The FERC also reversed the ALJ’s decision that Grand Gulf sales from January through September 2000 should be included in the calculation of Entergy Arkansas’s payment. The FERC affirmed on other grounds the ALJ’s rejection of the LPSC’s claim that certain joint account sales should be accounted for as part of the calculation of Entergy Arkansas’s payment. In November 2018 the LPSC requested rehearing of the FERC’s October 2018 decision. In December 2019 the FERC denied the LPSC’s request for rehearing. In January 2020 the LPSC appealed the December 2019 decision to the D.C. Circuit.
In December 2018, Entergy made a compliance filing in response to the FERC’s October 2018 order. The compliance filing provided a final calculation of Entergy Arkansas’s payments to the other Utility operating companies, including interest. No protests were filed in response to the December 2018 compliance filing. Refunds and interest in the following amounts were paid by Entergy Arkansas to the other operating companies in December 2018:
 Total refunds including interest
Payment/(Receipt)
 (In Millions)
PrincipalInterestTotal
Entergy Arkansas$68$67$135
Entergy Louisiana($30)($29)($59)
Entergy Mississippi($18)($18)($36)
Entergy New Orleans($3)($4)($7)
Entergy Texas($17)($16)($33)

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

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

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

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

In July 2020 the APSC issued a decision finding that Entergy Arkansas’s application is not in the public interest. The order also directed Entergy Arkansas to refund to its retail customers within 30 days of the order the FERC-determined over-collection of $13.7 million, plus interest, associated with a recalculated bandwidth remedy. In addition to these primary findings, the order also denied the Attorney General’s request for Entergy Arkansas to prepare a compliance filing detailing all of the retail impacts from the opportunity sales and denied a request by the Arkansas Electric Energy Consumers to recalculate all costs using the revised responsibility ratio. Entergy Arkansas filed a motion for temporary stay of the 30-day requirement to allow Entergy Arkansas a reasonable opportunity to seek rehearing of the APSC order, but in July 2020 the APSC denied Entergy Arkansas’s request for a stay and directed Entergy Arkansas to refund to its retail customers the component of the total FERC-determined opportunity sales payment that was associated with increased bandwidth remedy payments of $13.7 million, plus interest. The refunds were issued in the August 2020 billing cycle. While the APSC denied Entergy Arkansas’s stay request, Entergy Arkansas believes its actions were prudent and, therefore, the costs, including the $13.7 million, plus interest, are recoverable. In July 2020, Entergy Arkansas requested rehearing of the APSC order, which rehearing was denied by the APSC in August 2020. In September 2020, Entergy Arkansas filed a complaint in the U.S. District Court for the Eastern District of Arkansas challenging the APSC’s order denying Entergy Arkansas’s request to recover the costs of these payments. In October 2020 the APSC filed a motion to dismiss Entergy Arkansas’s complaint, to which Entergy Arkansas responded. Also in December 2020, Entergy Arkansas and the APSC held a pre-trial conference, and filed a report with the court in January 2021. The court held a hearing in February 2021 regarding issues addressed in the pre-trial conference report, and in June 2021 the court stayed all discovery until it rules on pending motions, after which the court will issue an amended schedule if necessary. In March 2022 the court denied the APSC’s motion to dismiss, and, in April 2022, issued a scheduling order including a trial date in February 2023. In June 2022, Entergy Arkansas filed a motion asserting that it is entitled to summary judgment because Entergy Arkansas’s position that the APSC’s order is pre-empted by the filed rate doctrine and violates the Dormant Commerce Clause is premised on facts that are not subject to genuine dispute. In July 2022, Arkansas Electric Energy Consumers, Inc., an industrial customer association, filed a motion to intervene and to hold Entergy Arkansas’s motion for summary judgment in abeyance pending a ruling on the motion to intervene. Entergy Arkansas filed a consolidated opposition to both motions. In August 2022 the APSC filed a motion for summary judgment arguing that there is no genuine issue as to any material fact and the APSC is entitled to judgment as a matter of law. In September 2022, Entergy Arkansas filed an opposition to the motion. In October 2022 the APSC filed a motion asking the court to hold further proceedings in abeyance pending a decision on the motions for summary judgment filed by Entergy Arkansas and the APSC. Also in October 2022, Entergy Arkansas filed an opposition to the motion, and the APSC filed a reply in support of its motion for summary judgment. In January 2023 the judge assigned to the case, on her own motion, identified facts that may present a conflict and recused herself; a new judge was assigned to the case, but he also recused due to a conflict. The case again was reassigned to a new judge. In January 2023 the court denied all pending motions (including those described above) except for a motion by the APSC to exclude certain testimony and further ruled that the matter would proceed to trial. In January 2023, Arkansas Electric Energy Consumers, Inc. filed a notice of appeal of the court’s order denying its motion to intervene to the United States Court of Appeals for the Eighth Circuit and a motion with the district court to stay the proceedings pending the appeal, which was denied. In February 2023, Arkansas Electric Energy Consumers, Inc. filed a motion with the United States Court of Appeals for the Eighth Circuit to stay the proceedings pending the appeal, which also was denied. The trial was held in February 2023. Following the trial, Entergy Arkansas filed a motion with the United States Court of Appeals for the Eighth Circuit to expedite the appeal filed by Arkansas Electric Energy Consumers, Inc. The United States Court of Appeals for
the Eighth Circuit granted Entergy Arkansas’s request, and oral arguments were held in June 2023. In August 2023 the United States Court of Appeals for the Eighth Circuit affirmed the order of the court denying Arkansas Electric Energy Consumers, Inc.’s motion to intervene.

In March 2024 the U.S. District Court for the Eastern District of Arkansas issued a judgment in favor of the APSC and against Entergy Arkansas. In March 2024 Entergy Arkansas filed a notice of appeal and a motion to expedite oral arguments with the United States Court of Appeals for the Eighth Circuit and the court granted the motion to expedite. Briefing to the United States Court of Appeals for the Eighth Circuit concluded in July 2024 and oral arguments concluded in September 2024. As a result of the adverse decision by the U.S. District Court for the Eastern District of Arkansas, Entergy Arkansas concluded that it could no longer support the recognition of its $131.8 million regulatory asset reflecting the previously-expected recovery of a portion of the costs at issue in the opportunity sales proceeding and recorded a $131.8 million ($99.1 million net-of-tax) charge to earnings in first quarter 2024. In December 2024 the United States Court of Appeals for the Eighth Circuit affirmed the decision of the U.S. District Court for the Eastern District of Arkansas, and Entergy Arkansas filed a petition for rehearing en banc. In January 2025 the United States Court of Appeals for the Eighth Circuit denied Entergy Arkansas’s petition. Entergy Arkansas is evaluating a petition for certiorari with the United States Supreme Court.
MSS-4 Replacement Tariff – Net Operating Loss Carryforward Proceeding

In January 2021, pursuant to section 205 of the Federal Power Act, Entergy Services filed an amendment to the MSS-4 replacement tariff, a tariff governing the sales of energy and capacity among the Utility operating companies, in order to provide for the inclusion of specified accumulated deferred income taxes, including net operating loss carryforward accumulated deferred income taxes (NOLC ADIT), in the rate for sales of energy among the Utility operating companies on a prospective basis. In March 2021, the FERC accepted the filing, subject to refund and hearing procedures.

In October 2021 the LPSC filed a complaint with the FERC alleging that Entergy Services improperly excluded NOLC ADIT from MSS-4 replacement tariff rates in the period before March 20, 2021. The LPSC argued that sales from Entergy Louisiana to Entergy Texas and Entergy New Orleans were charged at rates lower than they otherwise should have been, and it accordingly seeks surcharges for the period prior to March 20, 2021. The FERC set the complaint for hearing procedures and subsequently the hearing for this complaint proceeding was consolidated with the hearing procedures for Entergy Services’ January 2021 NOLC ADIT filing.

Testimony was filed by parties in 2023, and the hearing before a FERC ALJ was concluded in February 2024. In June 2024, the FERC ALJ issued an initial decision addressing three major issues: (1) whether Entergy Services’ proposed prospective inclusion and allocation of NOLC ADIT in MSS-4 replacement tariff rates using a modified with-and-without methodology is just and reasonable; (2) whether Entergy Services correctly calculated excess and deficient accumulated deferred income taxes in accordance with the terms of a prior settlement; and (3) whether NOLC ADIT should have been included in MSS-4 replacement tariff rates prior to the effective date of the January 2021 MSS-4 replacement tariff filing.

With respect to issues (1) and (2), the presiding ALJ concluded that Entergy Services’ proposed methodology for allocating and including NOLC ADIT in MSS-4 replacement tariff rates was just and reasonable and that Entergy Services correctly performed the excess and deficient accumulated deferred income taxes calculations. With respect to issue (3), however, the presiding ALJ agreed with the LPSC that NOLC ADIT should have been included in MSS-4 replacement tariff rates since September 1, 2016, and as a result, the presiding ALJ ordered that Entergy Louisiana and Entergy Arkansas recalculate bills for the period of September 1, 2016 through November 11, 2023 with surcharges expected to be due to those operating companies from the purchasing operating companies, Entergy New Orleans, Entergy Texas, and Entergy Louisiana (for some Entergy Arkansas sales). The presiding ALJ also ordered Entergy Services to pay the interest owed to Entergy Louisiana on these surcharges.
The surcharge methodology that the presiding ALJ recommended in connection with issue (3) was not supported by any participant in the hearing. As part of their exceptions to the initial decision, all parties to the proceeding opposed the use of the ALJ’s methodology, except for the FERC trial staff, which took no position. During the hearing, the LPSC and the FERC trial staff advocated that the alleged tariff violation should be remedied by the application of Entergy Services’ January 2021 proposed methodology. All other parties, including the PUCT, the City Council, and Entergy Services, opposed any surcharges for the period prior to the March 20, 2021 effective date of the January 2021 filing.

Entergy Services disputes the presiding ALJ's rulings on issue (3) and filed exceptions to these rulings in July 2024. The ALJ's initial decision is not binding on the FERC and is an interim step in the hearing process. No refunds will be owed in connection with this proceeding unless and until the FERC requires them in a final order.
Complaints Against System Energy

System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf.  System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. System Energy and the Unit Power Sales Agreement have been the subject of several litigation proceedings at the FERC, including challenges with respect to System Energy’s authorized return on equity and capital structure, renewal of its sale-leaseback arrangement, treatment of uncertain tax positions, a broader investigation of rates under the Unit Power Sales Agreement, and two prudence complaints, one challenging the extended power uprate completed at Grand Gulf in 2012 and the operation and management of Grand Gulf, particularly in the 2016-2020 time period, and the second challenging the operation and management of Grand Gulf in the 2021-2022 time period. Settlements that resolve all significant aspects of these complaints have been reached with the MPSC, the APSC, the City Council, and the LPSC, and these settlements have been approved by the FERC. Following are discussions of the proceedings.

Return on Equity and Capital Structure Complaints

In January 2017 the APSC and the MPSC filed a complaint with the FERC against System Energy. The complaint sought a reduction in the return on equity component of the Unit Power Sales Agreement pursuant to which System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. Entergy Arkansas also sells some of its Grand Gulf capacity and energy to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under separate agreements. The return on equity under the Unit Power Sales Agreement at the time of the complaint was 10.94%, which was established in a rate proceeding that became final in July 2001.

The APSC and the MPSC complaint alleged that the return on equity was unjust and unreasonable because capital market and other considerations indicated that it was excessive. The complaint requested proceedings to investigate the return on equity and establish a lower return on equity, and also requested that the FERC establish January 23, 2017 as a refund effective date. The complaint included a return on equity analysis that purported to establish that the range of reasonable return on equity for System Energy was between 8.37% and 8.67%. System Energy answered the complaint in February 2017 and disputed that a return on equity of 8.37% to 8.67% was just and reasonable. The LPSC and the City Council intervened in the proceeding expressing support for the complaint. In September 2017 the FERC established a refund effective date of January 23, 2017 and directed the parties to engage in settlement proceedings before an ALJ. The parties were unable to settle the return on equity issue and a FERC hearing judge was assigned in July 2018. The 15-month refund period in connection with the APSC/MPSC complaint expired on April 23, 2018.

In April 2018 the LPSC filed a complaint with the FERC against System Energy seeking an additional 15-month refund period.  The LPSC complaint requested similar relief from the FERC with respect to System Energy’s
return on equity and also requested the FERC to investigate System Energy’s capital structure.  The APSC, the MPSC, and the City Council intervened in the proceeding, filed an answer expressing support for the complaint, and asked the FERC to consolidate this proceeding with the proceeding initiated by the complaint of the APSC and the MPSC in January 2017. System Energy answered the LPSC complaint in May 2018 and also filed a motion to dismiss the complaint. In August 2018 the FERC issued an order dismissing the LPSC’s request to investigate System Energy’s capital structure and setting for hearing the return on equity complaint, with a refund effective date of April 27, 2018. The 15-month refund period in connection with the LPSC return on equity complaint expired on July 26, 2019.

The portion of the LPSC’s complaint dealing with return on equity was subsequently consolidated with the APSC and the MPSC complaint for hearing. The parties also addressed an order (issued in a separate FERC proceeding involving New England transmission owners) that proposed modifying the FERC’s standard methodology for determining return on equity. In September 2018 the LPSC filed an amended complaint raising the same capital structure claim the FERC had earlier dismissed. The FERC initiated a new proceeding for the amended capital structure complaint, and System Energy answered the complaint in October 2018. In January 2019 the FERC set the amended complaint for settlement and hearing proceedings. Settlement proceedings in the capital structure proceeding commenced in February 2019, but were terminated in June 2019, and the amended capital structure complaint was consolidated with the ongoing return on equity proceeding. The 15-month refund period in connection with the capital structure complaint was from September 24, 2018 to December 23, 2019.

Several rounds of testimony were filed by the parties in these proceedings between January 2019 and August 2020. Some of these rounds of testimony were precipitated by developments in an unrelated proceeding in which the FERC issued orders addressing the methodology for determining the return on equity applicable to transmission owners in MISO (Opinion Nos. 569 and 569-A). The final positions of the parties, after the submission of all pre-filed testimony, were as follows. With regard to the return on equity complaints for the first refund period, based on their respective interpretations and applications of the Opinion No. 569-A methodology, the LPSC argued for an authorized return on equity for System Energy of 7.97%; the MPSC and the APSC argued for an authorized return on equity of 9.24%; and the FERC trial staff argued for an authorized return on equity of 9.49%. For the second refund period and on a prospective basis, based on their respective interpretations and applications of the Opinion No. 569-A methodology, the LPSC argued for an authorized return on equity for System Energy of 7.78%; the MPSC and the APSC argued that an authorized return on equity of 9.15% may be appropriate if the second complaint was not dismissed; and the FERC trial staff argued for an authorized return on equity of 9.09% if the second complaint was not dismissed. The LPSC also continued to support as its primary recommendation, based on an alternative analysis to the Opinion No. 569-A methodology, an authorized return on equity for System Energy as low as 7.56% for the first complaint refund period and as low as 7.18% for the second complaint refund period and prospectively. The MPSC and the APSC also continued to support as their primary recommendation, based on an alternative analysis to the Opinion No. 569-A methodology, an authorized return on equity for System Energy as low as 8.26% for the first complaint refund period and as low as 8.32% for the second complaint refund period and prospectively. System Energy argued that strict application of the Opinion No. 569-A methodology produces results inconsistent with investor requirements and does not provide a sound basis on which to evaluate System Energy’s authorized return on equity. Therefore, as its primary recommendation, System Energy argued for the use of a methodology that incorporates four separate financial models and, based on application of this recommended methodology, an authorized return on equity of 10.12% for the first refund period, which also fell within the presumptively just and reasonable range calculated for the second refund period and prospectively. Under the Opinion No. 569-A methodology, System Energy calculated an authorized return on equity of 9.44% for the first refund period, which also fell within the presumptively just and reasonable range calculated for the second refund period and prospectively.

With regard to the capital structure, the LPSC’s primary recommendation was that the FERC establish a hypothetical capital structure for System Energy for ratemaking purposes, according to which System Energy’s common equity ratio would be set to Entergy Corporation’s equity ratio of 37% equity and 63% debt. The APSC and the MPSC recommended that 35.98% be set as the common equity ratio for System Energy. The FERC trial
staff argued that the average capital structure of the proxy group used to develop System Energy’s return on equity should be used to establish the capital structure. Using this approach, the FERC trial staff calculated the average capital structure for its proposed proxy group of 46.74% common equity and 53.26% debt. System Energy disputed all of these recommendations and argued that the use of its actual capital structure was just and reasonable.

After conducting a hearing, in March 2021 the FERC ALJ issued an initial decision. With regard to System Energy’s authorized return on equity, the ALJ determined that the existing return on equity of 10.94% was no longer just and reasonable, and that the replacement authorized return on equity, based on application of the Opinion No. 569-A methodology, should be 9.32%. The ALJ further determined that System Energy should pay refunds for a fifteen-month refund period (January 2017-April 2018) based on the difference between the current return on equity and the replacement authorized return on equity. The ALJ determined that the April 2018 complaint concerning the authorized return on equity should be dismissed, and that no refunds for a second fifteen-month refund period should be due. With regard to System Energy’s capital structure, the ALJ determined that System Energy’s actual equity ratio was excessive and that the just and reasonable equity ratio was 48.15% equity, based on the average equity ratio of the proxy group used to evaluate the return on equity for the second complaint. The ALJ further determined that System Energy should pay refunds for a fifteen-month refund period (September 2018-December 2019) based on the difference between the actual equity ratio and the 48.15% equity ratio.

In April 2021, System Energy filed its brief on exceptions, in which it challenged the initial decision’s findings on both the return on equity and capital structure issues. Also in April 2021 the LPSC, the APSC, the MPSC, the City Council, and the FERC trial staff filed briefs on exceptions. Reply briefs opposing exceptions were filed in May 2021 by System Energy, the FERC trial staff, the LPSC, the APSC, the MPSC, and the City Council.

As discussed below in “System Energy Settlement with the MPSC,” “System Energy Settlement with the APSC,” “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the MPSC, the APSC, the City Council, and the LPSC have settled their claims related to these proceedings. As part of the settlements with their respective retail regulators, effective July 2022 for Entergy Mississippi, November 2023 for Entergy Arkansas, June 2024 for Entergy New Orleans, and September 2024 for Entergy Louisiana, bills issued under the Unit Power Sales Agreement reflect a return on equity of 9.65% and a capital structure not to exceed 52% equity.

In August 2022 the D.C. Circuit issued an order addressing appeals of FERC’s Opinion No. 569 and 569-A, which established the methodology applied in the ALJ’s initial decision in the proceeding against System Energy discussed above. The appellate order addressed the methodology for determining the return on equity applicable to transmission owners in MISO. The D.C. Circuit found the FERC’s use of the Risk Premium model as part of the methodology to be arbitrary and capricious, and remanded the case back to the FERC. In October 2024, after System Energy had reached settlements with each of the retail regulators involved in the return on equity and capital structure proceeding discussed above, the FERC issued a remand order in the MISO transmission owners’ return on equity case, concluding that the record supported the methodology that it originally directed in Opinion No. 569 utilizing an equal weighting of the two-step discounted cash flow model and capital asset pricing model. As a result, it determined that the just and reasonable return on equity for the MISO transmission owners is 9.98%. In light of the System Energy settlements detailed below, the FERC’s changes to its return on equity methodology in the decision on the MISO transmission owners’ return on equity will not have any immediate effect on System Energy’s return on equity because System Energy’s return on equity has been set at 9.65% through the global settlement through the end of June 2026.

Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue

In May 2018 the LPSC filed a complaint against System Energy and Entergy Services related to System Energy’s renewal of a sale-leaseback transaction originally entered into in December 1988 for an 11.5% undivided interest in Grand Gulf Unit 1. The complaint alleged that System Energy violated the filed rate and the FERC’s ratemaking and accounting requirements when it included in Unit Power Sales Agreement billings the cost of
capital additions associated with the sale-leaseback interest, and that System Energy was double-recovering costs by including both the lease payments and the capital additions in Unit Power Sales Agreement billings. The complaint also claimed that System Energy was imprudent in entering into the sale-leaseback renewal because the Utility operating companies that purchase Grand Gulf’s output from System Energy could have obtained cheaper capacity and energy in the MISO markets. The complaint further alleged that System Energy violated various other reporting and accounting requirements and should have sought prior FERC approval of the lease renewal. The complaint sought various forms of relief from the FERC, including refunds for capital addition costs for all years in which they were recorded in allegedly non-formula accounts or, alternatively, the disallowance of the return on equity for the capital additions in those years plus interest; a disallowance and refund of the lease costs of the sale-leaseback renewal on grounds of imprudence; an investigation into System Energy’s treatment of a DOE litigation payment; and the imposition of certain forward-looking procedural protections, including audit rights for retail regulators of the Unit Power Sales Agreement formula rates. The APSC, the MPSC, and the City Council intervened in the proceeding.

In June 2018, System Energy and Entergy Services filed a motion to dismiss and an answer to the LPSC complaint denying that System Energy’s treatment of the sale-leaseback renewal and capital additions violated the terms of the filed rate or any other FERC ratemaking, accounting, or legal requirements or otherwise constituted double recovery. The response also argued that the complaint was inconsistent with a FERC-approved settlement to which the LPSC is a party and that explicitly authorized System Energy to recover its lease payments. Finally, the response argued that both the capital additions and the sale-leaseback renewal were prudent investments and the LPSC complaint failed to justify any disallowance or refunds. The response also offered to submit formula rate protocols for the Unit Power Sales Agreement similar to the procedures used for reviewing transmission rates under the MISO tariff. In September 2018 the FERC issued an order setting the complaint for hearing and settlement proceedings and establishing a refund effective date of May 18, 2018.

In February 2019 the presiding ALJ ruled that the hearing ordered by the FERC includes the issue of whether specific subcategories of accumulated deferred income tax should be included in, or excluded from, System Energy’s formula rate. Testimony was filed by the LPSC, the MPSC, the APSC, the City Council, the FERC trial staff, and System Energy between March 2019 and October 2019. The final positions of the parties, after all pre-filed testimony was submitted, were as follows. The LPSC sought refunds that included the renewal lease payments (approximately $17.2 million per year since July 2015), rate base reductions for accumulated deferred income tax associated with uncertain tax positions (with a corresponding refund of approximately $512 million), and the cost of capital additions associated with the sale-leaseback interest, as well as interest on those amounts. The LPSC also argued that adjustments to depreciation rates should require retroactive depreciation expense refunds but only prospective rate base adjustments. The APSC, the MPSC, and the City Council generally agreed with the LPSC’s positions. The FERC trial staff argued for refunds for rate base reductions for liabilities associated with uncertain tax positions, and also argued that System Energy recovered $32 million more than it should have in depreciation expense for capital additions. System Energy filed testimony asking the FERC to reject all of the LPSC’s claims for refunds and opposing the FERC trial staff’s position regarding the uncertain tax position issue. System Energy also argued that the FERC trial staff’s position regarding depreciation rates for capital additions was not unreasonable, but any change in depreciation expense is only one element of a Unit Power Sales Agreement re-billing calculation. Adjustments to depreciation expense in any re-billing under the Unit Power Sales Agreement formula rate would also involve changes to accumulated depreciation, accumulated deferred income taxes, and other formula elements as needed.

After holding a hearing in November 2019, in April 2020 the FERC ALJ issued the initial decision. Among other things, the ALJ determined that refunds were due on three main issues. First, with regard to the lease renewal payments, the ALJ determined that System Energy was recovering an unjust acquisition premium through the lease renewal payments, and that System Energy’s recovery from customers through rates should be limited to the cost of service based on the remaining net book value of the leased assets, which was approximately $70 million. The ALJ found that the remedy for this issue should be the refund of lease payments (approximately $17.2 million per year since July 2015) with interest determined at the FERC quarterly interest rate, which would be offset by the addition
of the net book value of the leased assets in the cost of service. The ALJ did not calculate a value for the refund expected as a result of this remedy. In addition, System Energy would no longer recover the lease payments in rates prospectively. Second, with regard to the liabilities associated with uncertain tax positions, the ALJ determined that the liabilities are accumulated deferred income taxes and that System Energy’s rate base should have been reduced for those liabilities. The ALJ also found that System Energy should include liabilities associated with uncertain tax positions as a rate base reduction going forward. Third, with regard to the depreciation expense adjustments, the ALJ found that System Energy should correct for the error in re-billings retroactively and prospectively, but that System Energy should not be permitted to recover interest on any retroactive return on enhanced rate base resulting from such corrections.

In June 2020, System Energy, the LPSC, and the FERC trial staff filed briefs on exceptions, challenging several of the initial decision’s findings. System Energy’s brief on exceptions challenged the initial decision’s limitations on recovery of the lease renewal payments, its proposed rate base refund for the liabilities associated with uncertain tax positions, and its proposal to asymmetrically treat interest on bill corrections for depreciation expense adjustments. The LPSC’s and the FERC trial staff’s briefs on exceptions each challenged the initial decision’s allowance for recovery of the cost of service associated with the lease renewal based on the remaining net book value of the leased assets, its calculation of the remaining net book value of the leased assets, and the amount of the initial decision’s proposed rate base refund for the liabilities associated with uncertain tax positions. The LPSC’s brief on exceptions also challenged the initial decision’s proposal that depreciation expense adjustments include retroactive adjustments to rate base and its finding that section 203 of the Federal Power Act did not apply to the lease renewal. The FERC trial staff’s brief on exceptions also challenged the initial decision’s finding that the FERC need not institute a formal investigation into System Energy’s tariff. In October 2020, System Energy, the LPSC, the MPSC, the APSC, and the City Council filed briefs opposing exceptions. System Energy opposed the exceptions filed by the LPSC and the FERC trial staff. The LPSC, the MPSC, the APSC, the City Council, and the FERC trial staff opposed the exceptions filed by System Energy. Also in October 2020 the MPSC, the APSC, and the City Council filed briefs adopting the exceptions of the LPSC and the FERC trial staff.

In addition, in September 2020, the IRS issued a Notice of Proposed Adjustment (NOPA) and Entergy executed it. The NOPA memorialized the IRS’s decision to adjust the 2015 consolidated federal income tax return of Entergy Corporation and certain of its subsidiaries, including System Energy, with regard to the uncertain decommissioning tax position. Pursuant to the audit resolution documented in the NOPA, the IRS allowed System Energy’s inclusion of $102 million of future nuclear decommissioning costs in System Energy’s cost of goods sold for the 2015 tax year, roughly 10% of the requested deduction, but disallowed the balance of the position. In September 2020, System Energy filed a motion to lodge the NOPA into the record in the FERC proceeding. In October 2020 the LPSC, the APSC, the MPSC, the City Council, and the FERC trial staff filed oppositions to System Energy’s motion. As a result of the NOPA issued by the IRS in September 2020, System Energy filed, in October 2020, a new Federal Power Act section 205 filing at FERC to establish an ongoing rate base credit for the accumulated deferred income taxes resulting from the decommissioning uncertain tax position. On a prospective basis beginning with the October 2020 bill, System Energy proposed to include the accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position as a credit to rate base under the Unit Power Sales Agreement. In November 2020 the LPSC, the APSC, the MPSC, and the City Council filed a protest to the filing, and System Energy responded.

In November 2020 the IRS issued a Revenue Agent’s Report (RAR) for the 2014/2015 tax year and in December 2020 Entergy executed it. The RAR contained the same adjustment to the uncertain nuclear decommissioning tax position as that which the IRS had announced in the NOPA. In December 2020, System Energy filed a motion to lodge the RAR into the record in the FERC proceeding addressing the uncertain tax position rate base issue. In January 2021 the LPSC, the APSC, the MPSC, and the City Council filed a protest to the motion.

As a result of the RAR, in December 2020, System Energy filed amendments to its new Federal Power Act section 205 filings to establish an ongoing rate base credit for the accumulated deferred income taxes resulting from
the decommissioning uncertain tax position and to credit excess accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position. The amendments both proposed the inclusion of the RAR as support for the filings. In December 2020 the LPSC, the APSC, and the City Council filed protests to the amendments. In February 2021 the FERC issued an order accepting System Energy’s Federal Power Act section 205 filings subject to refund, setting them for hearing, and holding the hearing in abeyance.

In December 2020, System Energy filed a new Federal Power Act section 205 filing to provide a one-time, historical credit of $25.2 million for the accumulated deferred income taxes that would have been created by the decommissioning uncertain tax position if the IRS’s decision had been known in 2016. In January 2021 the LPSC, APSC, MPSC, and City Council filed a protest to the filing. In February 2021 the FERC issued an order accepting System Energy’s Federal Power Act section 205 filing subject to refund, setting it for hearing, and holding the hearing in abeyance. System Energy provided the one-time credit during the first quarter 2021.

In December 2022 the FERC issued an order on the ALJ’s initial decision, which affirmed it in part and modified it in part. The FERC’s order directed System Energy to calculate refunds on three issues, and to provide a compliance report detailing the calculations. The FERC’s order also disallowed the future recovery of sale-leaseback renewal costs, which is estimated at approximately $11.5 million annually for purchases from Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans through July 2036. The three refund issues were rental expenses related to the renewal of the sale-leaseback arrangements; refunds, if any, for the revenue requirement impact of including accumulated deferred income taxes resulting from the decommissioning uncertain tax positions from 2004 through the present; and refunds for the net effect of correcting the depreciation inputs for capital additions attributable to the portion of plant subject to the sale-leaseback.

As a result of the FERC order’s directives regarding the recovery of the sale-leaseback transaction, in December 2022 System Energy reduced the Grand Gulf sale-leaseback regulatory liability by $56 million, reduced the related accumulated deferred income tax asset by $94 million, and reduced the Grand Gulf sale-leaseback accumulated deferred income tax regulatory liability by $25 million, resulting in an increase in income tax expense of $13 million. In addition, the FERC determined that System Energy recognized excess depreciation expense related to property subject to the sale-leaseback. As a result, in December 2022, System Energy recorded a reduction in depreciation expense and the related accumulated depreciation of $33 million.

In January 2023, System Energy filed its compliance report with the FERC. With respect to the sale-leaseback renewal costs, System Energy calculated a refund of $89.8 million, which represented all of the sale-leaseback renewal rental costs that System Energy recovered in rates, with interest. With respect to the decommissioning uncertain tax position issue, System Energy calculated that no additional refunds were owed because it had already provided a one-time historical credit (for the period January 2016 through September 2020) of $25.2 million based on the accumulated deferred income taxes that resulted from the IRS’s partial acceptance of the decommissioning tax position, and because it has been providing an ongoing rate base credit for the accumulated deferred income taxes that resulted from the IRS’s partial acceptance of the decommissioning tax position since October 2020. With respect to the depreciation refund, System Energy calculated a refund of $13.7 million, which is the net total of a refund to customers for excess depreciation expense previously collected, plus interest, offset by the additional return on rate base that System Energy previously did not collect, without interest. See “System Energy Settlement with the MPSC” below for discussion of the regulatory charge and corresponding regulatory liability recorded in June 2022 related to these proceedings. In January 2023, System Energy paid the refunds of $103.5 million, which included refunds of $41.7 million to Entergy Arkansas, $27.8 million to Entergy Louisiana, and $34 million to Entergy New Orleans.

In February 2023 the LPSC, the APSC, and the City Council filed protests to System Energy’s January 2023 compliance report, in which they challenged System Energy’s calculation of the refunds associated with the decommissioning tax position but did not protest the other components of the compliance report. Each of them argued that System Energy should have paid additional refunds for the decommissioning tax position issue, and the City Council estimated the total additional refunds owed to customers of Entergy Louisiana, Entergy New Orleans,
and Entergy Arkansas for that issue as $493 million, including interest (and without factoring in the $25.2 million refund that System Energy already paid in 2021).

In January 2023, System Energy filed a request for rehearing of the FERC’s determinations in the December 2022 order on sale-leaseback refund issues and future lease cost disallowances, the FERC’s prospective policy on uncertain tax positions, and the proper accounting of System Energy’s accumulated deferred income taxes adjustment for the Tax Cuts and Jobs Act of 2017; and a motion for confirmation of its interpretation of the December 2022 order’s remedy concerning the decommissioning tax position. In January 2023 the retail regulators filed a motion for confirmation of their interpretation of the refund requirement in the December 2022 FERC order and a provisional request for rehearing. In February 2023 the FERC issued a notice that the rehearing requests were denied by operation of law. In March 2023, System Energy filed in the United States Court of Appeals for the Fifth Circuit a petition for review of the December 2022 order. In March 2023, System Energy also filed an unopposed motion to stay the proceeding in the Fifth Circuit pending the FERC’s disposition of the pending motions, and the court granted the motion to stay.

In February 2023, System Energy submitted a tariff compliance filing with the FERC to clarify that, consistent with the releases provided in the MPSC settlement, Entergy Mississippi will continue to be charged for its allocation of the sale-leaseback renewal costs under the Unit Power Sales Agreement. See “System Energy Settlement with the MPSC” below for discussion of the settlement. In March 2023 the MPSC filed a protest to System Energy’s tariff compliance filing. The MPSC argues that the settlement did not specifically address post-settlement sale-leaseback renewal costs and that the sale-leaseback renewal costs may not be recovered under the Unit Power Sales Agreement. Entergy Mississippi’s allocated sale-leaseback renewal costs are estimated at $5.7 million annually for the remaining term of the sale-leaseback renewal.

In August 2023 the FERC issued an order addressing arguments raised on rehearing and partially setting aside the prior order (rehearing order). The rehearing order addressed rehearing requests that were filed in January 2023 separately by System Energy and the LPSC, the APSC, and the City Council.

In the rehearing order, the FERC directed System Energy to recalculate refunds for two issues: (1) refunds of rental expenses related to the renewal of the sale-leaseback arrangements and (2) refunds for the net effect of correcting the depreciation inputs for capital additions associated with the sale-leaseback. With regard to the sale-leaseback renewal rental expenses, the rehearing order allowed System Energy to recover an implied return of and on the depreciated cost of the portion of the plant subject to the sale-leaseback as of the expiration of the initial lease term. With regard to the depreciation input issue, the rehearing order allowed System Energy to offset refunds so that System Energy may collect interest on the rate base recalculations that were part of the overall depreciation rate recalculations. The rehearing order further directed System Energy to submit within 60 days of the date of the rehearing order an additional compliance filing to revise the total refunds for these two issues. As discussed above, System Energy’s January 2023 compliance filing calculated $103.5 million in total refunds, and the refunds were paid in January 2023. In October 2023, System Energy filed its compliance report with the FERC as directed in the August 2023 rehearing order. The October 2023 compliance report reflected recalculated refunds totaling $35.7 million for the two issues resulting in $67.8 million in refunds that could be recouped by System Energy. As discussed below in “System Energy Settlement with the APSC,” System Energy reached a settlement in principle with the APSC to resolve several pending cases under the FERC’s jurisdiction, including this one, pursuant to which it agreed not to recoup the $27.3 million calculated for Entergy Arkansas in the compliance filing. As a result of the FERC’s rulings on the sale-leaseback and depreciation input issues in the August 2023 rehearing order, in third quarter 2023, System Energy recorded a regulatory asset and corresponding regulatory credit of $40 million to reflect the portion of the January 2023 refunds to be recouped from Entergy Louisiana and Entergy New Orleans. Consistent with the compliance filing, in October 2023, Entergy Louisiana and Entergy New Orleans paid recoupment amounts of $18.2 million and $22.3 million, respectively, to System Energy.
On the third refund issue identified in the rehearing requests, concerning the decommissioning uncertain tax positions, the rehearing order denied all rehearing requests, re-affirmed the remedy contained in the December 2022 order, and did not direct System Energy to recalculate refunds or to submit an additional compliance filing.

In September 2023, System Energy filed a protective appeal of the rehearing order with the United States Court of Appeals for the Fifth Circuit. The appeal was consolidated with System Energy’s prior appeal of the December 2022 order.

In September 2023 the LPSC filed with the FERC a request for rehearing and clarification of the rehearing order. The LPSC requested that the FERC reverse its determination in the rehearing order that System Energy may collect an implied return of and on the depreciated cost of the portion of the plant subject to the sale-leaseback, as of the expiration of the initial lease term, as well as its determination in the rehearing order that System Energy may offset the refunds for the depreciation rate input issue and collect interest on the rate base recalculations that were part of the overall depreciation rate recalculations. In addition, the LPSC requested that the FERC either confirm the LPSC’s interpretation of the refund associated with the decommissioning uncertain tax positions or explain why it is not doing so. In October 2023 the FERC issued a notice that the rehearing request was deemed denied by operation of law. In November 2023 the FERC issued a further notice stating that it would not issue any further order addressing the rehearing request. Also in November 2023 the LPSC filed with the United States Court of Appeals for the Fifth Circuit a petition for review of the FERC’s August 2023 rehearing order and denials of the September 2023 rehearing request.

In December 2023 the United States Court of Appeals for the Fifth Circuit lifted the abeyance on the consolidated System Energy appeals and it also consolidated the LPSC’s appeal with the System Energy appeals. Briefing of the appeals occurred between March 2024 and July 2024. In September 2024 the parties filed a joint motion to continue and stay oral argument, previously scheduled for October 2024, pending the FERC’s decision whether to approve the settlement between System Energy and the LPSC, and the United States Court of Appeals for the Fifth Circuit granted the motion. In November 2024, after the FERC issued the order approving the settlement between System Energy and the LPSC, System Energy, the LPSC, the APSC, and the FERC filed a joint stipulation to dismiss the pending appeals, which the United States Court of Appeals for the Fifth Circuit granted.

As discussed below in “System Energy Settlement with the MPSC,” “System Energy Settlement with the APSC,” “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the MPSC, the APSC, the City Council, and the LPSC have settled their claims related to this proceeding.

LPSC Additional Complaints

In May 2020 the LPSC authorized its staff to file additional complaints at the FERC related to the rates charged by System Energy for Grand Gulf energy and capacity supplied to Entergy Louisiana under the Unit Power Sales Agreement. The LPSC directive noted that the initial decision issued by the presiding ALJ in the Grand Gulf sale-leaseback complaint proceeding did not address, for procedural reasons, certain rate issues raised by the LPSC and declined to order further investigation of rates charged by System Energy.

Unit Power Sales Agreement Complaint

The first of the additional complaints was filed by the LPSC, the APSC, the MPSC, and the City Council in September 2020. The first complaint raised two sets of rate allegations: violations of the filed rate and a corresponding request for refunds for prior periods; and elements of the Unit Power Sales Agreement are unjust and unreasonable and a corresponding request for refunds for the 15-month refund period and changes to the Unit Power Sales Agreement prospectively. Several of the filed rate allegations overlapped with the previous complaints. The filed rate allegations not previously raised were that System Energy: failed to provide a rate base credit to customers for the “time value” of sale-leaseback lease payments collected from customers in advance of the time those payments were due to the owner-lessors; improperly included certain sale-leaseback transaction costs in rate base as
prepayments; improperly included nuclear refueling outage costs in rate base; wrongly included categories of accumulated deferred income taxes as increases to rate base; charged customers based on a higher equity ratio than would be appropriate due to excessive retained earnings; and did not correctly reflect money pool investments and imprudently invested cash into the money pool. The elements of the Unit Power Sales Agreement that the complaint alleged were unjust and unreasonable include: the current cash working capital allowance of zero, uncapped recovery of incentive and executive compensation, lack of an equity re-opener, and recovery of lobbying and private airplane travel expenses. The complaint also requested a rate investigation into the Unit Power Sales Agreement and System Energy’s billing practices pursuant to section 206 of the Federal Power Act, including any issue relevant to the Unit Power Sales Agreement and its inputs. System Energy filed its answer opposing the complaint in November 2020. In its answer, System Energy argued that all of the claims raised in the complaint should be dismissed and agreed that bill adjustment with respect to two discrete issues were justified. System Energy argued that dismissal was warranted because all claims fell into one or more of the following categories: the claims had been raised and were being litigated in another proceeding; the claims did not present a prima facie case and did not satisfy the threshold burden to establish a complaint proceeding; the claims were premised on a theory or request relief that is incompatible with federal law or FERC policy; the claims request relief that is inconsistent with the filed rate; the claims were barred or waived by the legal doctrine of laches; and/or the claims had been fully addressed and do not warrant further litigation. In December 2020, System Energy filed a bill adjustment report indicating that $3.4 million had been credited to customers in connection with the two discrete issues concerning the inclusion of certain accumulated deferred income taxes balances in rates.

In May 2021 the FERC issued an order addressing the complaint, establishing a refund effective date of September 21, 2020, establishing hearing procedures, and holding those procedures in abeyance pending the FERC’s review of the initial decision in the Grand Gulf sale-leaseback renewal complaint discussed above. System Energy agreed that the hearing should be held in abeyance but sought rehearing of FERC’s decision as related to matters set for hearing that were beyond the scope of FERC’s jurisdiction or authority. The complainants sought rehearing of FERC’s decision to hold the hearing in abeyance and filed a motion to proceed, which motion System Energy opposed. In June 2021, System Energy’s request for rehearing was denied by operation of law, and System Energy filed an appeal of FERC’s orders in the Court of Appeals for the Fifth Circuit. In November 2021 the Fifth Circuit dismissed the appeal as premature.

In August 2021 the FERC issued an order addressing System Energy’s and the complainants’ rehearing requests. The FERC dismissed part of the complaint seeking an equity re-opener, maintained the abeyance for issues related to the proceeding addressing the sale-leaseback renewal and uncertain tax positions, lifted the abeyance for issues unrelated to that proceeding, and clarified the scope of the hearing.

In November 2021 the LPSC, the APSC, and the City Council filed direct testimony and requested the FERC to order refunds for prior periods and prospective amendments to the Unit Power Sales Agreement. The LPSC’s refund claims included, among other things, allegations that: (1) System Energy should not have included certain sale-leaseback transaction costs in prepayments; (2) System Energy should have credited rate base to reflect the time value of money associated with the advance collection of lease payments; (3) System Energy incorrectly included refueling outage costs that were recorded in account 174 in rate base; and (4) System Energy should have excluded several accumulated deferred income tax balances in account 190 from rate base. The LPSC also sought a retroactive adjustment to retained earnings and capital structure in conjunction with the implementation of its proposed refunds. In addition, the LPSC sought amendments to the Unit Power Sales Agreement going forward to address below-the-line costs, incentive compensation, the working capital allowance, litigation expenses, and the 2019 termination of the capital funds agreement. The APSC argued that: (1) System Energy should have included borrowings from the Entergy system money pool in its determination of short-term debt in its cost of capital; and (2) System Energy should credit customers with System Energy’s allocation of earnings on money pool investments. The City Council alleged that System Energy has maintained excess cash on hand in the money pool and that retention of excess cash was imprudent. Based on this allegation, the City Council’s witness recommended a refund of approximately $98.8 million for the period 2004-September 2021 or other alternative relief. The City Council
further recommended that the FERC impose a hypothetical equity ratio such as 48.15% equity to capital on a prospective basis.

In January 2022, System Energy filed answering testimony arguing that the FERC should not order refunds for prior periods or any prospective amendments to the Unit Power Sales Agreement. In response to the LPSC’s refund claims, System Energy argued, among other things, that: (1) the inclusion of sale-leaseback transaction costs in prepayments was correct; (2) that the filed rate doctrine bars the request for a retroactive credit to rate base for the time value of money associated with the advance collection of lease payments; (3) that an accounting misclassification for deferred refueling outage costs had been corrected, caused no harm to customers, and requires no refunds; and (4) that its accounting and ratemaking treatment of specified accumulated deferred income tax balances in account 190 had been correct. System Energy further responded that no retroactive adjustment to retained earnings or capital structure should be ordered because there was no general policy requiring such a remedy, and there was no showing that the retained earnings element of the capital structure was incorrectly implemented. Further, System Energy presented evidence that all of the costs that were being challenged were long known to the retail regulators and were approved by them for inclusion in retail rates, and the attempt to retroactively challenge these costs, some of which had been included in rates for decades, was unjust and unreasonable. In response to the LPSC’s proposed going-forward adjustments, System Energy presented evidence to show that none of the proposed adjustments were needed. On the issue of below-the-line expenses, during discovery procedures System Energy identified a historical allocation error in certain months and agreed to provide a bill credit to customers to correct the error. In response to the APSC’s claims, System Energy argued that the Unit Power Sales Agreement did not include System Energy’s borrowings from the Entergy system money pool or earnings on deposits to the Entergy system money pool in the determination of the cost of capital; and accordingly, no refunds were appropriate on those issues. In response to the City Council’s claims, System Energy argued that it has reasonably managed its cash and that the City Council’s theory of cash management was defective because it failed to adequately consider the relevant cash needs of System Energy and it made faulty presumptions about the operation of the Entergy system money pool. System Energy further pointed out that the issue of its capital structure was already subject to pending FERC litigation.

In March 2022 the FERC trial staff filed direct and answering testimony in response to the LPSC, the APSC, and the City Council’s direct testimony. In its testimony, the FERC trial staff recommended refunds for two primary reasons: (1) it concluded that System Energy should have excluded specified accumulated deferred income tax balances in account 190 associated with rate refunds; and (2) it concluded that System Energy should have excluded specified accumulated deferred income tax balances in account 190 associated with a deemed contract satisfaction and reissuance that occurred in 2005. The FERC trial staff recommended refunds of $84.1 million, exclusive of any tax gross-up or FERC interest. In addition, the FERC trial staff recommended the following prospective modifications to the Unit Power Sales Agreement: (1) inclusion of a rate base credit to recognize the time value of money associated with the advance collection of lease payments; (2) exclusion of executive incentive compensation costs for members of the Office of the Chief Executive and long-term performance unit costs where awards are based solely or primarily on financial metrics; and (3) exclusion of unvested, accrued amounts for stock options, performance units, and restricted stock awards. With respect to issues that ultimately concerned the reasonableness of System Energy’s rate of return, the FERC trial staff stated that it was unnecessary to consider such issues in the proceeding, in light of the pending case concerning System Energy’s return on equity and capital structure. On all other material issues raised by the LPSC, the APSC, and the City Council, the FERC trial staff recommended either no refunds or no modification to the Unit Power Sales Agreement.

In April 2022, System Energy filed cross-answering testimony in response to the FERC trial staff’s recommendations of refunds for the accumulated deferred income taxes issues and proposed modifications to the Unit Power Sales Agreement for the executive incentive compensation issues. In June 2022 the FERC trial staff submitted revised answering testimony, in which it recommended additional refunds associated with the accumulated deferred income tax balances in account 190 associated with a deemed contract satisfaction and reissuance that occurred in 2005. Based on the testimony revisions, the FERC trial staff’s recommended refunds total $106.6 million, exclusive of any tax gross-up or FERC awarded interest. Also in June 2022, System Energy
filed revised and supplemental cross-answering testimony to respond to the FERC trial staff’s testimony and oppose its revised recommendation.

In May 2022 the LPSC, the APSC, and the City Council filed rebuttal testimony. The LPSC’s testimony asserted new claims, including that: (1) certain of the sale-leaseback transaction costs may have been imprudently incurred; (2) accumulated deferred income taxes associated with sale-leaseback transaction costs should have been included in rate base; (3) accumulated deferred income taxes associated with federal investment tax credits should have been excluded from rate base; (4) monthly net operating loss accumulated deferred income taxes should have been excluded from rate base; and (5) several categories of proposed rate changes, including executive incentive compensation, air travel, industry dues, and legal costs, also warranted historical refunds. The LPSC’s rebuttal testimony argued that refunds for the alleged tariff violations and other claims must be calculated by rerunning the Unit Power Sales Agreement formula rate; however, it included estimates of refunds associated with some, but not all, of its claims, totaling $286 million without interest. The City Council’s rebuttal testimony also proposed a new, alternate theory and claim for relief regarding System Energy’s participation in the Entergy system money pool, under which it calculates estimated refunds of approximately $51.7 million. The APSC’s rebuttal testimony agreed with the LPSC’s direct testimony that retained earnings should be adjusted in a comprehensive refund calculation. The testimony quantified the estimated impacts of three issues: (1) a $1.5 million reduction in the revenue requirement under the Unit Power Sales Agreement if System Energy’s borrowings from the money pool were included in short-term debt; (2) a $1.9 million reduction in the revenue requirement if System Energy’s allocated share of money pool earnings were credited through the Unit Power Sales Agreement; and (3) a $1.9 million reduction in the revenue requirement for every $50 million of refunds ordered in a given year, without interest. In total, excluding the settled issues noted below, the claims sought more than $700 million in refunds and interest, based on charges to all Unit Power Sales Agreement purchasers including Entergy Mississippi. The hearing before a FERC ALJ occurred between September and December 2022.

In November 2022, System Energy filed a partial settlement agreement with the APSC, the City Council, and the LPSC that resolved the following issues raised in the Unit Power Sales Agreement complaint: advance collection of lease payments, aircraft costs, executive incentive compensation, money pool borrowings, advertising expenses, deferred nuclear refueling outage costs, industry association dues, and termination of the capital funds agreement. The settlement provided that System Energy would provide a black box refund of $18 million (inclusive of interest), plus additional refund amounts with interest to be calculated for certain issues to be distributed to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans as the Utility operating companies other than Entergy Mississippi purchasing under the Unit Power Sales Agreement. The settlement further provided that if the APSC, the City Council, or the LPSC agreed to the global settlement System Energy entered into with the MPSC (discussed below), and such global settlement included a black box refund amount, then the black box refund for this settlement agreement would not be incremental or in addition to the global black box refund amount. The settlement agreement addressed other matters as well, including adjustments to rate base beginning in October 2022, exclusion of certain other costs, and inclusion of money pool borrowings, if any, in short-term debt within the cost of capital calculation used in the Unit Power Sales Agreement. In April 2023 the FERC approved the settlement agreement. The refund provided for in the settlement agreement was included in the May 2023 service month bills under the Unit Power Sales Agreement.

In May 2023 the presiding ALJ issued an initial decision finding that System Energy should have excluded multiple identified categories of accumulated deferred income taxes from rate base when calculating Unit Power Sales Agreement bills. The initial decision also found that the Unit Power Sales Agreement should be modified such that a cash working capital allowance of negative $36.4 million is applied prospectively. On the other non-settled issues for which the complainants sought refunds or changes to the Unit Power Sales Agreement, the initial decision ruled against the complainants.

System Energy disagreed with the ALJ’s findings concerning the accumulated deferred income taxes issues and cash working capital. In July 2023, System Energy filed a brief on exceptions to the initial decision’s accumulated deferred income taxes findings. Also in July 2023, the APSC, the LPSC, the City Council, and the
FERC trial staff filed separate briefs on exceptions. In August 2023 all parties filed separate briefs opposing exceptions.

As discussed below in “System Energy Settlement with the MPSC,” “System Energy Settlement with the APSC,” and “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the MPSC, the APSC, and the City Council, and the LPSC have settled their claims related to this proceeding.

Grand Gulf Prudence Complaints

The second of the additional complaints was filed at the FERC in March 2021 by the LPSC, the APSC, and the City Council against System Energy, Entergy Services, Entergy Operations, and Entergy Corporation. The second complaint contained two primary allegations. First, it alleged that, based on the plant’s capacity factor and alleged safety performance, System Energy and the other respondents imprudently operated Grand Gulf during the period 2016-2020, and it sought refunds of at least $360 million in alleged replacement energy costs, in addition to other costs, including those that could only be identified upon further investigation. Second, it alleged that the performance and/or management of the 2012 extended power uprate of Grand Gulf was imprudent, and it sought refunds of all costs of the 2012 uprate that were determined to result from imprudent planning or management of the project. In addition to the requested refunds, the complaint asked that the FERC modify the Unit Power Sales Agreement to provide for full cost recovery only if certain performance indicators were met and to require pre-authorization of capital improvement projects in excess of $125 million before related costs could be passed through to customers in rates. In April 2021, System Energy and the other respondents filed their motion to dismiss and answer to the complaint. System Energy requested that the FERC dismiss the claims within the complaint. With respect to the claim concerning operations, System Energy argued that the complaint did not meet its legal burden because, among other reasons, it failed to allege any specific imprudent conduct. With respect to the claim concerning the uprate, System Energy argued that the complaint failed because, among other reasons, the complainants’ own conduct prevented them from raising a serious doubt as to the prudence of the uprate. System Energy also requested that the FERC dismiss other elements of the complaint, including the proposed modifications to the Unit Power Sales Agreement, because they were not warranted. In February 2023 the FERC issued an order denying rehearing and thereby affirming its order setting the complaint for settlement and hearing procedures. In July 2023 the FERC chief ALJ terminated settlement procedures and appointed a presiding ALJ to oversee hearing procedures. In September 2023 a procedural schedule for hearing procedures was established. Also in September 2023 the LPSC authorized its staff to file an additional complaint concerning the prudence of System Energy’s operation and management of Grand Gulf in the year 2022. In October 2023 the LPSC, the APSC, and the City Council filed what they styled as an amended and supplemental complaint with the FERC against System Energy, Entergy Services, and Entergy Operations. In November 2023, System Energy answered the amended and supplemental complaint. Pursuant to the procedural schedule, the complainants’ testimony in the original complaint proceeding was filed in December 2023. System Energy’s answering testimony was filed in May 2024, and the FERC trial staff’s direct and answering testimony was filed in June 2024.

As discussed below in “System Energy Settlement with the APSC,” “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the APSC, the City Council, and the LPSC have settled all of their claims related to this proceeding.

System Energy Settlement with the MPSC

In June 2022, System Energy, Entergy Mississippi, and additional named Entergy parties involved in thirteen docketed proceedings before the FERC filed with the FERC a partial settlement agreement and offer of settlement. The settlement memorialized the Entergy parties’ agreement with the MPSC to globally resolve all actual and potential claims between the Entergy parties and the MPSC associated with those FERC proceedings and with System Energy’s past implementation of the Unit Power Sales Agreement. The Unit Power Sales Agreement is a FERC-jurisdictional formula rate tariff for sales of energy and capacity from System Energy’s owned and
leased share of Grand Gulf to Entergy Mississippi, Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans. Entergy Mississippi purchases the greatest single amount, nearly 40% of System Energy’s share of Grand Gulf, after its additional purchases from affiliates are considered.

The settlement provided for a black box refund of $235 million from System Energy to Entergy Mississippi. In addition, beginning with the July 2022 service month, the settlement provided for Entergy Mississippi’s bills from System Energy to be adjusted to reflect: an authorized rate of return on equity of 9.65%, a capital structure not to exceed 52% equity, a rate base reduction for the advance collection of sale-leaseback rental costs, and the exclusion of certain long-term incentive plan performance unit costs from rates. The settlement was approved by the MPSC in June 2022 and the FERC in November 2022.

System Energy had previously recorded a provision and associated liability of $37 million for elements of the applicable litigation. In June 2022, System Energy recorded a regulatory charge of $551 million ($413 million net-of-tax), increasing the regulatory liability to $588 million, which consisted of $235 million for the settlement with the MPSC and $353 million for potential future refunds to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans. System Energy paid the black box refund of $235 million to Entergy Mississippi in November 2022.

System Energy Settlement with the APSC

In October 2023, System Energy, Entergy Arkansas, and additional named Entergy parties involved in multiple docketed proceedings pending before the FERC reached a settlement in principle with the APSC to globally resolve all of their actual and potential claims in those dockets and with System Energy’s past implementation of the Unit Power Sales Agreement. The settlement also covered the amended and supplemental complaint, discussed above in “Grand Gulf Prudence Complaint,” filed at the FERC in October 2023. System Energy, Entergy Arkansas, additional Entergy parties, and the APSC filed the settlement agreement and supporting materials with the FERC in November 2023.

The terms of the settlement with the APSC aligned with the $588 million global black box settlement reached between System Energy and the MPSC in June 2022 and provided for Entergy Arkansas to receive a black box refund of $142 million from System Energy, inclusive of $49.5 million already received by Entergy Arkansas from System Energy. In addition, beginning with the November 2023 service month, the settlement provided for Entergy Arkansas’s bills from System Energy to be adjusted to reflect an authorized rate of return on equity of 9.65% and a capital structure not to exceed 52% equity. In March 2024 the FERC approved the settlement, and System Energy paid the remaining black box refund of $93 million to Entergy Arkansas in 2024.

System Energy Settlement with the City Council

In April 2024, System Energy, Entergy New Orleans, and additional named Entergy parties involved in multiple docketed proceedings pending before the FERC reached a settlement in principle with the City Council to globally resolve all of their actual and potential claims in those dockets and with System Energy’s past implementation of the Unit Power Sales Agreement. The settlement also covered the amended and supplemental complaint, discussed in “Grand Gulf Prudence Complaints” above, filed by the LPSC, the APSC, and the City Council at the FERC in October 2023. In May 2024, System Energy, Entergy New Orleans, additional named Entergy parties, and the City Council filed the settlement agreement and supporting materials with the FERC.

The terms of the settlement with the City Council aligned with the $588 million global black box settlement amount reflected in the prior settlements reached between System Energy and the MPSC in June 2022 and between System Energy and the APSC in November 2023. The settlement provided for Entergy New Orleans to receive a black box refund of $116 million from System Energy, inclusive of approximately $18 million already received by Entergy New Orleans from System Energy. In addition, beginning with the June 2024 service month, the settlement provided for Entergy New Orleans’s bills from System Energy to be adjusted to reflect an authorized rate of return on equity of 9.65% and a capital structure not to exceed 52% equity. In August 2024 the FERC approved the
settlement, and System Energy paid the remaining black box refund of $98 million to Entergy New Orleans in October 2024.

System Energy Settlement with the LPSC

In July 2024, System Energy and the LPSC staff reached a settlement in principle to globally resolve all of the LPSC’s actual and potential claims in multiple docketed proceedings pending before the FERC (including all docketed proceedings resolved by the MPSC, the APSC, and the City Council settlements) and with System Energy’s past implementation of the Unit Power Sales Agreement. The settlement also covered the amended and supplemental complaint, discussed above in “Grand Gulf Prudence Complaints,” filed by the LPSC, the APSC, and the City Council at the FERC in October 2023. In August 2024 the LPSC approved the settlement. In September 2024 the settling parties filed the settlement for approval by the FERC.

The terms of the settlement with the LPSC staff aligned with the $588 million global black box settlement amount reflected in the prior settlements reached between System Energy and the MPSC in June 2022, between System Energy and the APSC in November 2023, and between System Energy and the City Council in April 2024. The settlement in principle provided for Entergy Louisiana to receive a black box refund of $95 million from System Energy, inclusive of approximately $15 million already received by Entergy Louisiana from System Energy. In addition, beginning with the September 2024 service month, the settlement provided for Entergy Louisiana’s bills from System Energy to be adjusted to reflect an authorized rate of return on equity of 9.65% and a capital structure not to exceed 52% equity. In November 2024 the FERC approved the settlement, and System Energy paid the remaining black box refund of $80 million to Entergy Louisiana in December 2024.

The settlement also included an agreement that, subject to the receipt of necessary regulatory approvals, Entergy Louisiana will divest to Entergy Mississippi all of its interest in Grand Gulf capacity and energy under the Unit Power Sales Agreement and its purchases from Entergy Arkansas under the MSS-4 replacement tariff. In October 2024 Entergy Louisiana and Entergy Mississippi filed with the FERC a PPA under which Entergy Mississippi would purchase Entergy Louisiana’s purchases of Grand Gulf capacity and energy. The PPA is governed by the MSS-4 replacement tariff, a tariff governing the sales of energy and capacity among the Utility operating companies. The requisite approvals for the PPA were issued by the FERC in November 2024 and the MPSC in February 2025. The divestiture is effective as of January 1, 2025.

System Energy Regulatory Liability for Pending Complaints

Prior to June 2022, System Energy recorded a provision and associated liability of $37 million for elements of the complaints against System Energy. In June 2022, as discussed in “System Energy Settlement with the MPSC” above, System Energy recorded a regulatory charge of $551 million ($413 million net-of-tax), increasing System Energy’s regulatory liability to $588 million, which consisted of $235 million for the settlement with the MPSC and $353 million for potential future refunds to Entergy Arkansas, Entergy New Orleans, and Entergy Louisiana. System Energy paid the black box refund of $235 million to Entergy Mississippi in November 2022. As discussed above in “Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue,” in January 2023 System Energy paid refunds of $103.5 million as a result of the FERC’s order in December 2022 in that proceeding and recouped $40.5 million of the $103.5 million from Entergy Louisiana and Entergy New Orleans in October 2023. In addition, as discussed above in “Unit Power Sales Agreement Complaint,” a black box refund of $18 million was made by System Energy in 2023 in connection with a partial settlement in that proceeding. Based on analysis of the then-pending complaints against System Energy and potential future settlement negotiations with the LPSC and the City Council, in third quarter 2023, System Energy recorded a regulatory charge of $40 million to increase System Energy’s regulatory liability related to complaints against System Energy. In December 2023 the $93 million black box refund to Entergy Arkansas was reclassified from the regulatory liability to accounts payable - associated companies on System Energy’s balance sheet. System Energy paid the remaining black box refunds of $93 million to Entergy Arkansas, $98 million to Entergy New Orleans, and $80 million to Entergy Louisiana in 2024.
Unit Power Sales Agreement

System Energy Formula Rate Annual Protocols Formal Challenge Concerning 2020 Calendar Year Bills

System Energy’s Unit Power Sales Agreement includes formula rate protocols that provide for the disclosure of cost inputs, an opportunity for informal discovery procedures, and a challenge process. In February 2022, pursuant to the protocols procedures, the LPSC, the APSC, the MPSC, the City Council, and the Mississippi Public Utilities Staff filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2020. This formal challenge was ultimately settled as a result of System Energy’s global settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” above for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.

System Energy Formula Rate Annual Protocols Formal Challenge Concerning 2021 Calendar Year Bills

In March 2023, pursuant to the protocols procedures discussed above, the LPSC, the APSC, and the City Council filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2021. This formal challenge was ultimately settled as a result of System Energy’s global settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” above for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.

System Energy Formula Rate Annual Protocols Formal Challenge Concerning 2022 Calendar Year Bills

In February 2024, pursuant to the protocols procedures, the LPSC and the City Council filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2022. This formal challenge was ultimately settled as a result of System Energy’s global settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” above for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.

Depreciation Amendment Proceeding

In December 2021, System Energy submitted to the FERC proposed amendments to the Unit Power Sales Agreement to adopt updated rates for use in calculating Grand Gulf plant depreciation and amortization expenses. The proposed amendments would result in higher charges to the Utility operating companies that buy capacity and energy from System Energy under the Unit Power Sales Agreement. In February 2022 the FERC accepted System Energy’s proposed increased depreciation rates with an effective date of March 1, 2022, subject to refund pending the outcome of the settlement and/or hearing procedures. In June 2023 System Energy filed with the FERC an unopposed offer of settlement that it had negotiated with intervenors to the proceeding. In August 2023 the FERC approved the settlement, which resolves the proceeding. In third quarter 2023, System Energy recorded a reduction in depreciation expense of $41 million representing the cumulative difference in depreciation expense resulting from the depreciation rates used from March 2022 through June 2023 and the depreciation rates included in the settlement filing approved by the FERC. In October 2023, System Energy filed a refund report with the FERC. The refund provided for in the refund report was included in the September 2023 service month bills under the Unit Power Sales Agreement. No comments or protests to the refund report were filed.

Pension Costs Amendment Proceeding

In October 2021, System Energy submitted to the FERC proposed amendments to the Unit Power Sales Agreement to include in rate base the prepaid and accrued pension costs associated with System Energy’s qualified pension plans. Based on data ending in 2020, the increased annual revenue requirement associated with the filing is approximately $8.9 million. In March 2022 the FERC accepted System Energy’s proposed amendments with an
effective date of December 1, 2021, subject to refund pending the outcome of the settlement and/or hearing procedures. In August 2023 the FERC chief ALJ terminated settlement procedures and designated a presiding ALJ to oversee hearing procedures. Testimony was filed by the parties from October 2023 through April 2024, and the hearing concluded in June 2024.

In September 2024 the presiding ALJ issued an initial decision recommending that the FERC approve inclusion of a line item in rate base for prepaid and accrued pension costs; however, the presiding ALJ did not agree with System Energy’s proposed methodology to calculate the value of the prepaid and accrued pension cost input. Instead, the presiding ALJ recommended limiting System Energy’s recovery to the prepaid and accrued pension costs that were incurred beginning in 2015 and later.

System Energy disputes the presiding ALJ's determination concerning the methodology used to calculate the prepaid and accrued pension input, and System Energy filed exceptions to these rulings in October 2024. In October 2024, the LPSC, the APSC, and the FERC trial staff filed separate briefs on exceptions; these parties generally argue that the presiding ALJ should have rejected System Energy’s filing entirely, rather than limit System Energy’s recovery of the prepaid and accrued pension costs. Later in October 2024, System Energy, the LPSC, the APSC, and the FERC trial staff filed separate briefs opposing exceptions.

If the ALJ’s determination is affirmed by the FERC, System Energy estimates refunds, including interest through December 31, 2024, of approximately $16 million to $21 million would be owed. The ALJ's initial decision is not binding on the FERC and is an interim step in the hearing process. No refunds will be owed in connection with this proceeding and no changes to System Energy’s pension cost recovery methodology will be implemented unless and until the FERC requires them in a final order. This proceeding is not covered by the global settlements described above.
Storm Cost Recovery Filings with Retail Regulators

Entergy Louisiana

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.

In December 2024, and subsequently amended in an errata filed in February 2025, Entergy Louisiana submitted an application to the LPSC seeking a determination that approximately $183.6 million in storm restoration costs associated with Hurricane Francine were reasonable and necessary and, therefore, eligible for recovery from customers, as well as approval to recover approximately $3.6 million in certain carrying costs from customers. The $183.6 million includes approximately $152.8 million in distribution capital costs and approximately $29.8 million in non-capital costs; the balance consists of transmission and generation capital costs. Entergy Louisiana proposes in its application to recover its distribution-related capital costs of $152.8 million through the distribution recovery mechanism of its formula rate plan. Entergy Louisiana has further requested the LPSC to authorize recovery of these distribution-related capital expenses through an interim rate adjustment, subject to true-up and refund, that would begin with the first billing cycle of March 2025. Entergy Louisiana also requested to recover, from its storm reserve escrow account, $33.5 million, which consists of non-capital costs and certain carrying costs. Entergy Louisiana has also proposed to recover the transmission and generation capital costs through separate ratemaking proceedings. In February 2025, Entergy Louisiana withdrew the $33.5 million from its storm reserve escrow account. The period for intervention has expired, and a status conference for the purpose of establishing a procedural schedule has been set for March 2025.
Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida

In August 2020 and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of Entergy Louisiana’s service area. The storms resulted in widespread outages, significant damage to distribution and transmission infrastructure, and the loss of sales during the outages. Additionally, as a result of Hurricane Laura’s extensive damage to the grid infrastructure serving the impacted area, large portions of the underlying transmission system required nearly a complete rebuild.

In October 2020, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments in connection with the issuance of shorter-term mortgage bonds to provide interim financing for restoration costs associated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta. Subsequently, Entergy Louisiana and the LPSC staff filed a joint motion seeking approval to exclude from the derivation of Entergy Louisiana’s capital structure and cost rate of debt for ratemaking purposes, including the allowance for funds used during construction, shorter-term debt up to $1.1 billion issued by Entergy Louisiana to fund costs associated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta costs on an interim basis. In November 2020 the LPSC issued an order approving the joint motion, and Entergy Louisiana issued $1.1 billion of 0.62% Series mortgage bonds due November 2023. Also in November 2020, Entergy Louisiana withdrew $257 million from its funded storm reserves.

In February 2021 two winter storms (collectively, Winter Storm Uri) brought freezing rain and ice to Louisiana. Ice accumulation sagged or downed trees, limbs, and power lines, causing damage to Entergy Louisiana’s transmission and distribution systems. The additional weight of ice caused trees and limbs to fall into power lines and other electric equipment. When the ice melted, it affected vegetation and electrical equipment, causing additional outages. Entergy Louisiana recovered the incremental fuel costs associated with Winter Storm Uri over a five-month period from April 2021 through August 2021.

In April 2021, Entergy Louisiana filed an application with the LPSC relating to Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri restoration costs and in July 2021, Entergy Louisiana made a supplemental filing updating the total restoration costs. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by these storms were estimated to be approximately $2.06 billion, including approximately $1.68 billion in capital costs and approximately $380 million in non-capital costs. Including carrying costs through January 2022, Entergy Louisiana sought an LPSC determination that $2.11 billion was prudently incurred and, therefore, was eligible for recovery from customers. Additionally, Entergy Louisiana requested that the LPSC determine that re-establishment of a storm escrow account to the previously authorized amount of $290 million was appropriate. In July 2021, Entergy Louisiana supplemented the application with a request regarding the financing and recovery of the recoverable storm restoration costs. Specifically, Entergy Louisiana requested approval to securitize its restoration costs pursuant to Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021.

In August 2021, Hurricane Ida caused extensive damage to Entergy Louisiana’s distribution and, to a lesser extent, transmission systems resulting in widespread power outages. In September 2021, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments in connection with the issuance of approximately $1 billion of shorter-term mortgage bonds to provide interim financing for restoration costs associated with Hurricane Ida, which bonds were issued in October 2021. Also in September 2021, Entergy Louisiana sought approval for the creation and funding of a $1 billion restricted escrow account for Hurricane Ida related restoration costs, subject to a subsequent prudence review.

After filing of testimony by the LPSC staff and intervenors, which generally supported or did not oppose Entergy Louisiana’s requests in regard to Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida, the parties negotiated and executed an uncontested stipulated settlement which was filed with the LPSC in February 2022. The settlement agreement contained the following key terms: $2.1 billion of restoration costs from Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri were prudently incurred and
eligible for recovery; carrying costs of $51 million were recoverable; a $290 million cash storm reserve should be re-established; a $1 billion reserve should be established to partially pay for Hurricane Ida restoration costs; and Entergy Louisiana was authorized to finance $3.186 billion utilizing the securitization process authorized by Act 55, as supplemented by Act 293. The LPSC issued an order approving the settlement in March 2022. As a result of the financing order, Entergy Louisiana reclassified $1.942 billion from utility plant to other regulatory assets.

In May 2022 the securitization financing closed, resulting in the issuance of $3.194 billion principal amount of bonds by Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA), a political subdivision of the State of Louisiana. The securitization was authorized pursuant to the Louisiana Utilities Restoration Corporation Act, Part VIII of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana legislature approved in 2021. The LCDA loaned the proceeds to the LURC. Pursuant to Act 293, the LURC contributed the net bond proceeds to a State legislatively authorized and LURC-sponsored trust, Restoration Law Trust I (the storm trust I).

Pursuant to Act 293, the net proceeds of the bonds were used by the storm trust I to purchase 31,635,718.7221 Class A preferred, non-voting membership interest units (the preferred membership interests) issued by Entergy Finance Company. Entergy Finance Company is required to make annual distributions (dividends) commencing on December 15, 2022 on the preferred membership interests issued to the storm trust I. These annual dividends received by the storm trust I will be distributed to Entergy Louisiana and the LURC, as beneficiaries of the storm trust I. Specifically, 1% of the annual dividends received by the storm trust I will be distributed to the LURC, for the benefit of customers, and 99% will be distributed to Entergy Louisiana, net of storm trust expenses. The preferred membership interests have a stated annual cumulative cash dividend rate of 7% and a liquidation price of $100 per unit. The terms of the preferred membership interests include certain financial covenants to which Entergy Finance Company is subject. Semi-annual redemptions of the preferred membership interests, subject to certain conditions, are expected to occur over the next 15 years.

Entergy and Entergy Louisiana do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA. The bonds are secured by system restoration property, which is the right granted by law to the LURC to collect a system restoration charge from customers. The system restoration charge is adjusted at least semi-annually to ensure that it is sufficient to service the bonds. Entergy Louisiana collects the system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee. Entergy Louisiana began collecting the system restoration charge effective with the first billing cycle of June 2022 and the system restoration charge is expected to remain in place for up to 15 years. Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as a billing and collection agent for the LCDA and the LURC. In the remote possibility that the system restoration charge, as well as any funds in the excess subaccount and funds in the debt service reserve account, are insufficient to service the bonds resulting in a payment default, the storm trust I is required to liquidate Entergy Finance Company preferred membership interests in an amount equal to what would be required to cure the default. The estimated value of this indirect guarantee is immaterial.

From the proceeds from the issuance of the preferred membership interests, Entergy Finance Company distributed $1.4 billion to its parent, Entergy Holdings Company, LLC, a company wholly-owned and consolidated by Entergy. Subsequently, Entergy Holdings Company liquidated, distributing the $1.4 billion it received from Entergy Finance Company to Entergy Louisiana as holder of 6,843,780.24 units of Class A, 4,126,940.15 units of Class B, and 2,935,152.69 units of Class C preferred membership interests. Entergy Louisiana had acquired these preferred membership interests with proceeds from previous securitizations of storm restoration costs. Entergy Finance Company loaned the remaining $1.7 billion from the preferred membership interests proceeds to Entergy which used the cash to redeem $650 million of 4.00% Series senior notes due July 2022 and indirectly contributed $1 billion to Entergy Louisiana as a capital contribution.

Entergy Louisiana used the $1 billion capital contribution to fund its Hurricane Ida escrow account and subsequently withdrew the $1 billion from the escrow account. With a portion of the $1 billion withdrawn from the
escrow account and the $1.4 billion from the Entergy Holdings Company liquidation, Entergy Louisiana deposited $290 million in a restricted escrow account as a storm damage reserve for future storms, used $1.2 billion to repay its unsecured term loan due June 2023, and used $435 million to redeem a portion of its 0.62% Series mortgage bonds due November 2023.

As discussed in Note 3 to the financial statements, the securitization resulted in recognition of a reduction of income tax expense of approximately $290 million by Entergy Louisiana. Entergy’s recognition of reduced income tax expense was partially offset by other tax charges resulting in a net reduction of income tax expense of $283 million. In recognition of obligations described in an LPSC ancillary order issued as part of the securitization regulatory proceeding, Entergy Louisiana recorded a $224 million ($165 million net-of-tax) regulatory charge and a corresponding regulatory liability to reflect its obligation to provide credits to its customers.

As discussed in Note 6 and Note 17 to the financial statements, Entergy Louisiana consolidates the storm trust I as a variable interest entity and the LURC’s 1% beneficial interest is presented as noncontrolling interest in the financial statements. In second quarter 2022, Entergy Louisiana recorded a charge of $31.6 million in other income to reflect the LURC’s beneficial interest in the storm trust I.

In April 2022, Entergy Louisiana filed an application with the LPSC relating to Hurricane Ida restoration costs. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by Hurricane Ida were estimated to be approximately $2.54 billion, including approximately $1.96 billion in capital costs and approximately $586 million in non-capital costs. Including carrying costs of $57 million through December 2022, Entergy Louisiana was seeking an LPSC determination that $2.60 billion was prudently incurred and, therefore, eligible for recovery from customers. As part of this filing, Entergy Louisiana also was seeking an LPSC determination that an additional $32 million in costs associated with the restoration of Entergy Louisiana’s electric facilities damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta as well as Winter Storm Uri was prudently incurred. This amount was exclusive of the requested $3 million in carrying costs through December 2022. In total, Entergy Louisiana was requesting an LPSC determination that $2.64 billion was prudently incurred and, therefore, eligible for recovery from customers. As discussed above, in March 2022 the LPSC approved financing of a $1 billion storm escrow account from which funds were withdrawn to finance costs associated with Hurricane Ida restoration. In June 2022, Entergy Louisiana supplemented the application with a request regarding the financing and recovery of the recoverable storm restoration costs. Specifically, Entergy Louisiana requested approval to securitize its restoration costs pursuant to Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021. In October 2022 the LPSC staff recommended a finding that the requested storm restoration costs of $2.64 billion, including associated carrying costs of $59.1 million, were prudently incurred and eligible for recovery from customers. The LPSC staff further recommended approval of Entergy Louisiana’s plans to securitize these costs, net of the $1 billion in funds withdrawn from the storm escrow account described above. The parties negotiated and executed an uncontested stipulated settlement which was filed with the LPSC in December 2022. The settlement agreement contains the following key terms: $2.57 billion of restoration costs from Hurricane Ida, Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri were prudently incurred and eligible for recovery; carrying costs of $59.2 million were recoverable; and Entergy Louisiana was authorized to finance $1.657 billion utilizing the securitization process authorized by Act 55, as supplemented by Act 293. A procedural motion to consider the uncontested settlement at the December 2022 LPSC meeting did not pass and the settlement was not voted on. In January 2023 an ALJ with the LPSC conducted a settlement hearing to receive the uncontested settlement and supporting testimony into evidence and issued a report of proceedings, which allows the LPSC to consider the uncontested settlement without the procedural motion that did not pass in December. In January 2023 the LPSC approved the stipulated settlement subject to certain modifications. These modifications include the recognition of accumulated deferred income tax benefits related to damaged assets and system restoration costs as a reduction of the amount authorized to be financed utilizing the securitization process authorized by Act 55, as supplemented by Act 293, from $1.657 billion to $1.491 billion. These modifications did not affect the LPSC’s conclusion that all system restoration costs sought by Entergy Louisiana were reasonable and prudent. In February 2023 the Louisiana Bond Commission voted to authorize the LCDA to issue the bonds authorized in the LPSC’s financing order.
In March 2023 the Hurricane Ida securitization financing closed, resulting in the issuance of approximately $1.491 billion principal amount of bonds by the LCDA and a remaining regulatory asset of $180 million to be recovered through the exclusion of the accumulated deferred income taxes related to damaged assets and system restoration costs from the determination of future rates. The securitization was authorized pursuant to the Louisiana Utilities Restoration Corporation Act, Part VIII of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021. The LCDA loaned the proceeds to the LURC. Pursuant to Act 293, the LURC contributed the net bond proceeds to a State legislatively authorized and LURC-sponsored trust, Restoration Law Trust II (the storm trust II).

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

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

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

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

As discussed in Note 6 and Note 17 to the financial statements, Entergy Louisiana consolidates the storm trust II as a variable interest entity and the LURC’s 1% beneficial interest is presented as noncontrolling interest in
the financial statements. In first quarter 2023, Entergy Louisiana recorded a charge of $14.6 million in other income to reflect the LURC’s beneficial interest in the storm trust II.

Hurricane Isaac

In August 2012, Hurricane Isaac caused extensive damage to Entergy Louisiana’s service area.  In June 2014 the LPSC authorized Entergy Louisiana to utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs.  Entergy Louisiana committed to pass on to customers a minimum of $30.8 million of customer benefits through annual customer credits of approximately $6.2 million for five years. Approvals for the Act 55 financings were obtained from the LURC and the Louisiana State Bond Commission.

In August 2014 the LCDA issued $314.85 million in bonds under Louisiana Act 55.  From the $309 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $16 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $293 million directly to Entergy Louisiana.  Entergy Louisiana used the $293 million received from the LURC to acquire 2,935,152.69 Class C preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 7.5% annual distribution rate. Distributions were payable quarterly commencing on September 15, 2014, and the membership interests had a liquidation price of $100 per unit. The preferred membership interests were callable at the option of Entergy Holdings Company after ten years under the terms of the LLC agreement. The terms of the membership interests included certain financial covenants to which Entergy Holdings Company was subject, including the requirement to maintain a net worth of at least $1.75 billion. As discussed above in “Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida”, in May 2022, Entergy Holdings Company liquidated and distributed cash to Entergy Louisiana as holder of the 2,935,152.69 units of Class C preferred membership interests.

Entergy and Entergy Louisiana do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA and there is no recourse against Entergy or Entergy Louisiana in the event of a bond default.  To service the bonds, Entergy Louisiana collects a system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee.  Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as the billing and collection agent for the state.

Hurricane Gustav and Hurricane Ike

In September 2008, Hurricane Gustav and Hurricane Ike caused catastrophic damage to Entergy Louisiana’s service territory.  In December 2009, Entergy Louisiana entered into a stipulation agreement with the LPSC staff regarding its storm costs.  In March and April 2010, Entergy Louisiana and other parties to the proceeding filed with the LPSC an uncontested stipulated settlement that included Entergy Louisiana’s proposal to utilize Act 55 financing, which included a commitment to pass on to customers a minimum of $43.3 million of customer benefits through a prospective annual rate reduction of $8.7 million for five years.  In April 2010 the LPSC approved the settlement and subsequently issued financing orders and a ratemaking order intended to facilitate the implementation of the Act 55 financings.  In June 2010 the Louisiana State Bond Commission approved the Act 55 financing. The settlement agreement allowed for an adjustment to the credits if there was a change in the applicable federal or state income tax rate. As a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, and the lowering of the federal corporate income tax rate from 35% to 21%, the Louisiana Act 55 financing savings obligation regulatory liability related to Hurricane Gustav and Hurricane Ike was reduced by $2.7 million, with a corresponding increase to Other regulatory credits on the income statement. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.

In July 2010 the LCDA issued two series of bonds totaling $713.0 million under Act 55.  From the $702.7 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $290 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $412.7 million directly to Entergy Louisiana.  From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana
used $412.7 million to acquire 4,126,940.15 Class B preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 9% annual distribution rate. Distributions were payable quarterly commencing on September 15, 2010, and the membership interests had a liquidation price of $100 per unit. The preferred membership interests were callable at the option of Entergy Holdings Company after ten years under the terms of the LLC agreement.  The terms of the membership interests included certain financial covenants to which Entergy Holdings Company was subject, including the requirement to maintain a net worth of at least $1 billion. As discussed above in “Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida”, in May 2022, Entergy Holdings Company liquidated and distributed cash to Entergy Louisiana as holder of the 4,126,940.15 units of Class B preferred membership interests.

The bonds were repaid in 2022. Entergy and Entergy Louisiana did not report the bonds issued by the LCDA on their balance sheets because the bonds were the obligation of the LCDA, and there was no recourse against Entergy or Entergy Louisiana in the event of a bond default.  To service the bonds, Entergy Louisiana collected a system restoration charge on behalf of the LURC and remitted the collections to the bond indenture trustee.  Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as the billing and collection agent for the state.

Hurricane Katrina and Hurricane Rita

In August and September 2005, Hurricanes Katrina and Rita caused catastrophic damage to Entergy Louisiana’s service territory. In March 2008, Entergy Louisiana and the LURC filed at the LPSC an application requesting that the LPSC grant a financing order authorizing the financing of Entergy Louisiana storm costs, storm reserves, and issuance costs pursuant to Louisiana Act 55.  Entergy Louisiana also filed an application requesting LPSC approval for ancillary issues including the mechanism to flow charges and savings to customers via a storm cost offset rider.  In April 2008 the Louisiana Public Facilities Authority (LPFA), which is the issuer of the bonds pursuant to the Act 55 financing, approved requests for the Act 55 financing.  Also in April 2008, Entergy Louisiana and the LPSC staff filed with the LPSC an uncontested stipulated settlement that included Entergy Louisiana’s proposal under the Act 55 financing, which included a commitment to pass on to customers a minimum of $40 million of customer benefits through a prospective annual rate reduction of $8 million for five years.  The LPSC subsequently approved the settlement and issued two financing orders and one ratemaking order intended to facilitate implementation of the Act 55 financing.  In May 2008 the Louisiana State Bond Commission granted final approval of the Act 55 financing. The settlement agreement allowed for an adjustment to the credits if there was a change in the applicable federal or state income tax rate. As a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, and the lowering of the federal corporate income tax rate from 35% to 21%, the Louisiana Act 55 financing savings obligation regulatory liability related to Hurricanes Katrina and Rita was reduced by $22.3 million, with a corresponding increase to Other regulatory credits on the income statement. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.

In July 2008 the LPFA issued $687.7 million in bonds under the aforementioned Act 55.  From the $679 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $152 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $527 million directly to Entergy Louisiana.  From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $545 million, including $17.8 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 5,449,861.85 Class A preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 10% annual distribution rate.  In August 2008 the LPFA issued $278.4 million in bonds under the aforementioned Act 55.  From the $274.7 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $87 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $187.7 million directly to Entergy Louisiana.  From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $189.4 million, including $1.7 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 1,893,918.39 Class A preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 10% annual distribution rate.  Distributions were payable quarterly commencing on September 15, 2008 and had a
liquidation price of $100 per unit.  The preferred membership interests were callable at the option of Entergy Holdings Company after ten years under the terms of the LLC agreement.  The terms of the membership interests included certain financial covenants to which Entergy Holdings Company was subject, including the requirement to maintain a net worth of at least $1 billion.  In February 2012, Entergy Louisiana sold 500,000 of its Class A preferred membership units in Entergy Holdings Company to a third party. Those preferred membership units were subsequently repurchased by Entergy Holdings Company in March 2019. As discussed above in “Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida”, in May 2022, Entergy Holdings Company liquidated and distributed cash to Entergy Louisiana as holder of the remaining 6,843,780.24 units of Class A preferred membership interests.

The bonds were repaid in 2018. Entergy and Entergy Louisiana did not report the bonds issued by the LPFA on their balance sheets because the bonds were the obligation of the LPFA, and there was no recourse against Entergy or Entergy Louisiana in the event of a bond default.  To service the bonds, Entergy Louisiana collected a system restoration charge on behalf of the LURC and remitted the collections to the bond indenture trustee.  Entergy and Entergy Louisiana did not report the collections as revenue because Entergy Louisiana was merely acting as the billing and collection agent for the state.

Entergy Mississippi

Prior to June 2024, Entergy Mississippi had approval from the MPSC to collect a storm damage provision of $1.75 million per month. If Entergy Mississippi’s accumulated storm damage provision balance exceeded $15 million, the collection of the storm damage provision ceased until such time that the accumulated storm damage provision became less than $10 million. Entergy Mississippi’s storm damage provision balance had been less than $10 million since May 2019, and Entergy Mississippi had been billing the monthly storm damage provision since July 2019.

In December 2023, Entergy Mississippi filed a Notice of Storm Escrow Disbursement and Request for Interim Relief notifying the MPSC that Entergy Mississippi had requested disbursement of approximately $34.5 million of storm escrow funds from its restricted storm escrow account. The filing also requested authorization from the MPSC, on a temporary basis, that the $34.5 million of storm escrow funds be credited to Entergy Mississippi’s storm damage provision, pending the MPSC’s review of Entergy Mississippi’s storm-related costs, and that Entergy Mississippi continue to bill its monthly storm damage provision without suspension in the event the storm damage provision balance exceeded $15 million, in anticipation of a subsequent filing by Entergy Mississippi in this proceeding. The storm damage provision exceeded $15 million upon receipt of the storm escrow funds. Because the MPSC had not entered an order on Entergy Mississippi’s filing on the requested relief to continue billing this provision, Entergy Mississippi suspended billing the monthly storm damage provision effective with February 2024 bills.

In March 2024, Entergy Mississippi made a combined dual filing which included a notice of intent to make routine change in rates and schedules and a motion for determination relating to the above-described notice of storm escrow disbursement. The notice of intent proposed a new storm damage mitigation and restoration rider to supersede both the then-current storm damage rate schedule and the vegetation management rider schedule, in which the collection of both expenses would be combined. The proposal requested that the MPSC authorize Entergy Mississippi to collect approximately $5.2 million per month for vegetation management and a storm damage provision. Furthermore, if Entergy Mississippi’s accumulated vegetation management and storm damage provision balance were to exceed $70 million, collection under the storm damage mitigation and restoration rider would cease until such time that the accumulated vegetation management and storm damage provision would become less than $60 million.

The Mississippi Public Utilities Staff reviewed the storm-related costs submitted by Entergy Mississippi and found them prudent. In June 2024 the MPSC considered and unanimously granted the relief sought by Entergy Mississippi, including authorization to credit any remaining funds in the storm escrow account to Entergy
Mississippi’s storm damage provision and to close the storm escrow account and approving the new storm damage mitigation and restoration rider. Entergy Mississippi’s storm escrow account was liquidated in July 2024, and the new combined storm damage mitigation and restoration rider became effective with the July 2024 billing cycle. Additionally, Entergy Mississippi made a compliance filing to cease billing under the existing vegetation management rider schedule as of the same billing cycle.

Entergy New Orleans

Hurricane Ida

In August 2021, Hurricane Ida caused significant damage to Entergy New Orleans’s service area, including Entergy’s electrical grid. The storm resulted in widespread power outages, including the loss of 100% of Entergy New Orleans’s load and damage to distribution and transmission infrastructure, including the loss of connectivity to the eastern interconnection. In September 2021, Entergy New Orleans withdrew $39 million from its funded storm reserves. In June 2022, Entergy New Orleans filed an application with the City Council requesting approval and certification that storm restoration costs associated with Hurricane Ida of approximately $170 million, which included $11 million in estimated costs, were reasonable, necessary, and prudently incurred to enable Entergy New Orleans to restore electric service to its customers and to repair Entergy New Orleans’s electric utility infrastructure. In addition, estimated carrying costs through December 2022 related to Hurricane Ida restoration costs were $9 million. Also, Entergy New Orleans requested approval that the $39 million withdrawal from its funded storm reserve in September 2021 and $7 million in excess storm reserve escrow withdrawals related to Hurricane Zeta in October 2020 and prior miscellaneous storms were properly applied to Hurricane Ida storm restoration costs, the application of which reduced the amount to be recovered from Entergy New Orleans customers by $46 million.

Additionally, in February 2022, Entergy New Orleans and the LURC filed with the City Council a securitization application requesting that the City Council review Entergy New Orleans’s storm reserve and increase the storm reserve funding level to $150 million, to be funded through securitization. In August 2022 the City Council’s advisors recommended that the City Council authorize a single securitization bond issuance to fund Entergy New Orleans’s storm recovery reserves to an amount sufficient to: (1) allow recovery of all of Entergy New Orleans’s unrecovered storm recovery costs following Hurricane Ida, subject to City Council review and certification; (2) provide initial funding of storm recovery reserves for future storms to a level of $75 million; and (3) fund the storm recovery bonds’ upfront financing costs. In September 2022, Entergy New Orleans and the City Council’s advisors entered into an agreement in principle, which was approved by the City Council along with a financing order in October 2022, which authorized Entergy New Orleans and the LURC to proceed with a single securitization bond issuance of approximately $206 million (subject to further adjustment and review pursuant to the Final Issuance Advice Letter process set forth in the financing order), with $125 million of that total to be used for interim recovery, subject to City Council review and certification, to be allocated to unrecovered Hurricane Ida storm recovery costs; $75 million of that total to provide for a storm recovery reserve for future storms; and the remainder to fund the recovery of the storm recovery bonds’ upfront financing costs.

In December 2022, Entergy New Orleans and the LURC filed with the City Council the Final Issuance Advice Letter for a securitization bond issuance in the amount of $209.3 million, the final structuring, terms, and pricing of which were approved by the City Council in accordance with the financing order. Also in December 2022 the LCDA issued $209.3 million in bonds pursuant to the Louisiana Electric Utility Storm Recovery Securitization Act, Part V-B of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana Regular Session of 2021. The LCDA loaned $201.8 million of bond proceeds, net of certain debt service and issuance costs, to the LURC. The LURC used the proceeds to purchase from Entergy New Orleans the storm recovery property, which is the right to collect storm recovery charges sufficient to pay the storm recovery bonds and associated financing costs, and Entergy New Orleans deposited $200 million in a restricted storm reserve escrow account as a storm damage reserve for Entergy New Orleans and received directly $1.8 million in estimated upfront financing costs. Subsequently, Entergy New Orleans withdrew $125 million from the newly securitized
storm reserve to cover Hurricane Ida storm recovery costs, subject to a final determination from the City Council regarding the prudency of the storm recovery costs.

Entergy and Entergy New Orleans do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA, and there is no recourse against Entergy or Entergy New Orleans in the event of a bond default. To service the bonds, Entergy New Orleans collects a storm recovery charge on behalf of the LURC and remits the collections to the bond indenture trustee. Entergy and Entergy New Orleans do not report the collections as revenue because Entergy New Orleans is merely acting as the billing and collection agent for the LURC.

In August 2023 the City Council advisors issued a report recommending that the City Council find that Entergy New Orleans prudently incurred approximately $164.1 million in storm restoration costs and $7.5 million in carrying charges and that such costs have already been properly recovered by Entergy New Orleans through withdrawals from the storm reserve escrow account. The City Council advisors also recommended that the City Council find that approximately $1.2 million in storm restoration costs had already been recovered through Entergy New Orleans’s base rates and that approximately $0.9 million in unused credits be applied against future storm costs. In August 2023 the City Council hearing officer certified the evidentiary record. In December 2023 the City Council approved a resolution adopting the advisors’ report and recommendations.

Entergy Texas

Hurricane Laura, Hurricane Delta, and Winter Storm Uri

In August 2020 and October 2020, Hurricane Laura and Hurricane Delta caused extensive damage to Entergy Texas’s service area. In February 2021, Winter Storm Uri also caused damage to Entergy Texas’s service area. The storms resulted in widespread power outages, significant damage primarily to distribution and transmission infrastructure, and the loss of sales during the power outages. In April 2021, Entergy Texas filed an application with the PUCT requesting a determination that approximately $250 million of system restoration costs associated with Hurricane Laura, Hurricane Delta, and Winter Storm Uri, including approximately $200 million in capital costs and approximately $50 million in non-capital costs, were reasonable and necessary to enable Entergy Texas to restore electric service to its customers and Entergy Texas’s electric utility infrastructure. The filing also included the projected balance of approximately $13 million of a regulatory asset containing previously approved system restoration costs related to Hurricane Harvey. In September 2021 the parties filed an unopposed settlement agreement, pursuant to which Entergy Texas removed from the amount to be securitized approximately $4.3 million that will instead be charged to its storm reserve, $5 million related to no particular issue, of which Entergy Texas would be permitted to seek recovery in a future proceeding, and approximately $300 thousand related to attestation costs. In December 2021 the PUCT issued an order approving the unopposed settlement and determining system restoration costs of $243 million related to Hurricane Laura, Hurricane Delta, and Winter Storm Uri and the $13 million projected remaining balance of the Hurricane Harvey system restoration costs were eligible for securitization. The order also determines that Entergy Texas can recover carrying costs on the system restoration costs related to Hurricane Laura, Hurricane Delta, and Winter Storm Uri.

In July 2021, Entergy Texas filed with the PUCT an application for a financing order to approve the securitization of the system restoration costs that are the subject of the April 2021 application. In November 2021 the parties filed an unopposed settlement agreement supporting the issuance of a financing order consistent with Entergy Texas’s application and with minor adjustments to certain upfront and ongoing costs to be incurred to facilitate the issuance and serving of system restoration bonds. In January 2022 the PUCT issued a financing order consistent with the unopposed settlement. As a result of the financing order, Entergy Texas reclassified $153 million from utility plant to other regulatory assets.

In April 2022, Entergy Texas Restoration Funding II, LLC, a company wholly-owned and consolidated by Entergy Texas, issued $290.85 million of senior secured system restoration bonds (securitization bonds). With the
proceeds, Entergy Texas Restoration Funding II purchased from Entergy Texas the transition property, which is the right to recover from customers through a system restoration charge amounts sufficient to service the securitization bonds. Entergy Texas began cost recovery through the system restoration charge effective with the first billing cycle of May 2022 and the system restoration charge is expected to remain in place up to 15 years. See Note 5 to the financial statements for a discussion of the April 2022 issuance of the securitization bonds.
Entergy New Orleans [Member]  
Public Utilities Disclosure [Text Block] RATE AND REGULATORY MATTERS (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Regulatory Assets and Regulatory 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. In addition to the regulatory assets and liabilities that are specifically disclosed on the face of the balance sheets, the tables below provide detail of “Other regulatory assets” and “Other regulatory liabilities” that are included on Entergy’s and the Registrant Subsidiaries’ balance sheets as of December 31, 2024 and 2023 (as noted in footnotes to the tables, a portion of these regulatory assets and regulatory liabilities is classified as held for sale in the balance sheets as of December 31, 2024):

Other Regulatory Assets

Entergy
20242023
 (In Millions)
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
$1,387.6 $1,655.5 
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or shutdown of non-nuclear power plants and solar facilities (Note 9) (a)
1,358.7 1,285.0 
Removal costs (Note 9)
1,107.6 1,010.7 
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators and Note 5 - Securitization Bonds)
547.3 536.9 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
227.1 250.9 
Retail rate deferrals - recovered through formula rates or rate riders as rates are redetermined by retail regulators
195.1 248.6 
Retired electric and gas meters - recovered through retail rates as determined by retail regulators (Note 2 - Retail Rate Proceedings)
135.7 153.8 
Deferred COVID-19 costs - recovered through retail rates as determined by retail regulators (Note 2 - Retail Rate Proceedings)
104.0 118.0 
Unamortized loss on reacquired debt - recovered over term of debt
57.9 63.1 
Advanced metering system surcharge for residential customers - recovered through December 2029
39.7 20.2 
Formula rate plan historical year rate adjustment (Note 2 - Retail Rate Proceedings) (b)
15.5 — 
Pension & postretirement benefits expense deferral - recovered through retail rates (Note 2 - Retail Rate Proceedings and Note 11 - Entergy Texas Reserve)
15.0 32.7 
Rate case depreciation relate back deferral - recovered over a six-month period beginning January 2024 (Note 2 - Retail Rate Proceedings)
— 27.6 
Opportunity sales - (Note 2 - Entergy Arkansas Opportunity Sales Proceeding) (b)
— 131.8 
Other99.7 134.6 
Entergy Total (c)
$5,290.9 $5,669.4 
Entergy Arkansas
 20242023
 (In Millions)
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or shutdown of non-nuclear power plants and solar facilities (Note 9) (a)
$693.0 $639.1 
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
433.3 536.6 
Removal costs (Note 9)
337.9 319.7 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
75.8 84.1 
Deferred COVID-19 costs - recovered over a 10-year period through December 2033
35.1 39.0 
Retired electric meters - recovered over a 15-year period through March 2034
32.8 36.3 
Storm damage costs - recovered through retail rates
29.8 33.1 
Unamortized loss on reacquired debt - recovered over term of debt
18.6 19.9 
Formula rate plan historical year rate adjustment (Note 2 - Retail Rate Proceedings) (b)
15.5 — 
Retail rate deferrals - recovered through rate riders as rates are redetermined annually (b)
13.6 24.9 
ANO Fukushima and Flood Barrier costs - recovered through retail rates through February 2026 (b)
2.1 3.8 
Opportunity sales - (Note 2 - Entergy Arkansas Opportunity Sales Proceeding) (b)
— 131.8 
Other12.6 17.1 
Entergy Arkansas Total$1,700.1 $1,885.4 

Entergy Louisiana
 20242023
 (In Millions)
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or shutdown of non-nuclear power plants (Note 9) (a)
$421.5 $408.7 
Pension & postretirement costs (Note 11 - Qualified Pension Plans and Non-Qualified Pension Plans) (a)
367.7 412.0 
Removal costs (Note 9)
323.2 262.3 
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)
226.6 202.6 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
111.4 123.0 
Retired electric and gas meters - recovered over a 22-year period through July 2041
78.5 83.2 
Deferred COVID-19 costs - recovery period to be determined (Note 2 - Retail Rate Proceedings) (a)
47.8 47.8 
Unamortized loss on reacquired debt - recovered over term of debt
21.7 23.4 
Other48.5 85.9 
Entergy Louisiana Total (c)
$1,646.9 $1,648.9 
Entergy Mississippi
 20242023
(In Millions)
Removal costs (Note 9)
$184.8 $188.0 
Retail rate deferrals - recovered through formula rates or rate riders as rates are redetermined annually
162.5 192.8 
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
112.1 127.6 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
29.1 32.0 
Asset retirement obligation - recovery dependent upon timing of shutdown of non-nuclear power plants and solar facility (Note 9) (a)
9.4 6.8 
Unamortized loss on reacquired debt - recovered over term of debt
9.1 10.0 
Attorney General litigation costs - recovered over a six-year period through March 2026 (b)
6.0 10.9 
Other12.8 11.0 
Entergy Mississippi Total$525.8 $579.1 

Entergy New Orleans
 20242023
 (In Millions)
Removal costs (Note 9)
$62.5 $61.1 
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
22.9 41.4 
Retired electric and gas meters - recovered over a 12-year period through July 2031 (b)
13.5 15.5 
Gas cross-boring costs - recovered through formula rates as rates are redetermined by retail regulators
11.9 10.9 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
10.8 11.8 
Deferred COVID-19 costs - recovered over a five-year period through August 2028 (b)
10.2 13.0 
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators and Note 5 - Entergy New Orleans Securitization Bonds - Hurricane Isaac)
4.0 3.9 
Unamortized loss on reacquired debt - recovered over term of debt
0.5 0.8 
Other20.7 24.0 
Entergy New Orleans Total (c)
$157.0 $182.4 
Entergy Texas
 20242023
 (In Millions)
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators and Note 5 - Entergy Texas Securitization Bonds - Hurricane Laura, Hurricane Delta, and Winter Storm Uri)
$286.5 $297.3 
Removal costs (Note 9)
102.3 77.5 
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
62.9 85.6 
Advanced metering system surcharge for residential customers - recovered through December 2029
39.7 20.2 
Pension & postretirement benefits expense deferral - recovered through retail rates (Note 2 - Retail Rate Proceedings and Note 11 - Entergy Texas Reserve)
15.0 32.7 
Retired electric meters - recovered through retail rates (Note 2 - Retail Rate Proceedings)
10.9 18.8 
Neches and Sabine costs - recovered over a 10-year period through September 2028
9.2 11.6 
Unamortized loss on reacquired debt - recovered over term of debt
7.6 8.3 
Rate case depreciation relate back deferral - recovered over a six-month period beginning January 2024 (Note 2 - Retail Rate Proceedings)
— 27.6 
Other15.6 17.0 
Entergy Texas Total$549.7 $596.6 

System Energy
 20242023
 (In Millions)
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear unit (Note 9) (b)
$224.8 $222.0 
Pension & postretirement costs (Note 11 - Qualified Pension Plans and Other Postretirement Benefits) (a)
104.4 121.6 
Removal costs - recovered through depreciation rates (Note 9)
96.9 102.1 
Unamortized loss on reacquired debt - recovered over term of debt
0.4 0.7 
System Energy Total$426.5 $446.4 

(a)Does not earn a return on investment, but is offset by related liabilities.
(b)Does not earn a return on investment.
(c)Includes $35.4 million at Entergy, $8.9 million at Entergy Louisiana, and $23.7 million at Entergy New Orleans as of December 31, 2024 of regulatory assets related to the respective natural gas distribution businesses classified as held for sale and included within “Non-current assets held for sale” on the respective consolidated balance sheets. See Note 14 to the financial statements for further discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses and the classification as held for sale.
Other Regulatory Liabilities

Entergy
20242023
(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)
$2,262.5 $1,826.2 
Securitization financing savings obligation (Note 3)
371.3 405.2 
Retail rate rider over-recovery - refunded through formula rate or rate riders as rates are redetermined by retail regulators
164.9 142.7 
Credits from resolution of the 2016-2018 IRS audit (Note 3)
163.3 98.0 
Customer rate credits from global stipulated settlement with the LPSC - returned to customers September 2024 through August 2026 (Note 2)
121.7 — 
Refund from System Energy settlement with the LPSC - to be returned to customers January 2025 through August 2027 (Note 2)
75.8 — 
Deferred tax equity partnership earnings (Note 1)
69.9 57.9 
Vidalia purchased power agreement (Note 8)
67.4 82.5 
Refund from System Energy settlement with the City Council - returned to customers over a 25-year period beginning September 2024 (Note 2)
64.7 — 
Shorter-term financing interest earnings (Note 2 - Retail Rate Proceedings) (a)
48.9 36.8 
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and the FERC
44.4 44.4 
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)
40.9 44.3 
Refund from System Energy settlement with the City Council - return to customers to be determined (Note 2)
32.0 — 
Refund from System Energy settlement with the APSC - refunded through a rate rider as rates are re-determined periodically (Note 2)
8.2 93.0 
Complaints against System Energy - potential future refunds (Note 2)
— 177.9 
Other75.2 108.0 
Entergy Total (b)
$3,611.1 $3,116.9 

Entergy Arkansas
 20242023
 (In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)
$761.3 $621.6 
Deferred tax equity partnership earnings (Note 1)
32.4 27.4 
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually
27.9 10.6 
Refund from System Energy settlement with the APSC - refunded through a rate rider as rates are re-determined periodically (Note 2)
8.2 93.0 
Internal restructuring guaranteed customer credits - returned to customers over a six-year period through December 2024
— 6.6 
Other1.4 — 
Entergy Arkansas Total$831.2 $759.2 
Entergy Louisiana
 20242023
 (In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)
$798.4 $644.0 
Securitization financing savings obligation (Note 3)
371.3 405.2 
Customer rate credits from global stipulated settlement with the LPSC - returned to customers September 2024 through August 2026 (Note 2)
121.7 — 
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually
96.3 86.4 
Refund from System Energy settlement with the LPSC - to be returned to customers January 2025 through August 2027 (Note 2)
75.8 — 
Vidalia purchased power agreement (Note 8)
67.4 82.5 
Shorter-term financing interest earnings (Note 2 - Retail Rate Proceedings) (a)
48.9 36.8 
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)
40.9 44.3 
Hurricane Ida insurance proceeds - returned to customers August 2024 to July 2025
26.0 32.3 
Credits from resolution of the 2016-2018 IRS audit - returned to customers September 2024 through August 2025 (Note 3)
25.3 38.0 
Sale-leaseback and depreciation refunds - returned to customers September 2023 through August 2024
— 14.1 
Other21.7 24.1 
Entergy Louisiana Total (b)
$1,693.7 $1,407.7 

Entergy Mississippi
20242023
 (In Millions)
Deferred tax equity partnership earnings (Note 1)
$37.5 $30.5 
Retail rate rider over-recovery - refunded through formula rate or rate riders as rates are redetermined annually
12.2 2.4 
Other postretirement benefits (Note 11 - Entergy Mississippi Other Postretirement Benefits)
7.4 — 
Other2.4 0.8 
Entergy Mississippi Total$59.5 $33.7 
Entergy New Orleans
20242023
 (In Millions)
Credits from resolution of the 2016-2018 IRS audit - to be returned to customers over a 25-year period beginning January 2025 (Note 3)
$138.0 $60.0 
Refund from System Energy settlement with the City Council - returned to customers over a 25-year period beginning September 2024 (Note 2)
64.7 — 
Refund from System Energy settlement with the City Council - return to customers to be determined (Note 2)
32.0 — 
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually
16.3 20.1 
Sale-leaseback and depreciation refunds - returned to customers over a 10-year period beginning September 2023 (Note 2)
5.2 9.8 
Other4.5 0.5 
Entergy New Orleans Total (b)
$260.7 $90.4 

Entergy Texas
 20242023
 (In Millions)
Retail rate rider over-recovery - return to customers to be determined
$12.2 $23.8 
Retail refunds - return to customers to be determined
6.2 6.2 
Rate case settlement relate back - amortized over a six-month period beginning January 2024 (Note 2 - Retail Rate Proceedings)
— 10.3 
Other 0.3 2.7 
Entergy Texas Total$18.7 $43.0 

System Energy
 20242023
 (In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)
$702.8 $560.6 
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and the FERC
44.4 44.4 
Complaints against System Energy - potential future refunds (Note 2)
— 177.9 
System Energy Total$747.2 $782.9 

(a)Offset by related asset.
(b)Includes $1.6 million at Entergy, $1.2 million at Entergy Louisiana, and $0.4 million at Entergy New Orleans as of December 31, 2024 of regulatory liabilities related to the respective natural gas distribution businesses classified as held for sale and included within other non-current liabilities on the respective consolidated balance sheets. See Note 14 to the financial statements for further discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses and the classification as held for sale.
Regulatory activity regarding the Tax Cuts and Jobs Act

See the “Other Tax Matters - Tax Cuts and Jobs Act” section in Note 3 to the financial statements for discussion of the effects of the December 2017 enactment of the Tax Cuts and Jobs Act (Tax Act), including its effects on Entergy’s and the Registrant Subsidiaries’ regulatory asset/liability for income taxes.

Entergy Louisiana

In an electric formula rate plan settlement approved by the LPSC in April 2018, the parties agreed that Entergy Louisiana would return to customers one-half of its eligible unprotected excess deferred income taxes from May 2018 through December 2018 and return to customers the other half from January 2019 through August 2022. In addition, the settlement provided that in order to flow back to customers certain other tax benefits created by the Tax Act, Entergy Louisiana established a regulatory liability effective January 1, 2018 in the amount of $9.1 million per month to reflect these tax benefits already included in retail rates until new base rates under the formula rate plan were established in September 2018, and this regulatory liability was returned to customers over the September 2018 through August 2019 formula rate plan rate-effective period. The LPSC staff and intervenors in the settlement reserved the right to obtain data from Entergy Louisiana to confirm the determination of excess accumulated deferred income taxes resulting from the Tax Act and the analysis thereof as part of the formula rate plan review proceeding for the 2017 test year filing. As discussed below in “Retail Rate Proceedings - Filings with the LPSC (Entergy Louisiana) - Retail Rates - Electric - Formula Rate Plan Global Settlement”, a global settlement resolving the outstanding issues related to the 2017 formula rate plan filing was reached in October 2023 and approved by the LPSC in November 2023.

System Energy

In a filing made with the FERC in March 2018, System Energy proposed revisions to the Unit Power Sales Agreement to reflect the effects of the Tax Act. In the filing System Energy proposed to return identified quantities of unprotected excess accumulated deferred income taxes to its customers by the end of 2018. In May 2018 the FERC accepted System Energy’s proposed tax revisions with an effective date of June 1, 2018, subject to refund and the outcome of settlement and hearing procedures. Settlement discussions were terminated in April 2019, and a hearing was held in March 2020. In December 2022 the FERC issued an order requiring System Energy to compute the amount of excess accumulated deferred income taxes associated with a previously uncertain decommissioning tax position with consideration for the resolution of the tax position by the IRS. In February 2023, System Energy submitted its compliance filing. This matter was ultimately settled as a result of System Energy’s settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” below for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.
Fuel and purchased power cost recovery

The Utility operating companies are allowed to recover fuel and purchased power costs through fuel mechanisms included in electric and gas rates that are recorded as fuel cost recovery revenues.  The difference between revenues collected and the current fuel and purchased power costs is generally recorded as “Deferred fuel costs” on the Utility operating companies’ financial statements.  The table below shows the amount of deferred fuel costs as of December 31, 2024 and 2023 that each Utility operating company expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.

 20242023
 (In Millions)
Entergy Arkansas
($45.2)($88.3)
Entergy Louisiana (a) (b)$163.4 $192.9 
Entergy Mississippi($126.3)($130.6)
Entergy New Orleans (a) (b)$8.0 $10.2 
Entergy Texas($59.3)$139.0 

(a)Includes $168.1 million in both years for Entergy Louisiana and $4.1 million in both years for Entergy New Orleans of fuel, purchased power, and capacity costs, which do not currently earn a return on investment and whose recovery periods are indeterminate but are expected to be recovered over a period greater than twelve months.
(b)Includes $0.7 million at Entergy Louisiana and $4.9 million at Entergy New Orleans as of December 31, 2024 of deferred fuel assets related to the respective natural gas distribution businesses classified as held for sale and included within “Current assets held for sale” on the respective consolidated balance sheets. See Note 14 to the financial statements for further discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses and the classification as held for sale.

Entergy Arkansas

Energy Cost Recovery Rider

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

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

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

In March 2018, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01547 per kWh to $0.01882 per kWh. The Arkansas Attorney General filed a response to Entergy Arkansas’s annual redetermination filing requesting that the APSC suspend the proposed tariff to investigate the amount of the redetermination or, alternatively, to allow recovery subject to refund. Among the reasons the Attorney General cited for suspension were questions pertaining to how Entergy Arkansas forecasted sales and potential implications of the Tax Cuts and Jobs Act. Entergy Arkansas replied to the Attorney General’s filing and stated that, to the extent there are questions pertaining to its load forecasting or the operation of the energy cost recovery rider, those issues exceed the scope of the instant rate redetermination. Entergy Arkansas also stated that potential effects of the Tax Cuts and Jobs Act are appropriately considered in the APSC’s separate proceeding regarding potential implications of the tax law. The APSC general staff filed a reply to the Attorney General’s filing and agreed that Entergy Arkansas’s filing complied with the terms of the energy cost recovery rider. The redetermined rate became effective with the first billing cycle of April 2018. Subsequently in April 2018 the APSC issued an order declining to suspend Entergy Arkansas’s energy cost recovery rider rate and declining to require further investigation at that time of the issues suggested by the Attorney General in the proceeding. Following a period of discovery, the Attorney General filed a supplemental response in October 2018 raising new issues with Entergy Arkansas’s March 2018 rate redetermination and asserting that $45.7 million of the increase should be collected subject to refund pending further investigation. Entergy Arkansas filed to dismiss the Attorney General’s supplemental response, the APSC general staff filed a motion to strike the Attorney General’s filing, and the Attorney General filed a supplemental response disputing Entergy Arkansas and the APSC staff’s filing. Applicable APSC rules and processes authorize its general staff to initiate periodic audits of Entergy Arkansas’s energy cost recovery rider. In late-2018 the APSC general staff notified Entergy Arkansas it initiated an audit of the 2017 fuel costs. The time in which the audit will be complete is uncertain at this time.

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

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

In March 2024, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease in the rate from $0.01883 per kWh to $0.00882 per kWh. Due to a change in law in the State of Arkansas, the annual redetermination included $9 million, recorded as a credit to fuel expense in first quarter 2024, for recovery attributed to net metering costs in 2023. The primary reason for the rate decrease is a large over-recovered balance as a result of lower natural gas prices in 2023. To mitigate the effect of projected increases in natural gas prices in 2024, Entergy Arkansas adjusted the over-recovered balance included in the March 2024 annual redetermination filing by $43.7 million. This adjustment is expected to reduce the rate change that will be reflected in the 2025 energy cost rate redetermination. The redetermined rate of $0.00882 per kWh became effective with the first billing cycle in April 2024 through the normal operation of the tariff.

Entergy Louisiana

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

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

In March 2020 the LPSC staff provided notice of an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2016 through 2019. The LPSC staff issued its audit report in September 2021, and although certain internal record keeping recommendations were made, the LPSC staff did not recommend any disallowances. The next step is for the LPSC to review the report, but there is not a deadline for the review.

In January 2023 the LPSC staff provided notice of an audit of Entergy Louisiana’s purchased gas adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s purchased gas adjustment clause for the period from 2021 through 2022. Discovery is ongoing, and no audit report has been filed.
In January 2023 the LPSC staff provided notice of an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2020 through 2022. Discovery is ongoing, and no audit report has been filed.

Entergy Mississippi

Entergy Mississippi’s rate schedules include an energy cost recovery rider and a power management rider, both of which are adjusted annually to reflect accumulated over- or under-recoveries. Entergy Mississippi recovers fuel and purchased energy costs through its energy cost recovery rider and recovers costs associated with natural gas hedging and capacity payments through its power management rider. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.

In November 2021, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an under-recovery of approximately $80.6 million as of September 30, 2021. In December 2021, at the request of the MPSC, Entergy Mississippi submitted a proposal to mitigate the impact of rising fuel costs on customer bills during 2022. Entergy Mississippi proposed that the deferred fuel balance as of December 31, 2021, which was $121.9 million, be amortized over three years and that the MPSC authorize Entergy Mississippi to apply its weighted-average cost of capital as the carrying cost for the unamortized fuel balance. In January 2022 the MPSC approved the amortization of $100 million of the deferred fuel balance over two years and authorized Entergy Mississippi to apply its weighted-average cost of capital as the carrying cost for the unamortized fuel balance. The MPSC approved the proposed energy cost factor effective for February 2022 bills.

See “Complaints Against System Energy - System Energy Settlement with the MPSC” below for discussion of the settlement agreement filed with the FERC in June 2022. The settlement, which was approved by the FERC in November 2022, provided for a refund of $235 million from System Energy to Entergy Mississippi. In July 2022 the MPSC directed the disbursement of settlement proceeds, ordering Entergy Mississippi to provide a one-time $80 bill credit to each of its approximately 460,000 retail customers to be effective during the September 2022 billing cycle and to apply the remaining proceeds to Entergy Mississippi’s under-recovered deferred fuel balance. In accordance with the MPSC’s directive, Entergy Mississippi provided approximately $36.7 million in customer bill credits as a result of the settlement. In November 2022, Entergy Mississippi applied the remaining settlement proceeds in the amount of approximately $198.3 million to Entergy Mississippi’s under-recovered deferred fuel balance.

Entergy Mississippi had a deferred fuel balance of approximately $291.7 million under the energy cost recovery rider as of July 31, 2022, along with an over-recovery balance of $51.1 million under the power management rider. Without further action, Entergy Mississippi anticipated a year-end deferred fuel balance of approximately $200 million after application of a portion of the System Energy settlement proceeds, as discussed above. In September 2022, Entergy Mississippi filed for interim adjustments under both the energy cost recovery rider and the power management rider. Entergy Mississippi proposed five monthly incremental adjustments to the net energy cost factor designed to collect the under-recovered fuel balance as of July 31, 2022 and to reflect the recovery of a higher natural gas price. Entergy Mississippi also proposed five monthly incremental adjustments to the power management adjustment factor designed to flow through to customers the over-recovered power management rider balance as of July 31, 2022. In October 2022 the MPSC approved modified interim adjustments to Entergy Mississippi’s energy cost recovery rider and power management rider. The MPSC approved dividing the energy cost recovery rider interim adjustment into two components that would allow Entergy Mississippi to (1) recover a natural gas fuel rate that is better aligned with current prices; and (2) recover the estimated under-recovered deferred fuel balance as of September 30, 2022 over a period of 20 months. The MPSC approved six monthly incremental adjustments to the net energy cost factor designed to reflect the recovery of a higher natural gas price. The MPSC also approved six monthly incremental adjustments to the power management adjustment factor designed to flow through to customers the over-recovered power management rider balance. In accordance
with the order of the MPSC, Entergy Mississippi did not file an annual redetermination of the energy cost recovery rider or the power management rider in November 2022.

In June 2023 the MPSC approved the joint stipulation agreement between Entergy Mississippi and the Mississippi Public Utilities Staff for Entergy Mississippi’s 2023 formula rate plan filing. The stipulation directed Entergy Mississippi to make a compliance filing to revise its power management cost adjustment factor, to revise its grid modernization cost adjustment factor, and to include a revision to reduce the net energy cost factor to a level necessary to reflect an average natural gas price of $4.50 per MMBtu. The MPSC approved the compliance filing in June 2023, effective for July 2023 bills. See “Retail Rate Proceedings - Filings with the MPSC (Entergy Mississippi) - Retail Rates - 2023 Formula Rate Plan Filing” below for further discussion of the 2023 formula rate plan filing and the joint stipulation agreement.

In November 2023 Entergy Mississippi filed its annual redeterminations of the energy cost factor and the power management cost adjustment factor. The calculation of the annual factor for the energy cost recovery rider included a projected over-recovery balance of approximately $142 million at the end of January 2024. The calculation of the annual factor for the power management rider included a projected under-recovery of $47 million at the end of January 2024. In January 2024 the MPSC approved the proposed energy cost factor and the proposed power management cost factor effective for February 2024 bills.

In June 2024 the MPSC approved the joint stipulation agreement between Entergy Mississippi and the Mississippi Public Utilities Staff for Entergy Mississippi’s 2024 formula rate plan filing. The 2024 formula rate plan filing included the conclusion of the modified interim adjustments to Entergy Mississippi’s energy cost recovery rider and power management rider, which were approved in October 2022 and allowed Entergy Mississippi to recover certain under-collected fuel balances, effective for July 2024 bills. The stipulation provided for Entergy Mississippi to reduce its net energy cost factor. See “Retail Rate Proceedings - Filings with the MPSC (Entergy Mississippi) - Retail Rates - 2024 Formula Rate Plan Filing” below for further discussion of the 2024 formula rate plan filing and the joint stipulation agreement.

In November 2024, Entergy Mississippi filed its annual redeterminations of the energy cost factor and the power management cost adjustment factor. The calculation of the annual factor for the energy cost recovery rider included a projected over-recovery balance of approximately $144.6 million as of September 2024. The calculation of the annual factor for the power management rider included a projected under-recovery of $60.1 million as of September 2024. In January 2025 the MPSC approved a revised energy cost factor, effective for February 2025 bills, that did not reflect the fuel savings associated with Entergy Mississippi’s incremental increase in its share of capacity and energy in connection with Entergy Mississippi’s assumption of Entergy Louisiana’s entitlements to Grand Gulf capacity and energy, which was subject to the MPSC’s review at such time. In February 2025 the MPSC approved Entergy Mississippi’s notice of intent for Entergy Mississippi’s assumption of Entergy Louisiana’s entitlements to Grand Gulf capacity and energy, with associated fuel savings to be reflected in Entergy Mississippi’s energy cost recovery rider, effective for March 2025 bills. Additionally, in February 2025 the MPSC approved the proposed power management cost adjustment factor, effective for March 2025 bills.

Entergy New Orleans

Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.

Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.
Entergy Texas

Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, not recovered in base rates.  Historically, semi-annual revisions of the fixed fuel factor have been made in March and September based on the market price of natural gas and changes in fuel mix.  The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. In 2023 the Texas legislature modified the Texas Utilities Code to provide that material over- and under-recovered fuel balances are to be refunded or surcharged through interim fuel adjustments and that fuel reconciliations must be filed at least once every two years. Entergy Texas expects the PUCT to undertake a rulemaking to effectuate the new legislation in 2025.

In May 2022, Entergy Texas filed an application with the PUCT to implement an interim fuel surcharge to collect the cumulative under-recovery of approximately $51.7 million, including interest, of fuel and purchased power costs incurred from May 1, 2020 through December 31, 2021. The under-recovery balance was primarily attributable to the impacts of Winter Storm Uri, including historically high natural gas prices, partially offset by settlements received by Entergy Texas from MISO related to Hurricane Laura. Entergy Texas proposed that the interim fuel surcharge be assessed over a period of six months beginning with the first billing cycle after the PUCT issues a final order, but no later than the first billing cycle of September 2022. Also in May 2022, the PUCT referred the proceeding to the State Office of Administrative Hearings. In July 2022, Entergy Texas filed on behalf of the parties an unopposed settlement resolving all issues in the proceeding. In addition, Entergy Texas filed on behalf of the parties a motion to admit evidence, to approve interim rates as requested in the initial application, and to remand the proceeding to the PUCT to consider the unopposed settlement. In August 2022 the ALJ with the State Office of Administrative Hearings issued an order granting Entergy Texas’s motion, approving interim rates effective with the first billing cycle of September 2022, and remanding the case to the PUCT for final approval. The interim fuel surcharge was approved by the PUCT in January 2023.

In September 2022, Entergy Texas filed an application with the PUCT to reconcile its fuel and purchased power costs for the period from April 2019 through March 2022. During the reconciliation period, Entergy Texas incurred approximately $1.7 billion in eligible fuel and purchased power expenses, net of certain revenues credited to such expenses and other adjustments. As of the end of the reconciliation period, Entergy Texas’s cumulative under-recovery balance was approximately $103.1 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning April 2022, pending future surcharges or refunds as approved by the PUCT. In November 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In July 2023, Entergy Texas filed an unopposed settlement, supporting testimony, and an agreed motion to admit evidence and remand the proceeding to the PUCT. Pursuant to the unopposed settlement, Entergy Texas would receive no disallowance of fuel costs incurred over the three-year reconciliation period and retain $9.3 million in margins from off-system sales made during the reconciliation period, resulting in a cumulative under-recovery balance of approximately $99.7 million, including interest, as of the end of the reconciliation period. In July 2023 the ALJ with the State Office of Administrative Hearings granted the motion to admit evidence and remanded the proceeding to the PUCT for consideration of the unopposed settlement. The PUCT approved the settlement in September 2023.

In September 2024, Entergy Texas filed an application with the PUCT to reconcile its fuel and purchased power costs for the period from April 2022 through March 2024. During the reconciliation period, Entergy Texas incurred approximately $1.6 billion in eligible fuel and purchased power expenses to generate and purchase electricity to serve its customers, net of certain revenues credited to such expenses and other adjustments. Entergy Texas’s cumulative under-recovery balance for the reconciliation period was approximately $30 million, including interest, which Entergy Texas requested authority to carry over as part of the cumulative fuel balance for the subsequent reconciliation period beginning April 2024. In November 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 procedural schedule, with a hearing on the merits scheduled for May 2025. A PUCT decision is expected in third quarter 2025.
In December 2024, Entergy Texas filed an application with the PUCT to implement an interim fuel refund of $45.5 million, including interest. Entergy Texas proposed that the interim fuel refund be implemented over a three-month period beginning with the first billing cycle in February 2025 for residential and other small customers and through a one-time credit, or surcharge depending on historical usage for the respective customer, for certain transmission voltage level and seasonal agricultural customers in February 2025. Also in December 2024 the PUCT referred the proceeding to the State Office of Administrative Hearings. In January 2025 the ALJ with the State Office of Administrative Hearings issued an order approving the interim fuel refund consistent with Entergy Texas’s application and, because no hearing was requested in the proceeding, dismissing the case from the State Office of Administrative Hearings and the PUCT.
Retail Rate Proceedings

Filings with the APSC (Entergy Arkansas)

Retail Rates

2022 Formula Rate Plan Filing

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

2023 Formula Rate Plan Filing

In July 2023, Entergy Arkansas filed with the APSC its 2023 formula rate plan filing to set its formula rate for the 2024 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2024 and a netting adjustment for the historical year 2022. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2024 projected year was 8.11% resulting in a revenue deficiency of $80.5 million. The earned rate of return on common equity for the 2022 historical year was 7.29% resulting in a $49.8 million netting adjustment. The total proposed revenue change for the 2024 projected year and 2022 historical year netting adjustment was $130.3 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $88.6 million. The APSC general staff and intervenors filed their errors and objections in October 2023, proposing certain adjustments, including the APSC general staff’s update to annual filing year revenues which lowers the constraint to $87.7 million. Entergy Arkansas filed its rebuttal in October 2023. In October 2023, Entergy
Arkansas filed with the APSC a settlement agreement reached with other parties resolving all issues in the proceeding, none of which affected Entergy Arkansas’s requested recovery up to the constraint of $87.7 million. The settlement agreement provided for amortization of the approximately $39 million regulatory asset for costs associated with the COVID-19 pandemic over a 10-year period as well as recovery of $34.9 million related to the resolution of the 2016 and 2017 IRS audits from previous tax positions that are no longer uncertain, partially offset by $24.7 million in excess accumulated deferred income taxes from reductions in state income tax rates, each before consideration of their respective tax gross-up. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit and the State of Arkansas corporate income tax rate changes. In December 2023 the APSC approved the settlement agreement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2024.

2024 Formula Rate Plan Filing

In July 2024, Entergy Arkansas filed with the APSC its 2024 formula rate plan filing to set its formula rate for the 2025 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the 2025 projected year and a netting adjustment for the 2023 historical year. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2025 projected year was 8.43% resulting in a revenue deficiency of $69.5 million. The earned rate of return on common equity for the 2023 historical year was 7.48% resulting in a $33.1 million netting adjustment. The total proposed revenue change for the 2025 projected year and 2023 historical year netting adjustment is $102.6 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $82.6 million. The APSC general staff and intervenors filed their errors and objections in October 2024, proposing certain adjustments, including the APSC general staff’s update to annual filing year revenues that increases the constraint to $83.5 million. Entergy Arkansas filed its rebuttal in October 2024, and later in October 2024 the parties submitted a joint issues list and stipulations setting forth the disputed issues and the noncontested issues. In December 2024 the APSC approved the parties’ stipulations without modification, approved Entergy Arkansas’s adjustment with respect to storm costs, directed Entergy Arkansas to adjust its projected year distribution reliability capital closings, and deferred the recoverability of Entergy Arkansas’s opportunity sales legal fees until the next general rate case. Also in December 2024 the APSC approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2025. As a result of the proceeding, the total revenue change was $82.7 million, including a $63.7 million increase for the 2025 projected year and a $31.4 million netting adjustment for the 2023 historical year. In fourth quarter 2024, Entergy Arkansas recorded a regulatory asset of $15.5 million to reflect the amount of the 2023 historical year netting adjustment that it expects to collect from its customers during the 2025 rate effective period. Pursuant to the terms of the parties’ stipulations, Entergy Arkansas made a filing with the APSC in January 2025 to refund customers $30.1 million in excess accumulated deferred income taxes resulting from the reduction in the State of Arkansas’s income tax rate from 4.8% to 4.3% in 2024. Entergy Arkansas will make this refund over a 24-month period effective with the first billing cycle of February 2025.

Grand Gulf Credit Rider

In June 2024, Entergy Arkansas filed with the APSC a tariff to provide retail customers a credit resulting from the terms of the settlement agreement between Entergy Arkansas, System Energy, additional named Entergy parties, and the APSC pertaining to System Energy’s billings for wholesale sales of energy and capacity from the Grand Gulf nuclear plant. See “Complaints Against System Energy - System Energy Settlement with the APSC” below for discussion of the settlement. In July 2024 the APSC approved the tariff, under which Entergy Arkansas will refund to retail customers a total of $100.6 million. To date, Entergy Arkansas has refunded $92.3 million of the total through one-time bill credits during the August 2024 billing cycle and is finalizing plans for the refund of the remaining regulatory liability balance.
Filings with the LPSC (Entergy Louisiana)

Retail Rates - Electric

2020 Formula Rate Plan Filing

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

In November 2023 the LPSC approved a global settlement which resolved all outstanding issues related to the 2017, 2018, and 2019 formula rate plan filings and resolved certain issues with respect to the 2020 and 2021 formula rate plan filings. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” below for further discussion.

2021 Formula Rate Plan Filing

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

In November 2023 the LPSC approved a global settlement which resolved all outstanding issues related to the 2017, 2018, and 2019 formula rate plan filings and resolved certain issues with respect to the 2020 and 2021
formula rate plan filings. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” below for further discussion.

2022 Formula Rate Plan Filing

In May 2023, Entergy Louisiana filed its formula rate plan evaluation report for its 2022 calendar year operations. The 2022 test year evaluation report produced an earned return on common equity of 8.33%, requiring an approximately $70.7 million increase to base rider revenue. Due to a cap for the 2021 and 2022 test years, however, base rider formula rate plan revenues were only increased by approximately $4.9 million, resulting in a revenue deficiency of approximately $65.9 million and providing for prospective return on common equity opportunity of approximately 8.38%. Other changes in formula rate plan revenue driven by increases in capacity costs, primarily legacy capacity costs, additions eligible for recovery through the transmission recovery mechanism and distribution recovery mechanism, and higher sales during the test period were offset by reductions in net MISO costs as well as credits for FERC-ordered refunds. Also included in the 2022 test year distribution recovery mechanism revenue requirement was a $6 million credit relating to the distribution recovery mechanism performance accountability standards and requirements. In total, the net increase in formula rate plan revenues, including base formula rate plan revenues inside the formula rate plan bandwidth and subject to the cap, as well as other formula rate plan revenues outside of the bandwidth, was $85.2 million. In August 2023 the LPSC staff filed a list of objections/reservations, including outstanding issues from the test years 2017-2021 formula rate plan filings, the calculation of certain refunds from System Energy, and certain calculations relating to the tax reform adjustment mechanism. Subject to LPSC review, the resulting net increase in formula rate plan revenues of $85.2 million became effective for bills rendered during the first billing cycle of September 2023, subject to refund. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” below for further discussion.

2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request

In August 2023, Entergy Louisiana filed an application for approval of a regulatory blueprint necessary for it to strengthen the electric grid for the State of Louisiana, which contained a dual-path request to update rates through either: (1) extension of Entergy Louisiana’s current formula rate plan (with certain modifications) for three years (the Rate Mitigation Proposal), which is Entergy Louisiana’s recommended path; or (2) implementation of rates resulting from a cost-of-service study (the Rate Case path). The application complied with Entergy Louisiana’s previous formula rate plan extension order requiring that for Entergy Louisiana to obtain another extension of its formula rate plan that included a rate reset, Entergy Louisiana would need to submit a full cost-of-service rate case. Entergy Louisiana’s filing supported the need to extend Entergy Louisiana’s formula rate plan with credit supportive mechanisms needed to facilitate investment in the distribution, transmission, and generation functions.

In July 2024, Entergy Louisiana reached an agreement in principle with the LPSC staff and the intervenors in the proceeding and filed with the LPSC a joint motion to suspend the procedural schedule to allow for all parties to finalize a stipulated settlement agreement.

In August 2024, Entergy Louisiana and the LPSC staff jointly filed a global stipulated settlement agreement for consideration by the LPSC with key terms as follows:

•continuation of the formula rate plan for 2024-2026 (test years 2023-2025);
•a base formula rate plan revenue increase of $120 million for test year 2023, effective for rates beginning September 2024;
•a $140 million cumulative cap on base formula rate plan revenue increases, if needed, for test years 2024 and 2025, excluding outside the bandwidth items;
•$184 million of customer rate credits to be given over two years, including increasing customer sharing of income tax benefits resulting from the 2016-2018 IRS audit, to resolve any remaining disputed issues stemming from formula rate plan test years prior to test year 2023, including but not limited to the investigation into Entergy Services costs billed to Entergy Louisiana. As discussed in Note 3 to the financial statements, a $38 million regulatory liability was recorded in 2023 in connection with the 2016-2018 IRS audit;
•$75.5 million of customer rate credits, as provided for in the System Energy global settlement, to be credited over three years subject to and conditioned upon FERC approval of the System Energy global settlement, which was approved in November 2024. See “Complaints Against System Energy – System Energy Settlement with the LPSC” below for further details of the System Energy global settlement;
•$5.8 million of customer rate credits provided for in the Entergy Louisiana formula rate plan global settlement agreement approved by the LPSC in November 2023 credited over one year. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement;
•an increase in the allowed midpoint return on common equity from 9.5% to 9.7%, with a bandwidth of 40 basis points above and below the midpoint, for the extended term of the formula rate plan, except that for test year 2023 in which the authorized return on common equity shall have no bearing on the change in base formula rate plan revenue described above and, for test year 2024, any earnings above the authorized return on common equity shall be returned to customers through a credit;
•an increase in nuclear depreciation rates by $15 million in each of the 2023, 2024, and 2025 test years outside of the formula rate plan bandwidth calculation; and
•for the transmission recovery mechanism and the distribution recovery mechanism, no change to the existing floors, but the caps for both would be $350 million for test year 2023, $375 million for test year 2024, and $400 million for test year 2025. Transmission projects filed with the LPSC will be exempt from the transmission recovery mechanism cap.

The global stipulated settlement agreement was unanimously approved by the LPSC in August 2024 and an order was issued by the LPSC in September 2024 reflecting the approval of the settlement.

Based on the July 2024 agreement in principle, in second quarter 2024 Entergy Louisiana recorded expenses of $151 million ($112 million net-of-tax) primarily consisting of regulatory charges to reflect the effects of the agreement in principle.

Formula Rate Plan Global Settlement

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

2023 Formula Rate Plan Filing

In August 2024, pursuant to the global stipulated settlement agreement, Entergy Louisiana filed its formula rate plan evaluation report for its 2023 calendar year operations. Consistent with the global stipulated settlement agreement, the filing reflected a 9.7% allowed return on common equity with a bandwidth of 40 basis points above and below the midpoint. For the 2023 test year, however, the bandwidth provisions of the formula rate plan were
temporarily suspended and, pursuant to the terms of the global stipulated settlement agreement, Entergy Louisiana implemented the September 2024 formula rate plan rate adjustments effective with the first billing cycle of September 2024. Those adjustments included a $120 million increase in base rider formula rate plan revenue and a $101.8 million one-time incremental net decrease consistent with the terms of the global stipulated settlement. The formula rate plan rate adjustments reflected in the evaluation report also include a redetermination of the transmission recovery mechanism, the distribution recovery mechanism, the additional capacity mechanism, the tax adjustment mechanism, the MISO cost recovery mechanism, and other one-time adjustments. In January 2025, Entergy Louisiana and the LPSC filed a joint report indicating that no disputed issues remained in the proceeding and requesting that the LPSC issue an order accepting Entergy Louisiana’s evaluation report and, ultimately, resolving this matter. Entergy Louisiana expects a decision on the joint report in first quarter 2025.

Investigation of Costs Billed by Entergy Services

In November 2018 the LPSC issued a notice of proceeding initiating an investigation into costs incurred by Entergy Services that are included in the retail rates of Entergy Louisiana. As stated in the notice of proceeding, the LPSC observed an increase in capital construction-related costs incurred by Entergy Services. Discovery was issued and included efforts to seek highly detailed information on a broad range of matters unrelated to the scope of the audit. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” above for further discussion.

COVID-19 Orders

In April 2020 the LPSC issued an order authorizing utilities to record as a regulatory asset expenses incurred from the suspension of disconnections and collection of late fees imposed by LPSC orders associated with the COVID-19 pandemic. In April 2023, Entergy Louisiana filed an application proposing to utilize approximately $1.6 billion in certain low interest debt to generate earnings to apply toward the reduction of the COVID-19 regulatory asset, as well as to conduct additional outside right-of-way vegetation management activities and fund the minor storm reserve account. In that filing, Entergy Louisiana proposed to delay repayment of certain shorter-term first mortgage bonds that were issued to finance storm restoration costs until the costs could be securitized, and to invest the funds that otherwise would be used to repay those bonds in the money pool to take advantage of the spread between prevailing interest rates on investments in the money pool and the interest rates on the bonds. The LPSC approved Entergy Louisiana’s requested relief in June 2023. In November 2024, Entergy Louisiana submitted a filing to the LPSC requesting that the LPSC review Entergy Louisiana’s computation of the COVID-19 regulatory asset as well as Entergy Louisiana’s proposal to offset the regulatory asset against the interest earned on the short-term debt funds, resulting in no increased costs to customers. At the time of the filing, Entergy Louisiana had a regulatory asset of $47.8 million for costs associated with the COVID-19 pandemic. As of December 31, 2024, Entergy Louisiana had a regulatory liability of $48.9 million for the deferred earnings related to the approximately $1.6 billion in low interest debt, which had been fully repaid by August 2024. In granting Entergy Louisiana’s requested relief in June 2023, the LPSC ordered that any amount of earnings exceeding the amount of the COVID-19 regulatory asset be transferred to Entergy Louisiana’s storm reserve escrow account.

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 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.

Filings with the MPSC (Entergy Mississippi)

Retail Rates

2022 Formula Rate Plan Filing

In March 2022, Entergy Mississippi submitted its formula rate plan 2022 test year filing and 2021 look-back filing showing Entergy Mississippi’s earned return for the historical 2021 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2022 calendar year to be below the formula rate plan bandwidth. The 2022 test year filing showed a $69 million rate increase was necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.70% return on rate base, within the formula rate plan bandwidth. The change in formula rate plan revenues, however, was capped at 4% of retail revenues, which equated to a revenue change of $48.6 million. The 2021 look-back filing compared actual 2021 results to the approved benchmark return on rate base and reflected the need for a $34.5 million interim increase in formula rate plan revenues. In fourth quarter 2021, Entergy Mississippi recorded a regulatory asset of $19 million to reflect the then-current estimate in connection with the look-back feature of the formula rate plan. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $24.3 million interim rate increase, reflecting a cap equal to 2% of 2021 retail revenues, effective in April 2022. With the implementation of the interim formula rate plan rates, Entergy Mississippi began recovery of the bad debt expense deferral resulting from the COVID-19 pandemic over a three-year period.

In June 2022, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed the 2022 test year filing that resulted in a total rate increase of $48.6 million. Pursuant to the joint stipulation, Entergy Mississippi’s 2021 look-back filing reflected an earned return on rate base of 5.99% in calendar year 2021, which was below the look-back bandwidth, resulting in a $34.3 million increase in the formula rate plan revenues on an interim basis through June 2023. In July 2022 the MPSC approved the joint stipulation with rates effective in August 2022. In July 2022, Entergy Mississippi recorded regulatory credits of $22.6 million to reflect the effects of the joint stipulation.
In July 2022 the MPSC directed Entergy Mississippi to flow $14.1 million of the power management rider over-recovery balance to customers beginning in August 2022 through December 2022 to mitigate the bill impact of the increase in formula rate plan revenues.

2023 Formula Rate Plan Filing

In March 2023, Entergy Mississippi submitted its formula rate plan 2023 test year filing and 2022 look-back filing showing Entergy Mississippi’s earned return on rate base for the historical 2022 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2023 calendar year to be below the formula rate plan bandwidth. The 2023 test year filing showed a $39.8 million rate increase was necessary to reset Entergy Mississippi’s earned return on rate base to the specified point of adjustment of 6.67%, within the formula rate plan bandwidth. The 2022 look-back filing compared actual 2022 results to the approved benchmark return on rate base and reflected the need for a $19.8 million temporary increase in formula rate plan revenues, including the refund of a $1.3 million over-recovery resulting from the demand-side management costs true-up for 2022. In fourth quarter 2022, Entergy Mississippi recorded a regulatory asset of $18.2 million in connection with the look-back feature of the formula rate plan to reflect that the 2022 estimated earned return was below the formula rate plan bandwidth. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $27.9 million interim rate increase, reflecting a cap equal to 2% of 2022 retail revenues, effective in April 2023.

In May 2023, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed a 2023 test year filing resulting in a total revenue increase of $26.5 million for 2023. Pursuant to the joint stipulation, Entergy Mississippi’s 2022 look-back filing reflected an earned return on rate base of 6.10% in calendar year 2022, which was below the look-back bandwidth, resulting in a $19.0 million increase in the formula rate plan revenues on an interim basis through June 2024. Entergy Mississippi recorded a regulatory credit of $0.8 million in June 2023 to reflect the increase in the look-back regulatory asset. In addition, certain long-term service agreement and conductor handling costs were authorized for realignment from the formula rate plan to the annual power management and grid modernization riders effective January 2023, resulting in regulatory credits recorded in June 2023 of $4.1 million and $4.3 million, respectively. Also, the amortization of Entergy Mississippi’s COVID-19 bad debt expense deferral was suspended for calendar year 2023, but resumed in July 2024. In June 2023 the MPSC approved the joint stipulation with rates effective in July 2023.

2024 Formula Rate Plan Filing

In March 2024, Entergy Mississippi submitted its formula rate plan 2024 test year filing and 2023 look-back filing showing Entergy Mississippi’s earned return on rate base for the historical 2023 calendar year to be within the formula rate plan bandwidth and projected earned return for the 2024 calendar year to be below the formula rate plan bandwidth. The 2024 test year filing showed a $63.4 million rate increase was necessary to reset Entergy Mississippi’s earned return on rate base to the specified point of adjustment of 7.10%, within the formula rate plan bandwidth. The 2023 look-back filing compared actual 2023 results to the approved benchmark return on rate base and reflected no change in formula rate plan revenues. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $32.6 million interim rate increase, reflecting a cap equal to 2% of 2023 retail revenues, effective April 2024.

In December 2014 the MPSC ordered Entergy Mississippi to file an updated depreciation study at least once every four years. Pursuant to this order and Entergy Mississippi’s filing cycle, Entergy Mississippi would have filed an updated depreciation report with its formula rate plan filing in 2023. However, in July 2022 the MPSC directed Entergy Mississippi to file its next depreciation study in connection with its 2024 formula rate plan filing notwithstanding the MPSC’s prior order. Accordingly, Entergy Mississippi filed a depreciation study in February 2024. The study showed a need for an increase in annual depreciation expense of $55.2 million. The calculated increase in annual depreciation expense was excluded from Entergy Mississippi’s 2024 formula rate plan revenue increase request because the MPSC had not yet approved the proposed depreciation rates.
In June 2024, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed the 2024 test year filing, with the exception of immaterial adjustments to certain operation and maintenance expenses. After performance adjustments, the formula rate plan reflected an earned return on rate base of 6.08% for calendar year 2024, which resulted in a total revenue increase of $64.6 million for 2024. The joint stipulation also recommended approval of a revised customer charge of $31.82 per month for residential customers and $53.10 per month for general service customers. Pursuant to the stipulation, Entergy Mississippi’s 2023 look-back filing reflected an earned return on rate base of 6.81%, resulting in an increase of $0.3 million in the formula rate plan revenues for 2023. Finally, the stipulation recommended approval of Entergy Mississippi’s proposed depreciation rates with those rates to be implemented upon request and approval at a later date. In June 2024 the MPSC approved the joint stipulation with rates effective in July 2024. The approval also included a reduction to the energy cost factor, resulting in a net bill decrease for a typical residential customer using 1,000 kWh per month. Also in June 2024, Entergy Mississippi recorded regulatory credits of $7.3 million to reflect the difference between interim rates placed in effect in April 2024 and the rates reflected in the joint stipulation.

In May 2024, Entergy Mississippi received approval from the MPSC for formula rate plan revisions that were necessary for Entergy Mississippi to comply with state legislation passed in January 2024. The legislation allows Entergy Mississippi to make interim rate adjustments 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 filed the first of its annual interim facilities rate adjustment reports in May 2024 to recover approximately $8.7 million of these costs over a six-month period with rates effective beginning in July 2024. Entergy Mississippi filed its second annual interim facilities rate adjustment report in December 2024 to recover approximately $46.7 million of these costs over a 12-month period with rates effective beginning in January 2025.

Grand Gulf Capacity Filing

In September 2024, Entergy Mississippi filed a notice of intent with the MPSC to implement revisions to its unit power cost recovery rider that would allow Entergy Mississippi to recover the first year of costs associated with the transfer of Entergy Louisiana’s entitlements to Grand Gulf capacity and energy, which consists of Energy Louisiana’s interest in and purchases of Grand Gulf capacity and energy under the revised rider schedule, effective by January 1, 2025. This notice filing related to the divestiture of Entergy Louisiana’s 14% share of Grand Gulf capacity and energy under the Unit Power Sales Agreement and 2.43% share of capacity and energy from Entergy Arkansas under the MSS-4 replacement tariff. This divestiture is being effectuated initially through Entergy Mississippi’s purchases from Entergy Louisiana pursuant to a PPA governed by the MSS-4 replacement tariff, a tariff governing the sales of energy and capacity among the Utility operating companies as described in the System Energy global settlement with the LPSC and Entergy Louisiana. The MSS-4 replacement PPA to effectuate this divestiture was approved by the FERC in November 2024. In February 2025 the MPSC approved Entergy Mississippi’s notice of intent, finding that it was just and reasonable for Entergy Mississippi to obtain Entergy Louisiana’s entitlements to Grand Gulf capacity and energy and that Entergy Mississippi should be allowed to recover the costs associated with the transfer of such entitlements to Grand Gulf capacity and energy, as described above. The MPSC approved the MSS-4 replacement PPA, effective as of January 1, 2025. See “Complaints Against System Energy – System Energy Settlement with the LPSC” below for further details of the System Energy global settlement with the LPSC and Note 8 to the financial statements for discussion of the Unit Power Sales Agreement.

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.

Filings with the City Council (Entergy New Orleans)

Retail Rates

2022 Formula Rate Plan Filing

In April 2022, Entergy New Orleans submitted to the City Council its formula rate plan 2021 test year filing. The 2021 test year evaluation report, subsequently updated in a July 2022 filing, produced an earned return on equity of 6.88% compared to the authorized return on equity of 9.35%. Entergy New Orleans sought approval of a $42.1 million rate increase based on the formula set by the City Council in the 2018 rate case. The formula resulted in an increase in authorized electric revenues of $34.1 million and an increase in authorized gas revenues of $3.3 million. Entergy New Orleans also sought to commence collecting $4.7 million in electric revenues that were previously approved by the City Council for collection through the formula rate plan. In July 2022 the City Council’s advisors issued a report seeking a reduction to Entergy New Orleans’s proposed increase of approximately $17.1 million in total for electric and gas revenues. Effective with the first billing cycle of September 2022, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council including adjustments filed in the City Council’s advisors’ report, per the approved process for formula rate plan implementation. The total formula rate plan increase implemented was $24.7 million, which includes an increase of $18.2 million in electric revenues, $4.7 million in previously approved electric revenues, and an increase of $1.8 million in gas revenues. Additionally, credits of $13.9 million funded by certain regulatory liabilities currently held by Entergy New Orleans for customers were issued over an eight-month period beginning September 2022.

2023 Formula Rate Plan Filing

In April 2023, Entergy New Orleans submitted to the City Council its formula rate plan 2022 test year filing. The 2022 test year evaluation report produced an electric earned return on equity of 7.34% and a gas earned return on equity of 3.52% compared to the authorized return on equity for each of 9.35%. Entergy New Orleans sought approval of a $25.6 million rate increase based on the formula set by the City Council in the 2018 rate case. The formula would result in an increase in authorized electric revenues of $17.4 million and an increase in authorized gas revenues of $8.2 million. Entergy New Orleans also sought to commence collecting $3.4 million in electric revenues that were previously approved by the City Council for collection through the formula rate plan. In July 2023, Entergy New Orleans filed a report to decrease its requested formula rate plan revenues by approximately $0.5 million to account for minor errors discovered after the filing. The City Council advisors issued a report seeking a reduction in the requested formula rate plan revenues of approximately $8.3 million, combined for electric and gas, due to alleged errors. The City Council advisors proposed additional rate mitigation in the amount of $12 million through offsets to the formula rate plan rate increase by certain regulatory liabilities. In September 2023 the City Council approved an agreement to settle the 2023 formula rate plan filing. Effective with the first billing cycle of September 2023, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council, per the approved process for formula rate plan implementation. The agreement provides for a total increase in electric revenues of $10.5 million and a total increase in gas revenues of
$6.9 million. The agreement also provides for a minor storm accrual of $0.5 million per year and the distribution of $8.9 million of currently held customer credits to implement the City Council advisors’ mitigation recommendations.

Request for Extension and Modification of Formula Rate Plan

In September 2023, Entergy New Orleans filed a motion seeking City Council approval of a three-year extension of Entergy New Orleans’s electric and gas formula rate plans. In October 2023 the City Council granted Entergy New Orleans’s request for an extension, subject to minor modifications which included a 55% equity ratio for rate setting purposes.

2024 Formula Rate Plan Filing

In April 2024, Entergy New Orleans submitted to the City Council its formula rate plan 2023 test year filing. Without the requested rate change in 2024, the 2023 test year evaluation report produced an electric earned return on equity of 8.66% and a gas earned return on equity of 5.87% compared to the authorized return on equity for each of 9.35%. Entergy New Orleans sought approval of a $12.6 million rate increase based on the formula set by the City Council in the 2018 rate case and approved again by the City Council in 2023. The formula would result in an increase in authorized electric revenues of $7.0 million and an increase in authorized gas revenues of $5.6 million. Following City Council review, the City Council’s advisors issued a report in July 2024 seeking a reduction in Entergy New Orleans’s requested formula rate plan revenues in an aggregate amount of approximately $1.6 million for electric and gas together due to alleged errors. Effective with the first billing cycle of September 2024, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council, per the approved process for formula rate plan implementation. The total formula rate plan increase implemented was $11.2 million, which includes an increase of $5.8 million in electric revenues and an increase of $5.4 million in gas revenues.

Filings with the PUCT and Texas Cities (Entergy Texas)

Retail Rates

2022 Base Rate Case

In July 2022, Entergy Texas filed a base rate case with the PUCT seeking a net increase in base rates of approximately $131.4 million. The base rate case was based on a 12-month test year ending December 31, 2021. Key drivers of the requested increase were changes in depreciation rates as the result of a depreciation study and an increase in the return on equity. In addition, Entergy Texas included capital additions placed into service for the period of January 1, 2018 through December 31, 2021, including those additions reflected in the then-effective distribution and transmission cost recovery factor riders and the generation cost recovery rider, all of which were reset to zero in June 2023 as a result of this proceeding. In July 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In October 2022 intervenors filed direct testimony challenging and supporting various aspects of Entergy Texas’s rate case application. The key issues addressed included the appropriate return on equity, generation plant deactivations, depreciation rates, and proposed tariffs related to electric vehicles. In November 2022 the PUCT staff filed direct testimony addressing a similar set of issues and recommending a reduction of $50.7 million to Entergy Texas’s overall cost of service associated with the requested net increase in base rates of approximately $131.4 million. Entergy Texas filed rebuttal testimony in November 2022.

In May 2023, Entergy Texas filed on behalf of the parties an unopposed settlement resolving all issues in the proceeding, except for issues related to electric vehicle charging infrastructure which were eventually severed to a separate proceeding and resolved in October 2024, and Entergy Texas filed an agreed motion for interim rates, subject to refund or surcharge to the extent that the interim rates differ from the final approved rates. The unopposed settlement reflected a net base rate increase to be effective and relate back to December 2022 of
$54 million, exclusive of, and incremental to, the costs being realigned from the distribution and transmission cost recovery factor riders and the generation cost recovery rider and $4.8 million of rate case expenses to be recovered through a rider over a period of 36 months. The net base rate increase of $54 million includes updated depreciation rates and a total annual revenue requirement of $14.5 million for the accrual of a self-insured storm reserve and the recovery of the regulatory assets for the pension and postretirement benefits expense deferral, costs associated with the COVID-19 pandemic, and retired non-advanced metering system electric meters. In May 2023 the ALJ with the State Office of Administrative Hearings granted the motion for interim rates, which became effective in June 2023. Additionally, the ALJ remanded the proceeding to the PUCT to consider the settlement. In August 2023 the PUCT issued an order approving the unopposed settlement. Concurrently, Entergy Texas recorded the reversal of $21.9 million of regulatory liabilities to reflect the recognition of certain receipts by Entergy Texas under affiliated PPAs that have been resolved.

Following the PUCT’s approval of the unopposed settlement in August 2023, Entergy Texas recorded a regulatory liability of $10.3 million, which reflected the net effects of higher depreciation and amortizations for the relate back period, partially offset by the relate back of base rate revenues that would have been collected had the approved rates been in effect for the period from December 2022 through June 2023, the date the new base rates were implemented on an interim basis. In October 2023, Entergy Texas filed a relate back surcharge rider to collect over six months beginning in January 2024 an additional approximately $24.6 million, which was the revenue requirement associated with the relate back of rates from December 2022 through June 2023, including carrying costs, as authorized by the PUCT’s August 2023 order. In November 2023, Entergy Texas filed an amended relate back surcharge rider to collect approximately $24.1 million based on a revised carrying cost rate. The amended relate back surcharge rider was approved by the PUCT in December 2023. The higher depreciation and amortizations for the relate back period were also recognized over the six months beginning in January 2024, resulting in no effect on net income from the collection of the relate back surcharge rider.

Distribution Cost Recovery Factor (DCRF) Rider

In June 2024, Entergy Texas filed with the PUCT a request to set a new DCRF rider. The new rider was designed to collect from Entergy Texas’s retail customers approximately $40.3 million annually based on its capital invested in distribution between January 1, 2022 and March 31, 2024. In September 2024 the PUCT approved the DCRF rider, consistent with Entergy Texas’s as-filed request, and rates became effective with the first billing cycle in October 2024.

In September 2024, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $48.9 million annually, or $8.6 million in incremental annual revenues beyond Entergy Texas’s then-effective DCRF rider based on its capital invested in distribution between April 1, 2024 and June 30, 2024. In December 2024, Entergy Texas filed an errata to revise its DCRF application for minor corrections, which decreased the requested annual revenue requirement to $48.5 million. The amended request represented an incremental increase of $8.2 million in annual revenues beyond Entergy Texas’s then-effective DCRF rider. Also in December 2024 the PUCT approved the DCRF rider, consistent with Entergy Texas’s filed errata, and rates became effective on December 20, 2024.

Transmission Cost Recovery Factor (TCRF) Rider

In December 2018, Entergy Texas filed with the PUCT a request to set a new TCRF rider. The new TCRF rider was designed to collect approximately $2.7 million annually from Entergy Texas’s retail customers based on its capital invested in transmission between January 1, 2018 and September 30, 2018. In April 2019 parties filed testimony proposing a load growth adjustment, which would fully offset Entergy Texas’s proposed TCRF revenue requirement. In July 2019 the PUCT granted Entergy Texas’s application as filed to begin recovery of the requested $2.7 million annual revenue requirement, rejecting opposing parties’ proposed adjustment; however, the PUCT found that the question of prudence of the actual investment costs should be determined in Entergy Texas’s next rate case similar to the procedure used for the costs recovered through the DCRF rider. In October 2019 the PUCT
issued an order on a motion for rehearing, clarifying and affirming its prior order granting Entergy Texas’s application as filed. Also in October 2019 a second motion for rehearing was filed, and Entergy Texas filed a response in opposition to the motion. The second motion for rehearing was overruled by operation of law. In December 2019, Texas Industrial Energy Consumers filed an appeal to the PUCT order in district court alleging that the PUCT erred in declining to apply a load growth adjustment.

In October 2021, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $66.1 million annually, or $15.1 million in incremental annual revenues beyond Entergy Texas’s then-effective TCRF rider based on its capital invested in transmission between September 1, 2020 and July 31, 2021 and changes in approved transmission charges. In January 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In February 2022 the parties filed an unopposed settlement recommending that Entergy Texas be allowed to collect its full requested TCRF revenue requirement with interim rates effective March 2022. In February 2022 the ALJ granted the motion for interim rates, admitted evidence, and remanded the case to the PUCT for consideration of a final order at a future open meeting. In June 2022 the PUCT issued an order approving the settlement.

In October 2024, Entergy Texas filed with the PUCT a request to amend its TCRF rider, which was previously reset to zero in June 2023 as a result of the 2022 base rate case. The proposed rider is designed to collect from Entergy Texas’s retail customers approximately $9.7 million annually based on its capital invested in transmission between January 1, 2022 and June 30, 2024 and changes in other transmission charges. In December 2024 the PUCT staff filed a recommendation that the PUCT approve Entergy Texas’s as-filed application. In February 2025 the PUCT staff issued a proposed order that, if approved by the PUCT, would approve Entergy Texas’s TCRF rider as filed.

Generation Cost Recovery Rider

In October 2020, Entergy Texas filed an application to establish a generation cost recovery rider to begin recovering a return of and on its generation capital investment in the Montgomery County Power Station. Entergy Texas filed an unopposed settlement agreement in December 2020, and the PUCT approved the generation cost recovery rider settlement rates on an interim basis in January 2021. In March 2021, Entergy Texas filed to update its generation cost recovery rider, and an unopposed settlement agreement filed by Entergy Texas on behalf of the parties in October 2021 was approved by the PUCT in January 2022. In February 2022, Entergy Texas filed a relate-back rider to collect over five months an additional approximately $5 million, which was the difference between the interim revenue requirement approved in January 2021 and the revenue requirement approved in January 2022 reflecting Entergy Texas’s full generation capital investment and ownership in Montgomery County Power Station on January 1, 2021, plus carrying costs from January 2021 through January 2022 when the updated revenue requirement took effect. The PUCT approved the relate-back rider consistent with Entergy Texas’s as-filed request, and rates became effective over a five-month period, in August 2022.

In December 2020, Entergy Texas also filed an application to amend its generation cost recovery rider to reflect its acquisition of the Hardin County Peaking Facility, which closed in June 2021. Because Hardin was to be acquired in the future, the initial generation cost recovery rider rates proposed in the application represented no change from the generation cost recovery rider rates established in Entergy Texas’s previous generation cost recovery rider proceeding. In July 2021 the PUCT issued an order approving the application. In August 2021, Entergy Texas filed an update application to recover its actual investment in the acquisition of the Hardin County Peaking Facility, and in January 2022, Entergy Texas filed an update to its application to align the requested revenue requirement with the terms of the generation cost recovery rider settlement approved by the PUCT in January 2022. In April 2022, Entergy Texas filed on behalf of the parties a unanimous settlement agreement that would adjust its generation cost recovery rider to recover an annual revenue requirement of approximately $92.8 million, which was $4.5 million in incremental annual revenue above the revenue requirement approved in January 2022 described above and related to Entergy Texas’s investment in the Montgomery County Power Station. The PUCT approved the settlement agreement and rates became effective in August 2022. In September 2022,
Entergy Texas filed a relate-back rider designed to collect over three months an additional approximately $5.7 million, which is the revenue requirement, plus carrying costs, associated with Entergy Texas’s acquisition of Hardin County Peaking Facility from June 2021 through August 2022 when the updated revenue requirement took effect. In April 2023 the PUCT approved Entergy Texas’s as-filed request with rates effective over three months beginning in May 2023.
Entergy Arkansas Opportunity Sales Proceeding

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

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

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

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

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

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

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

In October 2018 the FERC issued an order addressing the ALJ’s July 2017 initial decision. The FERC reversed the ALJ’s decision to cap the reduction in Entergy Arkansas’s payment to account for the increased bandwidth payments that Entergy Arkansas made to the other operating companies. The FERC also reversed the ALJ’s decision that Grand Gulf sales from January through September 2000 should be included in the calculation of Entergy Arkansas’s payment. The FERC affirmed on other grounds the ALJ’s rejection of the LPSC’s claim that certain joint account sales should be accounted for as part of the calculation of Entergy Arkansas’s payment. In November 2018 the LPSC requested rehearing of the FERC’s October 2018 decision. In December 2019 the FERC denied the LPSC’s request for rehearing. In January 2020 the LPSC appealed the December 2019 decision to the D.C. Circuit.
In December 2018, Entergy made a compliance filing in response to the FERC’s October 2018 order. The compliance filing provided a final calculation of Entergy Arkansas’s payments to the other Utility operating companies, including interest. No protests were filed in response to the December 2018 compliance filing. Refunds and interest in the following amounts were paid by Entergy Arkansas to the other operating companies in December 2018:
 Total refunds including interest
Payment/(Receipt)
 (In Millions)
PrincipalInterestTotal
Entergy Arkansas$68$67$135
Entergy Louisiana($30)($29)($59)
Entergy Mississippi($18)($18)($36)
Entergy New Orleans($3)($4)($7)
Entergy Texas($17)($16)($33)

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

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

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

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

In July 2020 the APSC issued a decision finding that Entergy Arkansas’s application is not in the public interest. The order also directed Entergy Arkansas to refund to its retail customers within 30 days of the order the FERC-determined over-collection of $13.7 million, plus interest, associated with a recalculated bandwidth remedy. In addition to these primary findings, the order also denied the Attorney General’s request for Entergy Arkansas to prepare a compliance filing detailing all of the retail impacts from the opportunity sales and denied a request by the Arkansas Electric Energy Consumers to recalculate all costs using the revised responsibility ratio. Entergy Arkansas filed a motion for temporary stay of the 30-day requirement to allow Entergy Arkansas a reasonable opportunity to seek rehearing of the APSC order, but in July 2020 the APSC denied Entergy Arkansas’s request for a stay and directed Entergy Arkansas to refund to its retail customers the component of the total FERC-determined opportunity sales payment that was associated with increased bandwidth remedy payments of $13.7 million, plus interest. The refunds were issued in the August 2020 billing cycle. While the APSC denied Entergy Arkansas’s stay request, Entergy Arkansas believes its actions were prudent and, therefore, the costs, including the $13.7 million, plus interest, are recoverable. In July 2020, Entergy Arkansas requested rehearing of the APSC order, which rehearing was denied by the APSC in August 2020. In September 2020, Entergy Arkansas filed a complaint in the U.S. District Court for the Eastern District of Arkansas challenging the APSC’s order denying Entergy Arkansas’s request to recover the costs of these payments. In October 2020 the APSC filed a motion to dismiss Entergy Arkansas’s complaint, to which Entergy Arkansas responded. Also in December 2020, Entergy Arkansas and the APSC held a pre-trial conference, and filed a report with the court in January 2021. The court held a hearing in February 2021 regarding issues addressed in the pre-trial conference report, and in June 2021 the court stayed all discovery until it rules on pending motions, after which the court will issue an amended schedule if necessary. In March 2022 the court denied the APSC’s motion to dismiss, and, in April 2022, issued a scheduling order including a trial date in February 2023. In June 2022, Entergy Arkansas filed a motion asserting that it is entitled to summary judgment because Entergy Arkansas’s position that the APSC’s order is pre-empted by the filed rate doctrine and violates the Dormant Commerce Clause is premised on facts that are not subject to genuine dispute. In July 2022, Arkansas Electric Energy Consumers, Inc., an industrial customer association, filed a motion to intervene and to hold Entergy Arkansas’s motion for summary judgment in abeyance pending a ruling on the motion to intervene. Entergy Arkansas filed a consolidated opposition to both motions. In August 2022 the APSC filed a motion for summary judgment arguing that there is no genuine issue as to any material fact and the APSC is entitled to judgment as a matter of law. In September 2022, Entergy Arkansas filed an opposition to the motion. In October 2022 the APSC filed a motion asking the court to hold further proceedings in abeyance pending a decision on the motions for summary judgment filed by Entergy Arkansas and the APSC. Also in October 2022, Entergy Arkansas filed an opposition to the motion, and the APSC filed a reply in support of its motion for summary judgment. In January 2023 the judge assigned to the case, on her own motion, identified facts that may present a conflict and recused herself; a new judge was assigned to the case, but he also recused due to a conflict. The case again was reassigned to a new judge. In January 2023 the court denied all pending motions (including those described above) except for a motion by the APSC to exclude certain testimony and further ruled that the matter would proceed to trial. In January 2023, Arkansas Electric Energy Consumers, Inc. filed a notice of appeal of the court’s order denying its motion to intervene to the United States Court of Appeals for the Eighth Circuit and a motion with the district court to stay the proceedings pending the appeal, which was denied. In February 2023, Arkansas Electric Energy Consumers, Inc. filed a motion with the United States Court of Appeals for the Eighth Circuit to stay the proceedings pending the appeal, which also was denied. The trial was held in February 2023. Following the trial, Entergy Arkansas filed a motion with the United States Court of Appeals for the Eighth Circuit to expedite the appeal filed by Arkansas Electric Energy Consumers, Inc. The United States Court of Appeals for
the Eighth Circuit granted Entergy Arkansas’s request, and oral arguments were held in June 2023. In August 2023 the United States Court of Appeals for the Eighth Circuit affirmed the order of the court denying Arkansas Electric Energy Consumers, Inc.’s motion to intervene.

In March 2024 the U.S. District Court for the Eastern District of Arkansas issued a judgment in favor of the APSC and against Entergy Arkansas. In March 2024 Entergy Arkansas filed a notice of appeal and a motion to expedite oral arguments with the United States Court of Appeals for the Eighth Circuit and the court granted the motion to expedite. Briefing to the United States Court of Appeals for the Eighth Circuit concluded in July 2024 and oral arguments concluded in September 2024. As a result of the adverse decision by the U.S. District Court for the Eastern District of Arkansas, Entergy Arkansas concluded that it could no longer support the recognition of its $131.8 million regulatory asset reflecting the previously-expected recovery of a portion of the costs at issue in the opportunity sales proceeding and recorded a $131.8 million ($99.1 million net-of-tax) charge to earnings in first quarter 2024. In December 2024 the United States Court of Appeals for the Eighth Circuit affirmed the decision of the U.S. District Court for the Eastern District of Arkansas, and Entergy Arkansas filed a petition for rehearing en banc. In January 2025 the United States Court of Appeals for the Eighth Circuit denied Entergy Arkansas’s petition. Entergy Arkansas is evaluating a petition for certiorari with the United States Supreme Court.
MSS-4 Replacement Tariff – Net Operating Loss Carryforward Proceeding

In January 2021, pursuant to section 205 of the Federal Power Act, Entergy Services filed an amendment to the MSS-4 replacement tariff, a tariff governing the sales of energy and capacity among the Utility operating companies, in order to provide for the inclusion of specified accumulated deferred income taxes, including net operating loss carryforward accumulated deferred income taxes (NOLC ADIT), in the rate for sales of energy among the Utility operating companies on a prospective basis. In March 2021, the FERC accepted the filing, subject to refund and hearing procedures.

In October 2021 the LPSC filed a complaint with the FERC alleging that Entergy Services improperly excluded NOLC ADIT from MSS-4 replacement tariff rates in the period before March 20, 2021. The LPSC argued that sales from Entergy Louisiana to Entergy Texas and Entergy New Orleans were charged at rates lower than they otherwise should have been, and it accordingly seeks surcharges for the period prior to March 20, 2021. The FERC set the complaint for hearing procedures and subsequently the hearing for this complaint proceeding was consolidated with the hearing procedures for Entergy Services’ January 2021 NOLC ADIT filing.

Testimony was filed by parties in 2023, and the hearing before a FERC ALJ was concluded in February 2024. In June 2024, the FERC ALJ issued an initial decision addressing three major issues: (1) whether Entergy Services’ proposed prospective inclusion and allocation of NOLC ADIT in MSS-4 replacement tariff rates using a modified with-and-without methodology is just and reasonable; (2) whether Entergy Services correctly calculated excess and deficient accumulated deferred income taxes in accordance with the terms of a prior settlement; and (3) whether NOLC ADIT should have been included in MSS-4 replacement tariff rates prior to the effective date of the January 2021 MSS-4 replacement tariff filing.

With respect to issues (1) and (2), the presiding ALJ concluded that Entergy Services’ proposed methodology for allocating and including NOLC ADIT in MSS-4 replacement tariff rates was just and reasonable and that Entergy Services correctly performed the excess and deficient accumulated deferred income taxes calculations. With respect to issue (3), however, the presiding ALJ agreed with the LPSC that NOLC ADIT should have been included in MSS-4 replacement tariff rates since September 1, 2016, and as a result, the presiding ALJ ordered that Entergy Louisiana and Entergy Arkansas recalculate bills for the period of September 1, 2016 through November 11, 2023 with surcharges expected to be due to those operating companies from the purchasing operating companies, Entergy New Orleans, Entergy Texas, and Entergy Louisiana (for some Entergy Arkansas sales). The presiding ALJ also ordered Entergy Services to pay the interest owed to Entergy Louisiana on these surcharges.
The surcharge methodology that the presiding ALJ recommended in connection with issue (3) was not supported by any participant in the hearing. As part of their exceptions to the initial decision, all parties to the proceeding opposed the use of the ALJ’s methodology, except for the FERC trial staff, which took no position. During the hearing, the LPSC and the FERC trial staff advocated that the alleged tariff violation should be remedied by the application of Entergy Services’ January 2021 proposed methodology. All other parties, including the PUCT, the City Council, and Entergy Services, opposed any surcharges for the period prior to the March 20, 2021 effective date of the January 2021 filing.

Entergy Services disputes the presiding ALJ's rulings on issue (3) and filed exceptions to these rulings in July 2024. The ALJ's initial decision is not binding on the FERC and is an interim step in the hearing process. No refunds will be owed in connection with this proceeding unless and until the FERC requires them in a final order.
Complaints Against System Energy

System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf.  System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. System Energy and the Unit Power Sales Agreement have been the subject of several litigation proceedings at the FERC, including challenges with respect to System Energy’s authorized return on equity and capital structure, renewal of its sale-leaseback arrangement, treatment of uncertain tax positions, a broader investigation of rates under the Unit Power Sales Agreement, and two prudence complaints, one challenging the extended power uprate completed at Grand Gulf in 2012 and the operation and management of Grand Gulf, particularly in the 2016-2020 time period, and the second challenging the operation and management of Grand Gulf in the 2021-2022 time period. Settlements that resolve all significant aspects of these complaints have been reached with the MPSC, the APSC, the City Council, and the LPSC, and these settlements have been approved by the FERC. Following are discussions of the proceedings.

Return on Equity and Capital Structure Complaints

In January 2017 the APSC and the MPSC filed a complaint with the FERC against System Energy. The complaint sought a reduction in the return on equity component of the Unit Power Sales Agreement pursuant to which System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. Entergy Arkansas also sells some of its Grand Gulf capacity and energy to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under separate agreements. The return on equity under the Unit Power Sales Agreement at the time of the complaint was 10.94%, which was established in a rate proceeding that became final in July 2001.

The APSC and the MPSC complaint alleged that the return on equity was unjust and unreasonable because capital market and other considerations indicated that it was excessive. The complaint requested proceedings to investigate the return on equity and establish a lower return on equity, and also requested that the FERC establish January 23, 2017 as a refund effective date. The complaint included a return on equity analysis that purported to establish that the range of reasonable return on equity for System Energy was between 8.37% and 8.67%. System Energy answered the complaint in February 2017 and disputed that a return on equity of 8.37% to 8.67% was just and reasonable. The LPSC and the City Council intervened in the proceeding expressing support for the complaint. In September 2017 the FERC established a refund effective date of January 23, 2017 and directed the parties to engage in settlement proceedings before an ALJ. The parties were unable to settle the return on equity issue and a FERC hearing judge was assigned in July 2018. The 15-month refund period in connection with the APSC/MPSC complaint expired on April 23, 2018.

In April 2018 the LPSC filed a complaint with the FERC against System Energy seeking an additional 15-month refund period.  The LPSC complaint requested similar relief from the FERC with respect to System Energy’s
return on equity and also requested the FERC to investigate System Energy’s capital structure.  The APSC, the MPSC, and the City Council intervened in the proceeding, filed an answer expressing support for the complaint, and asked the FERC to consolidate this proceeding with the proceeding initiated by the complaint of the APSC and the MPSC in January 2017. System Energy answered the LPSC complaint in May 2018 and also filed a motion to dismiss the complaint. In August 2018 the FERC issued an order dismissing the LPSC’s request to investigate System Energy’s capital structure and setting for hearing the return on equity complaint, with a refund effective date of April 27, 2018. The 15-month refund period in connection with the LPSC return on equity complaint expired on July 26, 2019.

The portion of the LPSC’s complaint dealing with return on equity was subsequently consolidated with the APSC and the MPSC complaint for hearing. The parties also addressed an order (issued in a separate FERC proceeding involving New England transmission owners) that proposed modifying the FERC’s standard methodology for determining return on equity. In September 2018 the LPSC filed an amended complaint raising the same capital structure claim the FERC had earlier dismissed. The FERC initiated a new proceeding for the amended capital structure complaint, and System Energy answered the complaint in October 2018. In January 2019 the FERC set the amended complaint for settlement and hearing proceedings. Settlement proceedings in the capital structure proceeding commenced in February 2019, but were terminated in June 2019, and the amended capital structure complaint was consolidated with the ongoing return on equity proceeding. The 15-month refund period in connection with the capital structure complaint was from September 24, 2018 to December 23, 2019.

Several rounds of testimony were filed by the parties in these proceedings between January 2019 and August 2020. Some of these rounds of testimony were precipitated by developments in an unrelated proceeding in which the FERC issued orders addressing the methodology for determining the return on equity applicable to transmission owners in MISO (Opinion Nos. 569 and 569-A). The final positions of the parties, after the submission of all pre-filed testimony, were as follows. With regard to the return on equity complaints for the first refund period, based on their respective interpretations and applications of the Opinion No. 569-A methodology, the LPSC argued for an authorized return on equity for System Energy of 7.97%; the MPSC and the APSC argued for an authorized return on equity of 9.24%; and the FERC trial staff argued for an authorized return on equity of 9.49%. For the second refund period and on a prospective basis, based on their respective interpretations and applications of the Opinion No. 569-A methodology, the LPSC argued for an authorized return on equity for System Energy of 7.78%; the MPSC and the APSC argued that an authorized return on equity of 9.15% may be appropriate if the second complaint was not dismissed; and the FERC trial staff argued for an authorized return on equity of 9.09% if the second complaint was not dismissed. The LPSC also continued to support as its primary recommendation, based on an alternative analysis to the Opinion No. 569-A methodology, an authorized return on equity for System Energy as low as 7.56% for the first complaint refund period and as low as 7.18% for the second complaint refund period and prospectively. The MPSC and the APSC also continued to support as their primary recommendation, based on an alternative analysis to the Opinion No. 569-A methodology, an authorized return on equity for System Energy as low as 8.26% for the first complaint refund period and as low as 8.32% for the second complaint refund period and prospectively. System Energy argued that strict application of the Opinion No. 569-A methodology produces results inconsistent with investor requirements and does not provide a sound basis on which to evaluate System Energy’s authorized return on equity. Therefore, as its primary recommendation, System Energy argued for the use of a methodology that incorporates four separate financial models and, based on application of this recommended methodology, an authorized return on equity of 10.12% for the first refund period, which also fell within the presumptively just and reasonable range calculated for the second refund period and prospectively. Under the Opinion No. 569-A methodology, System Energy calculated an authorized return on equity of 9.44% for the first refund period, which also fell within the presumptively just and reasonable range calculated for the second refund period and prospectively.

With regard to the capital structure, the LPSC’s primary recommendation was that the FERC establish a hypothetical capital structure for System Energy for ratemaking purposes, according to which System Energy’s common equity ratio would be set to Entergy Corporation’s equity ratio of 37% equity and 63% debt. The APSC and the MPSC recommended that 35.98% be set as the common equity ratio for System Energy. The FERC trial
staff argued that the average capital structure of the proxy group used to develop System Energy’s return on equity should be used to establish the capital structure. Using this approach, the FERC trial staff calculated the average capital structure for its proposed proxy group of 46.74% common equity and 53.26% debt. System Energy disputed all of these recommendations and argued that the use of its actual capital structure was just and reasonable.

After conducting a hearing, in March 2021 the FERC ALJ issued an initial decision. With regard to System Energy’s authorized return on equity, the ALJ determined that the existing return on equity of 10.94% was no longer just and reasonable, and that the replacement authorized return on equity, based on application of the Opinion No. 569-A methodology, should be 9.32%. The ALJ further determined that System Energy should pay refunds for a fifteen-month refund period (January 2017-April 2018) based on the difference between the current return on equity and the replacement authorized return on equity. The ALJ determined that the April 2018 complaint concerning the authorized return on equity should be dismissed, and that no refunds for a second fifteen-month refund period should be due. With regard to System Energy’s capital structure, the ALJ determined that System Energy’s actual equity ratio was excessive and that the just and reasonable equity ratio was 48.15% equity, based on the average equity ratio of the proxy group used to evaluate the return on equity for the second complaint. The ALJ further determined that System Energy should pay refunds for a fifteen-month refund period (September 2018-December 2019) based on the difference between the actual equity ratio and the 48.15% equity ratio.

In April 2021, System Energy filed its brief on exceptions, in which it challenged the initial decision’s findings on both the return on equity and capital structure issues. Also in April 2021 the LPSC, the APSC, the MPSC, the City Council, and the FERC trial staff filed briefs on exceptions. Reply briefs opposing exceptions were filed in May 2021 by System Energy, the FERC trial staff, the LPSC, the APSC, the MPSC, and the City Council.

As discussed below in “System Energy Settlement with the MPSC,” “System Energy Settlement with the APSC,” “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the MPSC, the APSC, the City Council, and the LPSC have settled their claims related to these proceedings. As part of the settlements with their respective retail regulators, effective July 2022 for Entergy Mississippi, November 2023 for Entergy Arkansas, June 2024 for Entergy New Orleans, and September 2024 for Entergy Louisiana, bills issued under the Unit Power Sales Agreement reflect a return on equity of 9.65% and a capital structure not to exceed 52% equity.

In August 2022 the D.C. Circuit issued an order addressing appeals of FERC’s Opinion No. 569 and 569-A, which established the methodology applied in the ALJ’s initial decision in the proceeding against System Energy discussed above. The appellate order addressed the methodology for determining the return on equity applicable to transmission owners in MISO. The D.C. Circuit found the FERC’s use of the Risk Premium model as part of the methodology to be arbitrary and capricious, and remanded the case back to the FERC. In October 2024, after System Energy had reached settlements with each of the retail regulators involved in the return on equity and capital structure proceeding discussed above, the FERC issued a remand order in the MISO transmission owners’ return on equity case, concluding that the record supported the methodology that it originally directed in Opinion No. 569 utilizing an equal weighting of the two-step discounted cash flow model and capital asset pricing model. As a result, it determined that the just and reasonable return on equity for the MISO transmission owners is 9.98%. In light of the System Energy settlements detailed below, the FERC’s changes to its return on equity methodology in the decision on the MISO transmission owners’ return on equity will not have any immediate effect on System Energy’s return on equity because System Energy’s return on equity has been set at 9.65% through the global settlement through the end of June 2026.

Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue

In May 2018 the LPSC filed a complaint against System Energy and Entergy Services related to System Energy’s renewal of a sale-leaseback transaction originally entered into in December 1988 for an 11.5% undivided interest in Grand Gulf Unit 1. The complaint alleged that System Energy violated the filed rate and the FERC’s ratemaking and accounting requirements when it included in Unit Power Sales Agreement billings the cost of
capital additions associated with the sale-leaseback interest, and that System Energy was double-recovering costs by including both the lease payments and the capital additions in Unit Power Sales Agreement billings. The complaint also claimed that System Energy was imprudent in entering into the sale-leaseback renewal because the Utility operating companies that purchase Grand Gulf’s output from System Energy could have obtained cheaper capacity and energy in the MISO markets. The complaint further alleged that System Energy violated various other reporting and accounting requirements and should have sought prior FERC approval of the lease renewal. The complaint sought various forms of relief from the FERC, including refunds for capital addition costs for all years in which they were recorded in allegedly non-formula accounts or, alternatively, the disallowance of the return on equity for the capital additions in those years plus interest; a disallowance and refund of the lease costs of the sale-leaseback renewal on grounds of imprudence; an investigation into System Energy’s treatment of a DOE litigation payment; and the imposition of certain forward-looking procedural protections, including audit rights for retail regulators of the Unit Power Sales Agreement formula rates. The APSC, the MPSC, and the City Council intervened in the proceeding.

In June 2018, System Energy and Entergy Services filed a motion to dismiss and an answer to the LPSC complaint denying that System Energy’s treatment of the sale-leaseback renewal and capital additions violated the terms of the filed rate or any other FERC ratemaking, accounting, or legal requirements or otherwise constituted double recovery. The response also argued that the complaint was inconsistent with a FERC-approved settlement to which the LPSC is a party and that explicitly authorized System Energy to recover its lease payments. Finally, the response argued that both the capital additions and the sale-leaseback renewal were prudent investments and the LPSC complaint failed to justify any disallowance or refunds. The response also offered to submit formula rate protocols for the Unit Power Sales Agreement similar to the procedures used for reviewing transmission rates under the MISO tariff. In September 2018 the FERC issued an order setting the complaint for hearing and settlement proceedings and establishing a refund effective date of May 18, 2018.

In February 2019 the presiding ALJ ruled that the hearing ordered by the FERC includes the issue of whether specific subcategories of accumulated deferred income tax should be included in, or excluded from, System Energy’s formula rate. Testimony was filed by the LPSC, the MPSC, the APSC, the City Council, the FERC trial staff, and System Energy between March 2019 and October 2019. The final positions of the parties, after all pre-filed testimony was submitted, were as follows. The LPSC sought refunds that included the renewal lease payments (approximately $17.2 million per year since July 2015), rate base reductions for accumulated deferred income tax associated with uncertain tax positions (with a corresponding refund of approximately $512 million), and the cost of capital additions associated with the sale-leaseback interest, as well as interest on those amounts. The LPSC also argued that adjustments to depreciation rates should require retroactive depreciation expense refunds but only prospective rate base adjustments. The APSC, the MPSC, and the City Council generally agreed with the LPSC’s positions. The FERC trial staff argued for refunds for rate base reductions for liabilities associated with uncertain tax positions, and also argued that System Energy recovered $32 million more than it should have in depreciation expense for capital additions. System Energy filed testimony asking the FERC to reject all of the LPSC’s claims for refunds and opposing the FERC trial staff’s position regarding the uncertain tax position issue. System Energy also argued that the FERC trial staff’s position regarding depreciation rates for capital additions was not unreasonable, but any change in depreciation expense is only one element of a Unit Power Sales Agreement re-billing calculation. Adjustments to depreciation expense in any re-billing under the Unit Power Sales Agreement formula rate would also involve changes to accumulated depreciation, accumulated deferred income taxes, and other formula elements as needed.

After holding a hearing in November 2019, in April 2020 the FERC ALJ issued the initial decision. Among other things, the ALJ determined that refunds were due on three main issues. First, with regard to the lease renewal payments, the ALJ determined that System Energy was recovering an unjust acquisition premium through the lease renewal payments, and that System Energy’s recovery from customers through rates should be limited to the cost of service based on the remaining net book value of the leased assets, which was approximately $70 million. The ALJ found that the remedy for this issue should be the refund of lease payments (approximately $17.2 million per year since July 2015) with interest determined at the FERC quarterly interest rate, which would be offset by the addition
of the net book value of the leased assets in the cost of service. The ALJ did not calculate a value for the refund expected as a result of this remedy. In addition, System Energy would no longer recover the lease payments in rates prospectively. Second, with regard to the liabilities associated with uncertain tax positions, the ALJ determined that the liabilities are accumulated deferred income taxes and that System Energy’s rate base should have been reduced for those liabilities. The ALJ also found that System Energy should include liabilities associated with uncertain tax positions as a rate base reduction going forward. Third, with regard to the depreciation expense adjustments, the ALJ found that System Energy should correct for the error in re-billings retroactively and prospectively, but that System Energy should not be permitted to recover interest on any retroactive return on enhanced rate base resulting from such corrections.

In June 2020, System Energy, the LPSC, and the FERC trial staff filed briefs on exceptions, challenging several of the initial decision’s findings. System Energy’s brief on exceptions challenged the initial decision’s limitations on recovery of the lease renewal payments, its proposed rate base refund for the liabilities associated with uncertain tax positions, and its proposal to asymmetrically treat interest on bill corrections for depreciation expense adjustments. The LPSC’s and the FERC trial staff’s briefs on exceptions each challenged the initial decision’s allowance for recovery of the cost of service associated with the lease renewal based on the remaining net book value of the leased assets, its calculation of the remaining net book value of the leased assets, and the amount of the initial decision’s proposed rate base refund for the liabilities associated with uncertain tax positions. The LPSC’s brief on exceptions also challenged the initial decision’s proposal that depreciation expense adjustments include retroactive adjustments to rate base and its finding that section 203 of the Federal Power Act did not apply to the lease renewal. The FERC trial staff’s brief on exceptions also challenged the initial decision’s finding that the FERC need not institute a formal investigation into System Energy’s tariff. In October 2020, System Energy, the LPSC, the MPSC, the APSC, and the City Council filed briefs opposing exceptions. System Energy opposed the exceptions filed by the LPSC and the FERC trial staff. The LPSC, the MPSC, the APSC, the City Council, and the FERC trial staff opposed the exceptions filed by System Energy. Also in October 2020 the MPSC, the APSC, and the City Council filed briefs adopting the exceptions of the LPSC and the FERC trial staff.

In addition, in September 2020, the IRS issued a Notice of Proposed Adjustment (NOPA) and Entergy executed it. The NOPA memorialized the IRS’s decision to adjust the 2015 consolidated federal income tax return of Entergy Corporation and certain of its subsidiaries, including System Energy, with regard to the uncertain decommissioning tax position. Pursuant to the audit resolution documented in the NOPA, the IRS allowed System Energy’s inclusion of $102 million of future nuclear decommissioning costs in System Energy’s cost of goods sold for the 2015 tax year, roughly 10% of the requested deduction, but disallowed the balance of the position. In September 2020, System Energy filed a motion to lodge the NOPA into the record in the FERC proceeding. In October 2020 the LPSC, the APSC, the MPSC, the City Council, and the FERC trial staff filed oppositions to System Energy’s motion. As a result of the NOPA issued by the IRS in September 2020, System Energy filed, in October 2020, a new Federal Power Act section 205 filing at FERC to establish an ongoing rate base credit for the accumulated deferred income taxes resulting from the decommissioning uncertain tax position. On a prospective basis beginning with the October 2020 bill, System Energy proposed to include the accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position as a credit to rate base under the Unit Power Sales Agreement. In November 2020 the LPSC, the APSC, the MPSC, and the City Council filed a protest to the filing, and System Energy responded.

In November 2020 the IRS issued a Revenue Agent’s Report (RAR) for the 2014/2015 tax year and in December 2020 Entergy executed it. The RAR contained the same adjustment to the uncertain nuclear decommissioning tax position as that which the IRS had announced in the NOPA. In December 2020, System Energy filed a motion to lodge the RAR into the record in the FERC proceeding addressing the uncertain tax position rate base issue. In January 2021 the LPSC, the APSC, the MPSC, and the City Council filed a protest to the motion.

As a result of the RAR, in December 2020, System Energy filed amendments to its new Federal Power Act section 205 filings to establish an ongoing rate base credit for the accumulated deferred income taxes resulting from
the decommissioning uncertain tax position and to credit excess accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position. The amendments both proposed the inclusion of the RAR as support for the filings. In December 2020 the LPSC, the APSC, and the City Council filed protests to the amendments. In February 2021 the FERC issued an order accepting System Energy’s Federal Power Act section 205 filings subject to refund, setting them for hearing, and holding the hearing in abeyance.

In December 2020, System Energy filed a new Federal Power Act section 205 filing to provide a one-time, historical credit of $25.2 million for the accumulated deferred income taxes that would have been created by the decommissioning uncertain tax position if the IRS’s decision had been known in 2016. In January 2021 the LPSC, APSC, MPSC, and City Council filed a protest to the filing. In February 2021 the FERC issued an order accepting System Energy’s Federal Power Act section 205 filing subject to refund, setting it for hearing, and holding the hearing in abeyance. System Energy provided the one-time credit during the first quarter 2021.

In December 2022 the FERC issued an order on the ALJ’s initial decision, which affirmed it in part and modified it in part. The FERC’s order directed System Energy to calculate refunds on three issues, and to provide a compliance report detailing the calculations. The FERC’s order also disallowed the future recovery of sale-leaseback renewal costs, which is estimated at approximately $11.5 million annually for purchases from Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans through July 2036. The three refund issues were rental expenses related to the renewal of the sale-leaseback arrangements; refunds, if any, for the revenue requirement impact of including accumulated deferred income taxes resulting from the decommissioning uncertain tax positions from 2004 through the present; and refunds for the net effect of correcting the depreciation inputs for capital additions attributable to the portion of plant subject to the sale-leaseback.

As a result of the FERC order’s directives regarding the recovery of the sale-leaseback transaction, in December 2022 System Energy reduced the Grand Gulf sale-leaseback regulatory liability by $56 million, reduced the related accumulated deferred income tax asset by $94 million, and reduced the Grand Gulf sale-leaseback accumulated deferred income tax regulatory liability by $25 million, resulting in an increase in income tax expense of $13 million. In addition, the FERC determined that System Energy recognized excess depreciation expense related to property subject to the sale-leaseback. As a result, in December 2022, System Energy recorded a reduction in depreciation expense and the related accumulated depreciation of $33 million.

In January 2023, System Energy filed its compliance report with the FERC. With respect to the sale-leaseback renewal costs, System Energy calculated a refund of $89.8 million, which represented all of the sale-leaseback renewal rental costs that System Energy recovered in rates, with interest. With respect to the decommissioning uncertain tax position issue, System Energy calculated that no additional refunds were owed because it had already provided a one-time historical credit (for the period January 2016 through September 2020) of $25.2 million based on the accumulated deferred income taxes that resulted from the IRS’s partial acceptance of the decommissioning tax position, and because it has been providing an ongoing rate base credit for the accumulated deferred income taxes that resulted from the IRS’s partial acceptance of the decommissioning tax position since October 2020. With respect to the depreciation refund, System Energy calculated a refund of $13.7 million, which is the net total of a refund to customers for excess depreciation expense previously collected, plus interest, offset by the additional return on rate base that System Energy previously did not collect, without interest. See “System Energy Settlement with the MPSC” below for discussion of the regulatory charge and corresponding regulatory liability recorded in June 2022 related to these proceedings. In January 2023, System Energy paid the refunds of $103.5 million, which included refunds of $41.7 million to Entergy Arkansas, $27.8 million to Entergy Louisiana, and $34 million to Entergy New Orleans.

In February 2023 the LPSC, the APSC, and the City Council filed protests to System Energy’s January 2023 compliance report, in which they challenged System Energy’s calculation of the refunds associated with the decommissioning tax position but did not protest the other components of the compliance report. Each of them argued that System Energy should have paid additional refunds for the decommissioning tax position issue, and the City Council estimated the total additional refunds owed to customers of Entergy Louisiana, Entergy New Orleans,
and Entergy Arkansas for that issue as $493 million, including interest (and without factoring in the $25.2 million refund that System Energy already paid in 2021).

In January 2023, System Energy filed a request for rehearing of the FERC’s determinations in the December 2022 order on sale-leaseback refund issues and future lease cost disallowances, the FERC’s prospective policy on uncertain tax positions, and the proper accounting of System Energy’s accumulated deferred income taxes adjustment for the Tax Cuts and Jobs Act of 2017; and a motion for confirmation of its interpretation of the December 2022 order’s remedy concerning the decommissioning tax position. In January 2023 the retail regulators filed a motion for confirmation of their interpretation of the refund requirement in the December 2022 FERC order and a provisional request for rehearing. In February 2023 the FERC issued a notice that the rehearing requests were denied by operation of law. In March 2023, System Energy filed in the United States Court of Appeals for the Fifth Circuit a petition for review of the December 2022 order. In March 2023, System Energy also filed an unopposed motion to stay the proceeding in the Fifth Circuit pending the FERC’s disposition of the pending motions, and the court granted the motion to stay.

In February 2023, System Energy submitted a tariff compliance filing with the FERC to clarify that, consistent with the releases provided in the MPSC settlement, Entergy Mississippi will continue to be charged for its allocation of the sale-leaseback renewal costs under the Unit Power Sales Agreement. See “System Energy Settlement with the MPSC” below for discussion of the settlement. In March 2023 the MPSC filed a protest to System Energy’s tariff compliance filing. The MPSC argues that the settlement did not specifically address post-settlement sale-leaseback renewal costs and that the sale-leaseback renewal costs may not be recovered under the Unit Power Sales Agreement. Entergy Mississippi’s allocated sale-leaseback renewal costs are estimated at $5.7 million annually for the remaining term of the sale-leaseback renewal.

In August 2023 the FERC issued an order addressing arguments raised on rehearing and partially setting aside the prior order (rehearing order). The rehearing order addressed rehearing requests that were filed in January 2023 separately by System Energy and the LPSC, the APSC, and the City Council.

In the rehearing order, the FERC directed System Energy to recalculate refunds for two issues: (1) refunds of rental expenses related to the renewal of the sale-leaseback arrangements and (2) refunds for the net effect of correcting the depreciation inputs for capital additions associated with the sale-leaseback. With regard to the sale-leaseback renewal rental expenses, the rehearing order allowed System Energy to recover an implied return of and on the depreciated cost of the portion of the plant subject to the sale-leaseback as of the expiration of the initial lease term. With regard to the depreciation input issue, the rehearing order allowed System Energy to offset refunds so that System Energy may collect interest on the rate base recalculations that were part of the overall depreciation rate recalculations. The rehearing order further directed System Energy to submit within 60 days of the date of the rehearing order an additional compliance filing to revise the total refunds for these two issues. As discussed above, System Energy’s January 2023 compliance filing calculated $103.5 million in total refunds, and the refunds were paid in January 2023. In October 2023, System Energy filed its compliance report with the FERC as directed in the August 2023 rehearing order. The October 2023 compliance report reflected recalculated refunds totaling $35.7 million for the two issues resulting in $67.8 million in refunds that could be recouped by System Energy. As discussed below in “System Energy Settlement with the APSC,” System Energy reached a settlement in principle with the APSC to resolve several pending cases under the FERC’s jurisdiction, including this one, pursuant to which it agreed not to recoup the $27.3 million calculated for Entergy Arkansas in the compliance filing. As a result of the FERC’s rulings on the sale-leaseback and depreciation input issues in the August 2023 rehearing order, in third quarter 2023, System Energy recorded a regulatory asset and corresponding regulatory credit of $40 million to reflect the portion of the January 2023 refunds to be recouped from Entergy Louisiana and Entergy New Orleans. Consistent with the compliance filing, in October 2023, Entergy Louisiana and Entergy New Orleans paid recoupment amounts of $18.2 million and $22.3 million, respectively, to System Energy.
On the third refund issue identified in the rehearing requests, concerning the decommissioning uncertain tax positions, the rehearing order denied all rehearing requests, re-affirmed the remedy contained in the December 2022 order, and did not direct System Energy to recalculate refunds or to submit an additional compliance filing.

In September 2023, System Energy filed a protective appeal of the rehearing order with the United States Court of Appeals for the Fifth Circuit. The appeal was consolidated with System Energy’s prior appeal of the December 2022 order.

In September 2023 the LPSC filed with the FERC a request for rehearing and clarification of the rehearing order. The LPSC requested that the FERC reverse its determination in the rehearing order that System Energy may collect an implied return of and on the depreciated cost of the portion of the plant subject to the sale-leaseback, as of the expiration of the initial lease term, as well as its determination in the rehearing order that System Energy may offset the refunds for the depreciation rate input issue and collect interest on the rate base recalculations that were part of the overall depreciation rate recalculations. In addition, the LPSC requested that the FERC either confirm the LPSC’s interpretation of the refund associated with the decommissioning uncertain tax positions or explain why it is not doing so. In October 2023 the FERC issued a notice that the rehearing request was deemed denied by operation of law. In November 2023 the FERC issued a further notice stating that it would not issue any further order addressing the rehearing request. Also in November 2023 the LPSC filed with the United States Court of Appeals for the Fifth Circuit a petition for review of the FERC’s August 2023 rehearing order and denials of the September 2023 rehearing request.

In December 2023 the United States Court of Appeals for the Fifth Circuit lifted the abeyance on the consolidated System Energy appeals and it also consolidated the LPSC’s appeal with the System Energy appeals. Briefing of the appeals occurred between March 2024 and July 2024. In September 2024 the parties filed a joint motion to continue and stay oral argument, previously scheduled for October 2024, pending the FERC’s decision whether to approve the settlement between System Energy and the LPSC, and the United States Court of Appeals for the Fifth Circuit granted the motion. In November 2024, after the FERC issued the order approving the settlement between System Energy and the LPSC, System Energy, the LPSC, the APSC, and the FERC filed a joint stipulation to dismiss the pending appeals, which the United States Court of Appeals for the Fifth Circuit granted.

As discussed below in “System Energy Settlement with the MPSC,” “System Energy Settlement with the APSC,” “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the MPSC, the APSC, the City Council, and the LPSC have settled their claims related to this proceeding.

LPSC Additional Complaints

In May 2020 the LPSC authorized its staff to file additional complaints at the FERC related to the rates charged by System Energy for Grand Gulf energy and capacity supplied to Entergy Louisiana under the Unit Power Sales Agreement. The LPSC directive noted that the initial decision issued by the presiding ALJ in the Grand Gulf sale-leaseback complaint proceeding did not address, for procedural reasons, certain rate issues raised by the LPSC and declined to order further investigation of rates charged by System Energy.

Unit Power Sales Agreement Complaint

The first of the additional complaints was filed by the LPSC, the APSC, the MPSC, and the City Council in September 2020. The first complaint raised two sets of rate allegations: violations of the filed rate and a corresponding request for refunds for prior periods; and elements of the Unit Power Sales Agreement are unjust and unreasonable and a corresponding request for refunds for the 15-month refund period and changes to the Unit Power Sales Agreement prospectively. Several of the filed rate allegations overlapped with the previous complaints. The filed rate allegations not previously raised were that System Energy: failed to provide a rate base credit to customers for the “time value” of sale-leaseback lease payments collected from customers in advance of the time those payments were due to the owner-lessors; improperly included certain sale-leaseback transaction costs in rate base as
prepayments; improperly included nuclear refueling outage costs in rate base; wrongly included categories of accumulated deferred income taxes as increases to rate base; charged customers based on a higher equity ratio than would be appropriate due to excessive retained earnings; and did not correctly reflect money pool investments and imprudently invested cash into the money pool. The elements of the Unit Power Sales Agreement that the complaint alleged were unjust and unreasonable include: the current cash working capital allowance of zero, uncapped recovery of incentive and executive compensation, lack of an equity re-opener, and recovery of lobbying and private airplane travel expenses. The complaint also requested a rate investigation into the Unit Power Sales Agreement and System Energy’s billing practices pursuant to section 206 of the Federal Power Act, including any issue relevant to the Unit Power Sales Agreement and its inputs. System Energy filed its answer opposing the complaint in November 2020. In its answer, System Energy argued that all of the claims raised in the complaint should be dismissed and agreed that bill adjustment with respect to two discrete issues were justified. System Energy argued that dismissal was warranted because all claims fell into one or more of the following categories: the claims had been raised and were being litigated in another proceeding; the claims did not present a prima facie case and did not satisfy the threshold burden to establish a complaint proceeding; the claims were premised on a theory or request relief that is incompatible with federal law or FERC policy; the claims request relief that is inconsistent with the filed rate; the claims were barred or waived by the legal doctrine of laches; and/or the claims had been fully addressed and do not warrant further litigation. In December 2020, System Energy filed a bill adjustment report indicating that $3.4 million had been credited to customers in connection with the two discrete issues concerning the inclusion of certain accumulated deferred income taxes balances in rates.

In May 2021 the FERC issued an order addressing the complaint, establishing a refund effective date of September 21, 2020, establishing hearing procedures, and holding those procedures in abeyance pending the FERC’s review of the initial decision in the Grand Gulf sale-leaseback renewal complaint discussed above. System Energy agreed that the hearing should be held in abeyance but sought rehearing of FERC’s decision as related to matters set for hearing that were beyond the scope of FERC’s jurisdiction or authority. The complainants sought rehearing of FERC’s decision to hold the hearing in abeyance and filed a motion to proceed, which motion System Energy opposed. In June 2021, System Energy’s request for rehearing was denied by operation of law, and System Energy filed an appeal of FERC’s orders in the Court of Appeals for the Fifth Circuit. In November 2021 the Fifth Circuit dismissed the appeal as premature.

In August 2021 the FERC issued an order addressing System Energy’s and the complainants’ rehearing requests. The FERC dismissed part of the complaint seeking an equity re-opener, maintained the abeyance for issues related to the proceeding addressing the sale-leaseback renewal and uncertain tax positions, lifted the abeyance for issues unrelated to that proceeding, and clarified the scope of the hearing.

In November 2021 the LPSC, the APSC, and the City Council filed direct testimony and requested the FERC to order refunds for prior periods and prospective amendments to the Unit Power Sales Agreement. The LPSC’s refund claims included, among other things, allegations that: (1) System Energy should not have included certain sale-leaseback transaction costs in prepayments; (2) System Energy should have credited rate base to reflect the time value of money associated with the advance collection of lease payments; (3) System Energy incorrectly included refueling outage costs that were recorded in account 174 in rate base; and (4) System Energy should have excluded several accumulated deferred income tax balances in account 190 from rate base. The LPSC also sought a retroactive adjustment to retained earnings and capital structure in conjunction with the implementation of its proposed refunds. In addition, the LPSC sought amendments to the Unit Power Sales Agreement going forward to address below-the-line costs, incentive compensation, the working capital allowance, litigation expenses, and the 2019 termination of the capital funds agreement. The APSC argued that: (1) System Energy should have included borrowings from the Entergy system money pool in its determination of short-term debt in its cost of capital; and (2) System Energy should credit customers with System Energy’s allocation of earnings on money pool investments. The City Council alleged that System Energy has maintained excess cash on hand in the money pool and that retention of excess cash was imprudent. Based on this allegation, the City Council’s witness recommended a refund of approximately $98.8 million for the period 2004-September 2021 or other alternative relief. The City Council
further recommended that the FERC impose a hypothetical equity ratio such as 48.15% equity to capital on a prospective basis.

In January 2022, System Energy filed answering testimony arguing that the FERC should not order refunds for prior periods or any prospective amendments to the Unit Power Sales Agreement. In response to the LPSC’s refund claims, System Energy argued, among other things, that: (1) the inclusion of sale-leaseback transaction costs in prepayments was correct; (2) that the filed rate doctrine bars the request for a retroactive credit to rate base for the time value of money associated with the advance collection of lease payments; (3) that an accounting misclassification for deferred refueling outage costs had been corrected, caused no harm to customers, and requires no refunds; and (4) that its accounting and ratemaking treatment of specified accumulated deferred income tax balances in account 190 had been correct. System Energy further responded that no retroactive adjustment to retained earnings or capital structure should be ordered because there was no general policy requiring such a remedy, and there was no showing that the retained earnings element of the capital structure was incorrectly implemented. Further, System Energy presented evidence that all of the costs that were being challenged were long known to the retail regulators and were approved by them for inclusion in retail rates, and the attempt to retroactively challenge these costs, some of which had been included in rates for decades, was unjust and unreasonable. In response to the LPSC’s proposed going-forward adjustments, System Energy presented evidence to show that none of the proposed adjustments were needed. On the issue of below-the-line expenses, during discovery procedures System Energy identified a historical allocation error in certain months and agreed to provide a bill credit to customers to correct the error. In response to the APSC’s claims, System Energy argued that the Unit Power Sales Agreement did not include System Energy’s borrowings from the Entergy system money pool or earnings on deposits to the Entergy system money pool in the determination of the cost of capital; and accordingly, no refunds were appropriate on those issues. In response to the City Council’s claims, System Energy argued that it has reasonably managed its cash and that the City Council’s theory of cash management was defective because it failed to adequately consider the relevant cash needs of System Energy and it made faulty presumptions about the operation of the Entergy system money pool. System Energy further pointed out that the issue of its capital structure was already subject to pending FERC litigation.

In March 2022 the FERC trial staff filed direct and answering testimony in response to the LPSC, the APSC, and the City Council’s direct testimony. In its testimony, the FERC trial staff recommended refunds for two primary reasons: (1) it concluded that System Energy should have excluded specified accumulated deferred income tax balances in account 190 associated with rate refunds; and (2) it concluded that System Energy should have excluded specified accumulated deferred income tax balances in account 190 associated with a deemed contract satisfaction and reissuance that occurred in 2005. The FERC trial staff recommended refunds of $84.1 million, exclusive of any tax gross-up or FERC interest. In addition, the FERC trial staff recommended the following prospective modifications to the Unit Power Sales Agreement: (1) inclusion of a rate base credit to recognize the time value of money associated with the advance collection of lease payments; (2) exclusion of executive incentive compensation costs for members of the Office of the Chief Executive and long-term performance unit costs where awards are based solely or primarily on financial metrics; and (3) exclusion of unvested, accrued amounts for stock options, performance units, and restricted stock awards. With respect to issues that ultimately concerned the reasonableness of System Energy’s rate of return, the FERC trial staff stated that it was unnecessary to consider such issues in the proceeding, in light of the pending case concerning System Energy’s return on equity and capital structure. On all other material issues raised by the LPSC, the APSC, and the City Council, the FERC trial staff recommended either no refunds or no modification to the Unit Power Sales Agreement.

In April 2022, System Energy filed cross-answering testimony in response to the FERC trial staff’s recommendations of refunds for the accumulated deferred income taxes issues and proposed modifications to the Unit Power Sales Agreement for the executive incentive compensation issues. In June 2022 the FERC trial staff submitted revised answering testimony, in which it recommended additional refunds associated with the accumulated deferred income tax balances in account 190 associated with a deemed contract satisfaction and reissuance that occurred in 2005. Based on the testimony revisions, the FERC trial staff’s recommended refunds total $106.6 million, exclusive of any tax gross-up or FERC awarded interest. Also in June 2022, System Energy
filed revised and supplemental cross-answering testimony to respond to the FERC trial staff’s testimony and oppose its revised recommendation.

In May 2022 the LPSC, the APSC, and the City Council filed rebuttal testimony. The LPSC’s testimony asserted new claims, including that: (1) certain of the sale-leaseback transaction costs may have been imprudently incurred; (2) accumulated deferred income taxes associated with sale-leaseback transaction costs should have been included in rate base; (3) accumulated deferred income taxes associated with federal investment tax credits should have been excluded from rate base; (4) monthly net operating loss accumulated deferred income taxes should have been excluded from rate base; and (5) several categories of proposed rate changes, including executive incentive compensation, air travel, industry dues, and legal costs, also warranted historical refunds. The LPSC’s rebuttal testimony argued that refunds for the alleged tariff violations and other claims must be calculated by rerunning the Unit Power Sales Agreement formula rate; however, it included estimates of refunds associated with some, but not all, of its claims, totaling $286 million without interest. The City Council’s rebuttal testimony also proposed a new, alternate theory and claim for relief regarding System Energy’s participation in the Entergy system money pool, under which it calculates estimated refunds of approximately $51.7 million. The APSC’s rebuttal testimony agreed with the LPSC’s direct testimony that retained earnings should be adjusted in a comprehensive refund calculation. The testimony quantified the estimated impacts of three issues: (1) a $1.5 million reduction in the revenue requirement under the Unit Power Sales Agreement if System Energy’s borrowings from the money pool were included in short-term debt; (2) a $1.9 million reduction in the revenue requirement if System Energy’s allocated share of money pool earnings were credited through the Unit Power Sales Agreement; and (3) a $1.9 million reduction in the revenue requirement for every $50 million of refunds ordered in a given year, without interest. In total, excluding the settled issues noted below, the claims sought more than $700 million in refunds and interest, based on charges to all Unit Power Sales Agreement purchasers including Entergy Mississippi. The hearing before a FERC ALJ occurred between September and December 2022.

In November 2022, System Energy filed a partial settlement agreement with the APSC, the City Council, and the LPSC that resolved the following issues raised in the Unit Power Sales Agreement complaint: advance collection of lease payments, aircraft costs, executive incentive compensation, money pool borrowings, advertising expenses, deferred nuclear refueling outage costs, industry association dues, and termination of the capital funds agreement. The settlement provided that System Energy would provide a black box refund of $18 million (inclusive of interest), plus additional refund amounts with interest to be calculated for certain issues to be distributed to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans as the Utility operating companies other than Entergy Mississippi purchasing under the Unit Power Sales Agreement. The settlement further provided that if the APSC, the City Council, or the LPSC agreed to the global settlement System Energy entered into with the MPSC (discussed below), and such global settlement included a black box refund amount, then the black box refund for this settlement agreement would not be incremental or in addition to the global black box refund amount. The settlement agreement addressed other matters as well, including adjustments to rate base beginning in October 2022, exclusion of certain other costs, and inclusion of money pool borrowings, if any, in short-term debt within the cost of capital calculation used in the Unit Power Sales Agreement. In April 2023 the FERC approved the settlement agreement. The refund provided for in the settlement agreement was included in the May 2023 service month bills under the Unit Power Sales Agreement.

In May 2023 the presiding ALJ issued an initial decision finding that System Energy should have excluded multiple identified categories of accumulated deferred income taxes from rate base when calculating Unit Power Sales Agreement bills. The initial decision also found that the Unit Power Sales Agreement should be modified such that a cash working capital allowance of negative $36.4 million is applied prospectively. On the other non-settled issues for which the complainants sought refunds or changes to the Unit Power Sales Agreement, the initial decision ruled against the complainants.

System Energy disagreed with the ALJ’s findings concerning the accumulated deferred income taxes issues and cash working capital. In July 2023, System Energy filed a brief on exceptions to the initial decision’s accumulated deferred income taxes findings. Also in July 2023, the APSC, the LPSC, the City Council, and the
FERC trial staff filed separate briefs on exceptions. In August 2023 all parties filed separate briefs opposing exceptions.

As discussed below in “System Energy Settlement with the MPSC,” “System Energy Settlement with the APSC,” and “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the MPSC, the APSC, and the City Council, and the LPSC have settled their claims related to this proceeding.

Grand Gulf Prudence Complaints

The second of the additional complaints was filed at the FERC in March 2021 by the LPSC, the APSC, and the City Council against System Energy, Entergy Services, Entergy Operations, and Entergy Corporation. The second complaint contained two primary allegations. First, it alleged that, based on the plant’s capacity factor and alleged safety performance, System Energy and the other respondents imprudently operated Grand Gulf during the period 2016-2020, and it sought refunds of at least $360 million in alleged replacement energy costs, in addition to other costs, including those that could only be identified upon further investigation. Second, it alleged that the performance and/or management of the 2012 extended power uprate of Grand Gulf was imprudent, and it sought refunds of all costs of the 2012 uprate that were determined to result from imprudent planning or management of the project. In addition to the requested refunds, the complaint asked that the FERC modify the Unit Power Sales Agreement to provide for full cost recovery only if certain performance indicators were met and to require pre-authorization of capital improvement projects in excess of $125 million before related costs could be passed through to customers in rates. In April 2021, System Energy and the other respondents filed their motion to dismiss and answer to the complaint. System Energy requested that the FERC dismiss the claims within the complaint. With respect to the claim concerning operations, System Energy argued that the complaint did not meet its legal burden because, among other reasons, it failed to allege any specific imprudent conduct. With respect to the claim concerning the uprate, System Energy argued that the complaint failed because, among other reasons, the complainants’ own conduct prevented them from raising a serious doubt as to the prudence of the uprate. System Energy also requested that the FERC dismiss other elements of the complaint, including the proposed modifications to the Unit Power Sales Agreement, because they were not warranted. In February 2023 the FERC issued an order denying rehearing and thereby affirming its order setting the complaint for settlement and hearing procedures. In July 2023 the FERC chief ALJ terminated settlement procedures and appointed a presiding ALJ to oversee hearing procedures. In September 2023 a procedural schedule for hearing procedures was established. Also in September 2023 the LPSC authorized its staff to file an additional complaint concerning the prudence of System Energy’s operation and management of Grand Gulf in the year 2022. In October 2023 the LPSC, the APSC, and the City Council filed what they styled as an amended and supplemental complaint with the FERC against System Energy, Entergy Services, and Entergy Operations. In November 2023, System Energy answered the amended and supplemental complaint. Pursuant to the procedural schedule, the complainants’ testimony in the original complaint proceeding was filed in December 2023. System Energy’s answering testimony was filed in May 2024, and the FERC trial staff’s direct and answering testimony was filed in June 2024.

As discussed below in “System Energy Settlement with the APSC,” “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the APSC, the City Council, and the LPSC have settled all of their claims related to this proceeding.

System Energy Settlement with the MPSC

In June 2022, System Energy, Entergy Mississippi, and additional named Entergy parties involved in thirteen docketed proceedings before the FERC filed with the FERC a partial settlement agreement and offer of settlement. The settlement memorialized the Entergy parties’ agreement with the MPSC to globally resolve all actual and potential claims between the Entergy parties and the MPSC associated with those FERC proceedings and with System Energy’s past implementation of the Unit Power Sales Agreement. The Unit Power Sales Agreement is a FERC-jurisdictional formula rate tariff for sales of energy and capacity from System Energy’s owned and
leased share of Grand Gulf to Entergy Mississippi, Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans. Entergy Mississippi purchases the greatest single amount, nearly 40% of System Energy’s share of Grand Gulf, after its additional purchases from affiliates are considered.

The settlement provided for a black box refund of $235 million from System Energy to Entergy Mississippi. In addition, beginning with the July 2022 service month, the settlement provided for Entergy Mississippi’s bills from System Energy to be adjusted to reflect: an authorized rate of return on equity of 9.65%, a capital structure not to exceed 52% equity, a rate base reduction for the advance collection of sale-leaseback rental costs, and the exclusion of certain long-term incentive plan performance unit costs from rates. The settlement was approved by the MPSC in June 2022 and the FERC in November 2022.

System Energy had previously recorded a provision and associated liability of $37 million for elements of the applicable litigation. In June 2022, System Energy recorded a regulatory charge of $551 million ($413 million net-of-tax), increasing the regulatory liability to $588 million, which consisted of $235 million for the settlement with the MPSC and $353 million for potential future refunds to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans. System Energy paid the black box refund of $235 million to Entergy Mississippi in November 2022.

System Energy Settlement with the APSC

In October 2023, System Energy, Entergy Arkansas, and additional named Entergy parties involved in multiple docketed proceedings pending before the FERC reached a settlement in principle with the APSC to globally resolve all of their actual and potential claims in those dockets and with System Energy’s past implementation of the Unit Power Sales Agreement. The settlement also covered the amended and supplemental complaint, discussed above in “Grand Gulf Prudence Complaint,” filed at the FERC in October 2023. System Energy, Entergy Arkansas, additional Entergy parties, and the APSC filed the settlement agreement and supporting materials with the FERC in November 2023.

The terms of the settlement with the APSC aligned with the $588 million global black box settlement reached between System Energy and the MPSC in June 2022 and provided for Entergy Arkansas to receive a black box refund of $142 million from System Energy, inclusive of $49.5 million already received by Entergy Arkansas from System Energy. In addition, beginning with the November 2023 service month, the settlement provided for Entergy Arkansas’s bills from System Energy to be adjusted to reflect an authorized rate of return on equity of 9.65% and a capital structure not to exceed 52% equity. In March 2024 the FERC approved the settlement, and System Energy paid the remaining black box refund of $93 million to Entergy Arkansas in 2024.

System Energy Settlement with the City Council

In April 2024, System Energy, Entergy New Orleans, and additional named Entergy parties involved in multiple docketed proceedings pending before the FERC reached a settlement in principle with the City Council to globally resolve all of their actual and potential claims in those dockets and with System Energy’s past implementation of the Unit Power Sales Agreement. The settlement also covered the amended and supplemental complaint, discussed in “Grand Gulf Prudence Complaints” above, filed by the LPSC, the APSC, and the City Council at the FERC in October 2023. In May 2024, System Energy, Entergy New Orleans, additional named Entergy parties, and the City Council filed the settlement agreement and supporting materials with the FERC.

The terms of the settlement with the City Council aligned with the $588 million global black box settlement amount reflected in the prior settlements reached between System Energy and the MPSC in June 2022 and between System Energy and the APSC in November 2023. The settlement provided for Entergy New Orleans to receive a black box refund of $116 million from System Energy, inclusive of approximately $18 million already received by Entergy New Orleans from System Energy. In addition, beginning with the June 2024 service month, the settlement provided for Entergy New Orleans’s bills from System Energy to be adjusted to reflect an authorized rate of return on equity of 9.65% and a capital structure not to exceed 52% equity. In August 2024 the FERC approved the
settlement, and System Energy paid the remaining black box refund of $98 million to Entergy New Orleans in October 2024.

System Energy Settlement with the LPSC

In July 2024, System Energy and the LPSC staff reached a settlement in principle to globally resolve all of the LPSC’s actual and potential claims in multiple docketed proceedings pending before the FERC (including all docketed proceedings resolved by the MPSC, the APSC, and the City Council settlements) and with System Energy’s past implementation of the Unit Power Sales Agreement. The settlement also covered the amended and supplemental complaint, discussed above in “Grand Gulf Prudence Complaints,” filed by the LPSC, the APSC, and the City Council at the FERC in October 2023. In August 2024 the LPSC approved the settlement. In September 2024 the settling parties filed the settlement for approval by the FERC.

The terms of the settlement with the LPSC staff aligned with the $588 million global black box settlement amount reflected in the prior settlements reached between System Energy and the MPSC in June 2022, between System Energy and the APSC in November 2023, and between System Energy and the City Council in April 2024. The settlement in principle provided for Entergy Louisiana to receive a black box refund of $95 million from System Energy, inclusive of approximately $15 million already received by Entergy Louisiana from System Energy. In addition, beginning with the September 2024 service month, the settlement provided for Entergy Louisiana’s bills from System Energy to be adjusted to reflect an authorized rate of return on equity of 9.65% and a capital structure not to exceed 52% equity. In November 2024 the FERC approved the settlement, and System Energy paid the remaining black box refund of $80 million to Entergy Louisiana in December 2024.

The settlement also included an agreement that, subject to the receipt of necessary regulatory approvals, Entergy Louisiana will divest to Entergy Mississippi all of its interest in Grand Gulf capacity and energy under the Unit Power Sales Agreement and its purchases from Entergy Arkansas under the MSS-4 replacement tariff. In October 2024 Entergy Louisiana and Entergy Mississippi filed with the FERC a PPA under which Entergy Mississippi would purchase Entergy Louisiana’s purchases of Grand Gulf capacity and energy. The PPA is governed by the MSS-4 replacement tariff, a tariff governing the sales of energy and capacity among the Utility operating companies. The requisite approvals for the PPA were issued by the FERC in November 2024 and the MPSC in February 2025. The divestiture is effective as of January 1, 2025.

System Energy Regulatory Liability for Pending Complaints

Prior to June 2022, System Energy recorded a provision and associated liability of $37 million for elements of the complaints against System Energy. In June 2022, as discussed in “System Energy Settlement with the MPSC” above, System Energy recorded a regulatory charge of $551 million ($413 million net-of-tax), increasing System Energy’s regulatory liability to $588 million, which consisted of $235 million for the settlement with the MPSC and $353 million for potential future refunds to Entergy Arkansas, Entergy New Orleans, and Entergy Louisiana. System Energy paid the black box refund of $235 million to Entergy Mississippi in November 2022. As discussed above in “Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue,” in January 2023 System Energy paid refunds of $103.5 million as a result of the FERC’s order in December 2022 in that proceeding and recouped $40.5 million of the $103.5 million from Entergy Louisiana and Entergy New Orleans in October 2023. In addition, as discussed above in “Unit Power Sales Agreement Complaint,” a black box refund of $18 million was made by System Energy in 2023 in connection with a partial settlement in that proceeding. Based on analysis of the then-pending complaints against System Energy and potential future settlement negotiations with the LPSC and the City Council, in third quarter 2023, System Energy recorded a regulatory charge of $40 million to increase System Energy’s regulatory liability related to complaints against System Energy. In December 2023 the $93 million black box refund to Entergy Arkansas was reclassified from the regulatory liability to accounts payable - associated companies on System Energy’s balance sheet. System Energy paid the remaining black box refunds of $93 million to Entergy Arkansas, $98 million to Entergy New Orleans, and $80 million to Entergy Louisiana in 2024.
Unit Power Sales Agreement

System Energy Formula Rate Annual Protocols Formal Challenge Concerning 2020 Calendar Year Bills

System Energy’s Unit Power Sales Agreement includes formula rate protocols that provide for the disclosure of cost inputs, an opportunity for informal discovery procedures, and a challenge process. In February 2022, pursuant to the protocols procedures, the LPSC, the APSC, the MPSC, the City Council, and the Mississippi Public Utilities Staff filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2020. This formal challenge was ultimately settled as a result of System Energy’s global settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” above for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.

System Energy Formula Rate Annual Protocols Formal Challenge Concerning 2021 Calendar Year Bills

In March 2023, pursuant to the protocols procedures discussed above, the LPSC, the APSC, and the City Council filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2021. This formal challenge was ultimately settled as a result of System Energy’s global settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” above for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.

System Energy Formula Rate Annual Protocols Formal Challenge Concerning 2022 Calendar Year Bills

In February 2024, pursuant to the protocols procedures, the LPSC and the City Council filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2022. This formal challenge was ultimately settled as a result of System Energy’s global settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” above for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.

Depreciation Amendment Proceeding

In December 2021, System Energy submitted to the FERC proposed amendments to the Unit Power Sales Agreement to adopt updated rates for use in calculating Grand Gulf plant depreciation and amortization expenses. The proposed amendments would result in higher charges to the Utility operating companies that buy capacity and energy from System Energy under the Unit Power Sales Agreement. In February 2022 the FERC accepted System Energy’s proposed increased depreciation rates with an effective date of March 1, 2022, subject to refund pending the outcome of the settlement and/or hearing procedures. In June 2023 System Energy filed with the FERC an unopposed offer of settlement that it had negotiated with intervenors to the proceeding. In August 2023 the FERC approved the settlement, which resolves the proceeding. In third quarter 2023, System Energy recorded a reduction in depreciation expense of $41 million representing the cumulative difference in depreciation expense resulting from the depreciation rates used from March 2022 through June 2023 and the depreciation rates included in the settlement filing approved by the FERC. In October 2023, System Energy filed a refund report with the FERC. The refund provided for in the refund report was included in the September 2023 service month bills under the Unit Power Sales Agreement. No comments or protests to the refund report were filed.

Pension Costs Amendment Proceeding

In October 2021, System Energy submitted to the FERC proposed amendments to the Unit Power Sales Agreement to include in rate base the prepaid and accrued pension costs associated with System Energy’s qualified pension plans. Based on data ending in 2020, the increased annual revenue requirement associated with the filing is approximately $8.9 million. In March 2022 the FERC accepted System Energy’s proposed amendments with an
effective date of December 1, 2021, subject to refund pending the outcome of the settlement and/or hearing procedures. In August 2023 the FERC chief ALJ terminated settlement procedures and designated a presiding ALJ to oversee hearing procedures. Testimony was filed by the parties from October 2023 through April 2024, and the hearing concluded in June 2024.

In September 2024 the presiding ALJ issued an initial decision recommending that the FERC approve inclusion of a line item in rate base for prepaid and accrued pension costs; however, the presiding ALJ did not agree with System Energy’s proposed methodology to calculate the value of the prepaid and accrued pension cost input. Instead, the presiding ALJ recommended limiting System Energy’s recovery to the prepaid and accrued pension costs that were incurred beginning in 2015 and later.

System Energy disputes the presiding ALJ's determination concerning the methodology used to calculate the prepaid and accrued pension input, and System Energy filed exceptions to these rulings in October 2024. In October 2024, the LPSC, the APSC, and the FERC trial staff filed separate briefs on exceptions; these parties generally argue that the presiding ALJ should have rejected System Energy’s filing entirely, rather than limit System Energy’s recovery of the prepaid and accrued pension costs. Later in October 2024, System Energy, the LPSC, the APSC, and the FERC trial staff filed separate briefs opposing exceptions.

If the ALJ’s determination is affirmed by the FERC, System Energy estimates refunds, including interest through December 31, 2024, of approximately $16 million to $21 million would be owed. The ALJ's initial decision is not binding on the FERC and is an interim step in the hearing process. No refunds will be owed in connection with this proceeding and no changes to System Energy’s pension cost recovery methodology will be implemented unless and until the FERC requires them in a final order. This proceeding is not covered by the global settlements described above.
Storm Cost Recovery Filings with Retail Regulators

Entergy Louisiana

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.

In December 2024, and subsequently amended in an errata filed in February 2025, Entergy Louisiana submitted an application to the LPSC seeking a determination that approximately $183.6 million in storm restoration costs associated with Hurricane Francine were reasonable and necessary and, therefore, eligible for recovery from customers, as well as approval to recover approximately $3.6 million in certain carrying costs from customers. The $183.6 million includes approximately $152.8 million in distribution capital costs and approximately $29.8 million in non-capital costs; the balance consists of transmission and generation capital costs. Entergy Louisiana proposes in its application to recover its distribution-related capital costs of $152.8 million through the distribution recovery mechanism of its formula rate plan. Entergy Louisiana has further requested the LPSC to authorize recovery of these distribution-related capital expenses through an interim rate adjustment, subject to true-up and refund, that would begin with the first billing cycle of March 2025. Entergy Louisiana also requested to recover, from its storm reserve escrow account, $33.5 million, which consists of non-capital costs and certain carrying costs. Entergy Louisiana has also proposed to recover the transmission and generation capital costs through separate ratemaking proceedings. In February 2025, Entergy Louisiana withdrew the $33.5 million from its storm reserve escrow account. The period for intervention has expired, and a status conference for the purpose of establishing a procedural schedule has been set for March 2025.
Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida

In August 2020 and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of Entergy Louisiana’s service area. The storms resulted in widespread outages, significant damage to distribution and transmission infrastructure, and the loss of sales during the outages. Additionally, as a result of Hurricane Laura’s extensive damage to the grid infrastructure serving the impacted area, large portions of the underlying transmission system required nearly a complete rebuild.

In October 2020, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments in connection with the issuance of shorter-term mortgage bonds to provide interim financing for restoration costs associated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta. Subsequently, Entergy Louisiana and the LPSC staff filed a joint motion seeking approval to exclude from the derivation of Entergy Louisiana’s capital structure and cost rate of debt for ratemaking purposes, including the allowance for funds used during construction, shorter-term debt up to $1.1 billion issued by Entergy Louisiana to fund costs associated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta costs on an interim basis. In November 2020 the LPSC issued an order approving the joint motion, and Entergy Louisiana issued $1.1 billion of 0.62% Series mortgage bonds due November 2023. Also in November 2020, Entergy Louisiana withdrew $257 million from its funded storm reserves.

In February 2021 two winter storms (collectively, Winter Storm Uri) brought freezing rain and ice to Louisiana. Ice accumulation sagged or downed trees, limbs, and power lines, causing damage to Entergy Louisiana’s transmission and distribution systems. The additional weight of ice caused trees and limbs to fall into power lines and other electric equipment. When the ice melted, it affected vegetation and electrical equipment, causing additional outages. Entergy Louisiana recovered the incremental fuel costs associated with Winter Storm Uri over a five-month period from April 2021 through August 2021.

In April 2021, Entergy Louisiana filed an application with the LPSC relating to Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri restoration costs and in July 2021, Entergy Louisiana made a supplemental filing updating the total restoration costs. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by these storms were estimated to be approximately $2.06 billion, including approximately $1.68 billion in capital costs and approximately $380 million in non-capital costs. Including carrying costs through January 2022, Entergy Louisiana sought an LPSC determination that $2.11 billion was prudently incurred and, therefore, was eligible for recovery from customers. Additionally, Entergy Louisiana requested that the LPSC determine that re-establishment of a storm escrow account to the previously authorized amount of $290 million was appropriate. In July 2021, Entergy Louisiana supplemented the application with a request regarding the financing and recovery of the recoverable storm restoration costs. Specifically, Entergy Louisiana requested approval to securitize its restoration costs pursuant to Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021.

In August 2021, Hurricane Ida caused extensive damage to Entergy Louisiana’s distribution and, to a lesser extent, transmission systems resulting in widespread power outages. In September 2021, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments in connection with the issuance of approximately $1 billion of shorter-term mortgage bonds to provide interim financing for restoration costs associated with Hurricane Ida, which bonds were issued in October 2021. Also in September 2021, Entergy Louisiana sought approval for the creation and funding of a $1 billion restricted escrow account for Hurricane Ida related restoration costs, subject to a subsequent prudence review.

After filing of testimony by the LPSC staff and intervenors, which generally supported or did not oppose Entergy Louisiana’s requests in regard to Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida, the parties negotiated and executed an uncontested stipulated settlement which was filed with the LPSC in February 2022. The settlement agreement contained the following key terms: $2.1 billion of restoration costs from Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri were prudently incurred and
eligible for recovery; carrying costs of $51 million were recoverable; a $290 million cash storm reserve should be re-established; a $1 billion reserve should be established to partially pay for Hurricane Ida restoration costs; and Entergy Louisiana was authorized to finance $3.186 billion utilizing the securitization process authorized by Act 55, as supplemented by Act 293. The LPSC issued an order approving the settlement in March 2022. As a result of the financing order, Entergy Louisiana reclassified $1.942 billion from utility plant to other regulatory assets.

In May 2022 the securitization financing closed, resulting in the issuance of $3.194 billion principal amount of bonds by Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA), a political subdivision of the State of Louisiana. The securitization was authorized pursuant to the Louisiana Utilities Restoration Corporation Act, Part VIII of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana legislature approved in 2021. The LCDA loaned the proceeds to the LURC. Pursuant to Act 293, the LURC contributed the net bond proceeds to a State legislatively authorized and LURC-sponsored trust, Restoration Law Trust I (the storm trust I).

Pursuant to Act 293, the net proceeds of the bonds were used by the storm trust I to purchase 31,635,718.7221 Class A preferred, non-voting membership interest units (the preferred membership interests) issued by Entergy Finance Company. Entergy Finance Company is required to make annual distributions (dividends) commencing on December 15, 2022 on the preferred membership interests issued to the storm trust I. These annual dividends received by the storm trust I will be distributed to Entergy Louisiana and the LURC, as beneficiaries of the storm trust I. Specifically, 1% of the annual dividends received by the storm trust I will be distributed to the LURC, for the benefit of customers, and 99% will be distributed to Entergy Louisiana, net of storm trust expenses. The preferred membership interests have a stated annual cumulative cash dividend rate of 7% and a liquidation price of $100 per unit. The terms of the preferred membership interests include certain financial covenants to which Entergy Finance Company is subject. Semi-annual redemptions of the preferred membership interests, subject to certain conditions, are expected to occur over the next 15 years.

Entergy and Entergy Louisiana do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA. The bonds are secured by system restoration property, which is the right granted by law to the LURC to collect a system restoration charge from customers. The system restoration charge is adjusted at least semi-annually to ensure that it is sufficient to service the bonds. Entergy Louisiana collects the system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee. Entergy Louisiana began collecting the system restoration charge effective with the first billing cycle of June 2022 and the system restoration charge is expected to remain in place for up to 15 years. Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as a billing and collection agent for the LCDA and the LURC. In the remote possibility that the system restoration charge, as well as any funds in the excess subaccount and funds in the debt service reserve account, are insufficient to service the bonds resulting in a payment default, the storm trust I is required to liquidate Entergy Finance Company preferred membership interests in an amount equal to what would be required to cure the default. The estimated value of this indirect guarantee is immaterial.

From the proceeds from the issuance of the preferred membership interests, Entergy Finance Company distributed $1.4 billion to its parent, Entergy Holdings Company, LLC, a company wholly-owned and consolidated by Entergy. Subsequently, Entergy Holdings Company liquidated, distributing the $1.4 billion it received from Entergy Finance Company to Entergy Louisiana as holder of 6,843,780.24 units of Class A, 4,126,940.15 units of Class B, and 2,935,152.69 units of Class C preferred membership interests. Entergy Louisiana had acquired these preferred membership interests with proceeds from previous securitizations of storm restoration costs. Entergy Finance Company loaned the remaining $1.7 billion from the preferred membership interests proceeds to Entergy which used the cash to redeem $650 million of 4.00% Series senior notes due July 2022 and indirectly contributed $1 billion to Entergy Louisiana as a capital contribution.

Entergy Louisiana used the $1 billion capital contribution to fund its Hurricane Ida escrow account and subsequently withdrew the $1 billion from the escrow account. With a portion of the $1 billion withdrawn from the
escrow account and the $1.4 billion from the Entergy Holdings Company liquidation, Entergy Louisiana deposited $290 million in a restricted escrow account as a storm damage reserve for future storms, used $1.2 billion to repay its unsecured term loan due June 2023, and used $435 million to redeem a portion of its 0.62% Series mortgage bonds due November 2023.

As discussed in Note 3 to the financial statements, the securitization resulted in recognition of a reduction of income tax expense of approximately $290 million by Entergy Louisiana. Entergy’s recognition of reduced income tax expense was partially offset by other tax charges resulting in a net reduction of income tax expense of $283 million. In recognition of obligations described in an LPSC ancillary order issued as part of the securitization regulatory proceeding, Entergy Louisiana recorded a $224 million ($165 million net-of-tax) regulatory charge and a corresponding regulatory liability to reflect its obligation to provide credits to its customers.

As discussed in Note 6 and Note 17 to the financial statements, Entergy Louisiana consolidates the storm trust I as a variable interest entity and the LURC’s 1% beneficial interest is presented as noncontrolling interest in the financial statements. In second quarter 2022, Entergy Louisiana recorded a charge of $31.6 million in other income to reflect the LURC’s beneficial interest in the storm trust I.

In April 2022, Entergy Louisiana filed an application with the LPSC relating to Hurricane Ida restoration costs. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by Hurricane Ida were estimated to be approximately $2.54 billion, including approximately $1.96 billion in capital costs and approximately $586 million in non-capital costs. Including carrying costs of $57 million through December 2022, Entergy Louisiana was seeking an LPSC determination that $2.60 billion was prudently incurred and, therefore, eligible for recovery from customers. As part of this filing, Entergy Louisiana also was seeking an LPSC determination that an additional $32 million in costs associated with the restoration of Entergy Louisiana’s electric facilities damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta as well as Winter Storm Uri was prudently incurred. This amount was exclusive of the requested $3 million in carrying costs through December 2022. In total, Entergy Louisiana was requesting an LPSC determination that $2.64 billion was prudently incurred and, therefore, eligible for recovery from customers. As discussed above, in March 2022 the LPSC approved financing of a $1 billion storm escrow account from which funds were withdrawn to finance costs associated with Hurricane Ida restoration. In June 2022, Entergy Louisiana supplemented the application with a request regarding the financing and recovery of the recoverable storm restoration costs. Specifically, Entergy Louisiana requested approval to securitize its restoration costs pursuant to Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021. In October 2022 the LPSC staff recommended a finding that the requested storm restoration costs of $2.64 billion, including associated carrying costs of $59.1 million, were prudently incurred and eligible for recovery from customers. The LPSC staff further recommended approval of Entergy Louisiana’s plans to securitize these costs, net of the $1 billion in funds withdrawn from the storm escrow account described above. The parties negotiated and executed an uncontested stipulated settlement which was filed with the LPSC in December 2022. The settlement agreement contains the following key terms: $2.57 billion of restoration costs from Hurricane Ida, Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri were prudently incurred and eligible for recovery; carrying costs of $59.2 million were recoverable; and Entergy Louisiana was authorized to finance $1.657 billion utilizing the securitization process authorized by Act 55, as supplemented by Act 293. A procedural motion to consider the uncontested settlement at the December 2022 LPSC meeting did not pass and the settlement was not voted on. In January 2023 an ALJ with the LPSC conducted a settlement hearing to receive the uncontested settlement and supporting testimony into evidence and issued a report of proceedings, which allows the LPSC to consider the uncontested settlement without the procedural motion that did not pass in December. In January 2023 the LPSC approved the stipulated settlement subject to certain modifications. These modifications include the recognition of accumulated deferred income tax benefits related to damaged assets and system restoration costs as a reduction of the amount authorized to be financed utilizing the securitization process authorized by Act 55, as supplemented by Act 293, from $1.657 billion to $1.491 billion. These modifications did not affect the LPSC’s conclusion that all system restoration costs sought by Entergy Louisiana were reasonable and prudent. In February 2023 the Louisiana Bond Commission voted to authorize the LCDA to issue the bonds authorized in the LPSC’s financing order.
In March 2023 the Hurricane Ida securitization financing closed, resulting in the issuance of approximately $1.491 billion principal amount of bonds by the LCDA and a remaining regulatory asset of $180 million to be recovered through the exclusion of the accumulated deferred income taxes related to damaged assets and system restoration costs from the determination of future rates. The securitization was authorized pursuant to the Louisiana Utilities Restoration Corporation Act, Part VIII of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021. The LCDA loaned the proceeds to the LURC. Pursuant to Act 293, the LURC contributed the net bond proceeds to a State legislatively authorized and LURC-sponsored trust, Restoration Law Trust II (the storm trust II).

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

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

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

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

As discussed in Note 6 and Note 17 to the financial statements, Entergy Louisiana consolidates the storm trust II as a variable interest entity and the LURC’s 1% beneficial interest is presented as noncontrolling interest in
the financial statements. In first quarter 2023, Entergy Louisiana recorded a charge of $14.6 million in other income to reflect the LURC’s beneficial interest in the storm trust II.

Hurricane Isaac

In August 2012, Hurricane Isaac caused extensive damage to Entergy Louisiana’s service area.  In June 2014 the LPSC authorized Entergy Louisiana to utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs.  Entergy Louisiana committed to pass on to customers a minimum of $30.8 million of customer benefits through annual customer credits of approximately $6.2 million for five years. Approvals for the Act 55 financings were obtained from the LURC and the Louisiana State Bond Commission.

In August 2014 the LCDA issued $314.85 million in bonds under Louisiana Act 55.  From the $309 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $16 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $293 million directly to Entergy Louisiana.  Entergy Louisiana used the $293 million received from the LURC to acquire 2,935,152.69 Class C preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 7.5% annual distribution rate. Distributions were payable quarterly commencing on September 15, 2014, and the membership interests had a liquidation price of $100 per unit. The preferred membership interests were callable at the option of Entergy Holdings Company after ten years under the terms of the LLC agreement. The terms of the membership interests included certain financial covenants to which Entergy Holdings Company was subject, including the requirement to maintain a net worth of at least $1.75 billion. As discussed above in “Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida”, in May 2022, Entergy Holdings Company liquidated and distributed cash to Entergy Louisiana as holder of the 2,935,152.69 units of Class C preferred membership interests.

Entergy and Entergy Louisiana do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA and there is no recourse against Entergy or Entergy Louisiana in the event of a bond default.  To service the bonds, Entergy Louisiana collects a system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee.  Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as the billing and collection agent for the state.

Hurricane Gustav and Hurricane Ike

In September 2008, Hurricane Gustav and Hurricane Ike caused catastrophic damage to Entergy Louisiana’s service territory.  In December 2009, Entergy Louisiana entered into a stipulation agreement with the LPSC staff regarding its storm costs.  In March and April 2010, Entergy Louisiana and other parties to the proceeding filed with the LPSC an uncontested stipulated settlement that included Entergy Louisiana’s proposal to utilize Act 55 financing, which included a commitment to pass on to customers a minimum of $43.3 million of customer benefits through a prospective annual rate reduction of $8.7 million for five years.  In April 2010 the LPSC approved the settlement and subsequently issued financing orders and a ratemaking order intended to facilitate the implementation of the Act 55 financings.  In June 2010 the Louisiana State Bond Commission approved the Act 55 financing. The settlement agreement allowed for an adjustment to the credits if there was a change in the applicable federal or state income tax rate. As a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, and the lowering of the federal corporate income tax rate from 35% to 21%, the Louisiana Act 55 financing savings obligation regulatory liability related to Hurricane Gustav and Hurricane Ike was reduced by $2.7 million, with a corresponding increase to Other regulatory credits on the income statement. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.

In July 2010 the LCDA issued two series of bonds totaling $713.0 million under Act 55.  From the $702.7 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $290 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $412.7 million directly to Entergy Louisiana.  From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana
used $412.7 million to acquire 4,126,940.15 Class B preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 9% annual distribution rate. Distributions were payable quarterly commencing on September 15, 2010, and the membership interests had a liquidation price of $100 per unit. The preferred membership interests were callable at the option of Entergy Holdings Company after ten years under the terms of the LLC agreement.  The terms of the membership interests included certain financial covenants to which Entergy Holdings Company was subject, including the requirement to maintain a net worth of at least $1 billion. As discussed above in “Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida”, in May 2022, Entergy Holdings Company liquidated and distributed cash to Entergy Louisiana as holder of the 4,126,940.15 units of Class B preferred membership interests.

The bonds were repaid in 2022. Entergy and Entergy Louisiana did not report the bonds issued by the LCDA on their balance sheets because the bonds were the obligation of the LCDA, and there was no recourse against Entergy or Entergy Louisiana in the event of a bond default.  To service the bonds, Entergy Louisiana collected a system restoration charge on behalf of the LURC and remitted the collections to the bond indenture trustee.  Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as the billing and collection agent for the state.

Hurricane Katrina and Hurricane Rita

In August and September 2005, Hurricanes Katrina and Rita caused catastrophic damage to Entergy Louisiana’s service territory. In March 2008, Entergy Louisiana and the LURC filed at the LPSC an application requesting that the LPSC grant a financing order authorizing the financing of Entergy Louisiana storm costs, storm reserves, and issuance costs pursuant to Louisiana Act 55.  Entergy Louisiana also filed an application requesting LPSC approval for ancillary issues including the mechanism to flow charges and savings to customers via a storm cost offset rider.  In April 2008 the Louisiana Public Facilities Authority (LPFA), which is the issuer of the bonds pursuant to the Act 55 financing, approved requests for the Act 55 financing.  Also in April 2008, Entergy Louisiana and the LPSC staff filed with the LPSC an uncontested stipulated settlement that included Entergy Louisiana’s proposal under the Act 55 financing, which included a commitment to pass on to customers a minimum of $40 million of customer benefits through a prospective annual rate reduction of $8 million for five years.  The LPSC subsequently approved the settlement and issued two financing orders and one ratemaking order intended to facilitate implementation of the Act 55 financing.  In May 2008 the Louisiana State Bond Commission granted final approval of the Act 55 financing. The settlement agreement allowed for an adjustment to the credits if there was a change in the applicable federal or state income tax rate. As a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, and the lowering of the federal corporate income tax rate from 35% to 21%, the Louisiana Act 55 financing savings obligation regulatory liability related to Hurricanes Katrina and Rita was reduced by $22.3 million, with a corresponding increase to Other regulatory credits on the income statement. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.

In July 2008 the LPFA issued $687.7 million in bonds under the aforementioned Act 55.  From the $679 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $152 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $527 million directly to Entergy Louisiana.  From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $545 million, including $17.8 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 5,449,861.85 Class A preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 10% annual distribution rate.  In August 2008 the LPFA issued $278.4 million in bonds under the aforementioned Act 55.  From the $274.7 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $87 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $187.7 million directly to Entergy Louisiana.  From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $189.4 million, including $1.7 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 1,893,918.39 Class A preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 10% annual distribution rate.  Distributions were payable quarterly commencing on September 15, 2008 and had a
liquidation price of $100 per unit.  The preferred membership interests were callable at the option of Entergy Holdings Company after ten years under the terms of the LLC agreement.  The terms of the membership interests included certain financial covenants to which Entergy Holdings Company was subject, including the requirement to maintain a net worth of at least $1 billion.  In February 2012, Entergy Louisiana sold 500,000 of its Class A preferred membership units in Entergy Holdings Company to a third party. Those preferred membership units were subsequently repurchased by Entergy Holdings Company in March 2019. As discussed above in “Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida”, in May 2022, Entergy Holdings Company liquidated and distributed cash to Entergy Louisiana as holder of the remaining 6,843,780.24 units of Class A preferred membership interests.

The bonds were repaid in 2018. Entergy and Entergy Louisiana did not report the bonds issued by the LPFA on their balance sheets because the bonds were the obligation of the LPFA, and there was no recourse against Entergy or Entergy Louisiana in the event of a bond default.  To service the bonds, Entergy Louisiana collected a system restoration charge on behalf of the LURC and remitted the collections to the bond indenture trustee.  Entergy and Entergy Louisiana did not report the collections as revenue because Entergy Louisiana was merely acting as the billing and collection agent for the state.

Entergy Mississippi

Prior to June 2024, Entergy Mississippi had approval from the MPSC to collect a storm damage provision of $1.75 million per month. If Entergy Mississippi’s accumulated storm damage provision balance exceeded $15 million, the collection of the storm damage provision ceased until such time that the accumulated storm damage provision became less than $10 million. Entergy Mississippi’s storm damage provision balance had been less than $10 million since May 2019, and Entergy Mississippi had been billing the monthly storm damage provision since July 2019.

In December 2023, Entergy Mississippi filed a Notice of Storm Escrow Disbursement and Request for Interim Relief notifying the MPSC that Entergy Mississippi had requested disbursement of approximately $34.5 million of storm escrow funds from its restricted storm escrow account. The filing also requested authorization from the MPSC, on a temporary basis, that the $34.5 million of storm escrow funds be credited to Entergy Mississippi’s storm damage provision, pending the MPSC’s review of Entergy Mississippi’s storm-related costs, and that Entergy Mississippi continue to bill its monthly storm damage provision without suspension in the event the storm damage provision balance exceeded $15 million, in anticipation of a subsequent filing by Entergy Mississippi in this proceeding. The storm damage provision exceeded $15 million upon receipt of the storm escrow funds. Because the MPSC had not entered an order on Entergy Mississippi’s filing on the requested relief to continue billing this provision, Entergy Mississippi suspended billing the monthly storm damage provision effective with February 2024 bills.

In March 2024, Entergy Mississippi made a combined dual filing which included a notice of intent to make routine change in rates and schedules and a motion for determination relating to the above-described notice of storm escrow disbursement. The notice of intent proposed a new storm damage mitigation and restoration rider to supersede both the then-current storm damage rate schedule and the vegetation management rider schedule, in which the collection of both expenses would be combined. The proposal requested that the MPSC authorize Entergy Mississippi to collect approximately $5.2 million per month for vegetation management and a storm damage provision. Furthermore, if Entergy Mississippi’s accumulated vegetation management and storm damage provision balance were to exceed $70 million, collection under the storm damage mitigation and restoration rider would cease until such time that the accumulated vegetation management and storm damage provision would become less than $60 million.

The Mississippi Public Utilities Staff reviewed the storm-related costs submitted by Entergy Mississippi and found them prudent. In June 2024 the MPSC considered and unanimously granted the relief sought by Entergy Mississippi, including authorization to credit any remaining funds in the storm escrow account to Entergy
Mississippi’s storm damage provision and to close the storm escrow account and approving the new storm damage mitigation and restoration rider. Entergy Mississippi’s storm escrow account was liquidated in July 2024, and the new combined storm damage mitigation and restoration rider became effective with the July 2024 billing cycle. Additionally, Entergy Mississippi made a compliance filing to cease billing under the existing vegetation management rider schedule as of the same billing cycle.

Entergy New Orleans

Hurricane Ida

In August 2021, Hurricane Ida caused significant damage to Entergy New Orleans’s service area, including Entergy’s electrical grid. The storm resulted in widespread power outages, including the loss of 100% of Entergy New Orleans’s load and damage to distribution and transmission infrastructure, including the loss of connectivity to the eastern interconnection. In September 2021, Entergy New Orleans withdrew $39 million from its funded storm reserves. In June 2022, Entergy New Orleans filed an application with the City Council requesting approval and certification that storm restoration costs associated with Hurricane Ida of approximately $170 million, which included $11 million in estimated costs, were reasonable, necessary, and prudently incurred to enable Entergy New Orleans to restore electric service to its customers and to repair Entergy New Orleans’s electric utility infrastructure. In addition, estimated carrying costs through December 2022 related to Hurricane Ida restoration costs were $9 million. Also, Entergy New Orleans requested approval that the $39 million withdrawal from its funded storm reserve in September 2021 and $7 million in excess storm reserve escrow withdrawals related to Hurricane Zeta in October 2020 and prior miscellaneous storms were properly applied to Hurricane Ida storm restoration costs, the application of which reduced the amount to be recovered from Entergy New Orleans customers by $46 million.

Additionally, in February 2022, Entergy New Orleans and the LURC filed with the City Council a securitization application requesting that the City Council review Entergy New Orleans’s storm reserve and increase the storm reserve funding level to $150 million, to be funded through securitization. In August 2022 the City Council’s advisors recommended that the City Council authorize a single securitization bond issuance to fund Entergy New Orleans’s storm recovery reserves to an amount sufficient to: (1) allow recovery of all of Entergy New Orleans’s unrecovered storm recovery costs following Hurricane Ida, subject to City Council review and certification; (2) provide initial funding of storm recovery reserves for future storms to a level of $75 million; and (3) fund the storm recovery bonds’ upfront financing costs. In September 2022, Entergy New Orleans and the City Council’s advisors entered into an agreement in principle, which was approved by the City Council along with a financing order in October 2022, which authorized Entergy New Orleans and the LURC to proceed with a single securitization bond issuance of approximately $206 million (subject to further adjustment and review pursuant to the Final Issuance Advice Letter process set forth in the financing order), with $125 million of that total to be used for interim recovery, subject to City Council review and certification, to be allocated to unrecovered Hurricane Ida storm recovery costs; $75 million of that total to provide for a storm recovery reserve for future storms; and the remainder to fund the recovery of the storm recovery bonds’ upfront financing costs.

In December 2022, Entergy New Orleans and the LURC filed with the City Council the Final Issuance Advice Letter for a securitization bond issuance in the amount of $209.3 million, the final structuring, terms, and pricing of which were approved by the City Council in accordance with the financing order. Also in December 2022 the LCDA issued $209.3 million in bonds pursuant to the Louisiana Electric Utility Storm Recovery Securitization Act, Part V-B of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana Regular Session of 2021. The LCDA loaned $201.8 million of bond proceeds, net of certain debt service and issuance costs, to the LURC. The LURC used the proceeds to purchase from Entergy New Orleans the storm recovery property, which is the right to collect storm recovery charges sufficient to pay the storm recovery bonds and associated financing costs, and Entergy New Orleans deposited $200 million in a restricted storm reserve escrow account as a storm damage reserve for Entergy New Orleans and received directly $1.8 million in estimated upfront financing costs. Subsequently, Entergy New Orleans withdrew $125 million from the newly securitized
storm reserve to cover Hurricane Ida storm recovery costs, subject to a final determination from the City Council regarding the prudency of the storm recovery costs.

Entergy and Entergy New Orleans do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA, and there is no recourse against Entergy or Entergy New Orleans in the event of a bond default. To service the bonds, Entergy New Orleans collects a storm recovery charge on behalf of the LURC and remits the collections to the bond indenture trustee. Entergy and Entergy New Orleans do not report the collections as revenue because Entergy New Orleans is merely acting as the billing and collection agent for the LURC.

In August 2023 the City Council advisors issued a report recommending that the City Council find that Entergy New Orleans prudently incurred approximately $164.1 million in storm restoration costs and $7.5 million in carrying charges and that such costs have already been properly recovered by Entergy New Orleans through withdrawals from the storm reserve escrow account. The City Council advisors also recommended that the City Council find that approximately $1.2 million in storm restoration costs had already been recovered through Entergy New Orleans’s base rates and that approximately $0.9 million in unused credits be applied against future storm costs. In August 2023 the City Council hearing officer certified the evidentiary record. In December 2023 the City Council approved a resolution adopting the advisors’ report and recommendations.

Entergy Texas

Hurricane Laura, Hurricane Delta, and Winter Storm Uri

In August 2020 and October 2020, Hurricane Laura and Hurricane Delta caused extensive damage to Entergy Texas’s service area. In February 2021, Winter Storm Uri also caused damage to Entergy Texas’s service area. The storms resulted in widespread power outages, significant damage primarily to distribution and transmission infrastructure, and the loss of sales during the power outages. In April 2021, Entergy Texas filed an application with the PUCT requesting a determination that approximately $250 million of system restoration costs associated with Hurricane Laura, Hurricane Delta, and Winter Storm Uri, including approximately $200 million in capital costs and approximately $50 million in non-capital costs, were reasonable and necessary to enable Entergy Texas to restore electric service to its customers and Entergy Texas’s electric utility infrastructure. The filing also included the projected balance of approximately $13 million of a regulatory asset containing previously approved system restoration costs related to Hurricane Harvey. In September 2021 the parties filed an unopposed settlement agreement, pursuant to which Entergy Texas removed from the amount to be securitized approximately $4.3 million that will instead be charged to its storm reserve, $5 million related to no particular issue, of which Entergy Texas would be permitted to seek recovery in a future proceeding, and approximately $300 thousand related to attestation costs. In December 2021 the PUCT issued an order approving the unopposed settlement and determining system restoration costs of $243 million related to Hurricane Laura, Hurricane Delta, and Winter Storm Uri and the $13 million projected remaining balance of the Hurricane Harvey system restoration costs were eligible for securitization. The order also determines that Entergy Texas can recover carrying costs on the system restoration costs related to Hurricane Laura, Hurricane Delta, and Winter Storm Uri.

In July 2021, Entergy Texas filed with the PUCT an application for a financing order to approve the securitization of the system restoration costs that are the subject of the April 2021 application. In November 2021 the parties filed an unopposed settlement agreement supporting the issuance of a financing order consistent with Entergy Texas’s application and with minor adjustments to certain upfront and ongoing costs to be incurred to facilitate the issuance and serving of system restoration bonds. In January 2022 the PUCT issued a financing order consistent with the unopposed settlement. As a result of the financing order, Entergy Texas reclassified $153 million from utility plant to other regulatory assets.

In April 2022, Entergy Texas Restoration Funding II, LLC, a company wholly-owned and consolidated by Entergy Texas, issued $290.85 million of senior secured system restoration bonds (securitization bonds). With the
proceeds, Entergy Texas Restoration Funding II purchased from Entergy Texas the transition property, which is the right to recover from customers through a system restoration charge amounts sufficient to service the securitization bonds. Entergy Texas began cost recovery through the system restoration charge effective with the first billing cycle of May 2022 and the system restoration charge is expected to remain in place up to 15 years. See Note 5 to the financial statements for a discussion of the April 2022 issuance of the securitization bonds.
Entergy Texas [Member]  
Public Utilities Disclosure [Text Block] RATE AND REGULATORY MATTERS (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Regulatory Assets and Regulatory 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. In addition to the regulatory assets and liabilities that are specifically disclosed on the face of the balance sheets, the tables below provide detail of “Other regulatory assets” and “Other regulatory liabilities” that are included on Entergy’s and the Registrant Subsidiaries’ balance sheets as of December 31, 2024 and 2023 (as noted in footnotes to the tables, a portion of these regulatory assets and regulatory liabilities is classified as held for sale in the balance sheets as of December 31, 2024):

Other Regulatory Assets

Entergy
20242023
 (In Millions)
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
$1,387.6 $1,655.5 
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or shutdown of non-nuclear power plants and solar facilities (Note 9) (a)
1,358.7 1,285.0 
Removal costs (Note 9)
1,107.6 1,010.7 
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators and Note 5 - Securitization Bonds)
547.3 536.9 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
227.1 250.9 
Retail rate deferrals - recovered through formula rates or rate riders as rates are redetermined by retail regulators
195.1 248.6 
Retired electric and gas meters - recovered through retail rates as determined by retail regulators (Note 2 - Retail Rate Proceedings)
135.7 153.8 
Deferred COVID-19 costs - recovered through retail rates as determined by retail regulators (Note 2 - Retail Rate Proceedings)
104.0 118.0 
Unamortized loss on reacquired debt - recovered over term of debt
57.9 63.1 
Advanced metering system surcharge for residential customers - recovered through December 2029
39.7 20.2 
Formula rate plan historical year rate adjustment (Note 2 - Retail Rate Proceedings) (b)
15.5 — 
Pension & postretirement benefits expense deferral - recovered through retail rates (Note 2 - Retail Rate Proceedings and Note 11 - Entergy Texas Reserve)
15.0 32.7 
Rate case depreciation relate back deferral - recovered over a six-month period beginning January 2024 (Note 2 - Retail Rate Proceedings)
— 27.6 
Opportunity sales - (Note 2 - Entergy Arkansas Opportunity Sales Proceeding) (b)
— 131.8 
Other99.7 134.6 
Entergy Total (c)
$5,290.9 $5,669.4 
Entergy Arkansas
 20242023
 (In Millions)
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or shutdown of non-nuclear power plants and solar facilities (Note 9) (a)
$693.0 $639.1 
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
433.3 536.6 
Removal costs (Note 9)
337.9 319.7 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
75.8 84.1 
Deferred COVID-19 costs - recovered over a 10-year period through December 2033
35.1 39.0 
Retired electric meters - recovered over a 15-year period through March 2034
32.8 36.3 
Storm damage costs - recovered through retail rates
29.8 33.1 
Unamortized loss on reacquired debt - recovered over term of debt
18.6 19.9 
Formula rate plan historical year rate adjustment (Note 2 - Retail Rate Proceedings) (b)
15.5 — 
Retail rate deferrals - recovered through rate riders as rates are redetermined annually (b)
13.6 24.9 
ANO Fukushima and Flood Barrier costs - recovered through retail rates through February 2026 (b)
2.1 3.8 
Opportunity sales - (Note 2 - Entergy Arkansas Opportunity Sales Proceeding) (b)
— 131.8 
Other12.6 17.1 
Entergy Arkansas Total$1,700.1 $1,885.4 

Entergy Louisiana
 20242023
 (In Millions)
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or shutdown of non-nuclear power plants (Note 9) (a)
$421.5 $408.7 
Pension & postretirement costs (Note 11 - Qualified Pension Plans and Non-Qualified Pension Plans) (a)
367.7 412.0 
Removal costs (Note 9)
323.2 262.3 
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)
226.6 202.6 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
111.4 123.0 
Retired electric and gas meters - recovered over a 22-year period through July 2041
78.5 83.2 
Deferred COVID-19 costs - recovery period to be determined (Note 2 - Retail Rate Proceedings) (a)
47.8 47.8 
Unamortized loss on reacquired debt - recovered over term of debt
21.7 23.4 
Other48.5 85.9 
Entergy Louisiana Total (c)
$1,646.9 $1,648.9 
Entergy Mississippi
 20242023
(In Millions)
Removal costs (Note 9)
$184.8 $188.0 
Retail rate deferrals - recovered through formula rates or rate riders as rates are redetermined annually
162.5 192.8 
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
112.1 127.6 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
29.1 32.0 
Asset retirement obligation - recovery dependent upon timing of shutdown of non-nuclear power plants and solar facility (Note 9) (a)
9.4 6.8 
Unamortized loss on reacquired debt - recovered over term of debt
9.1 10.0 
Attorney General litigation costs - recovered over a six-year period through March 2026 (b)
6.0 10.9 
Other12.8 11.0 
Entergy Mississippi Total$525.8 $579.1 

Entergy New Orleans
 20242023
 (In Millions)
Removal costs (Note 9)
$62.5 $61.1 
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
22.9 41.4 
Retired electric and gas meters - recovered over a 12-year period through July 2031 (b)
13.5 15.5 
Gas cross-boring costs - recovered through formula rates as rates are redetermined by retail regulators
11.9 10.9 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
10.8 11.8 
Deferred COVID-19 costs - recovered over a five-year period through August 2028 (b)
10.2 13.0 
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators and Note 5 - Entergy New Orleans Securitization Bonds - Hurricane Isaac)
4.0 3.9 
Unamortized loss on reacquired debt - recovered over term of debt
0.5 0.8 
Other20.7 24.0 
Entergy New Orleans Total (c)
$157.0 $182.4 
Entergy Texas
 20242023
 (In Millions)
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators and Note 5 - Entergy Texas Securitization Bonds - Hurricane Laura, Hurricane Delta, and Winter Storm Uri)
$286.5 $297.3 
Removal costs (Note 9)
102.3 77.5 
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
62.9 85.6 
Advanced metering system surcharge for residential customers - recovered through December 2029
39.7 20.2 
Pension & postretirement benefits expense deferral - recovered through retail rates (Note 2 - Retail Rate Proceedings and Note 11 - Entergy Texas Reserve)
15.0 32.7 
Retired electric meters - recovered through retail rates (Note 2 - Retail Rate Proceedings)
10.9 18.8 
Neches and Sabine costs - recovered over a 10-year period through September 2028
9.2 11.6 
Unamortized loss on reacquired debt - recovered over term of debt
7.6 8.3 
Rate case depreciation relate back deferral - recovered over a six-month period beginning January 2024 (Note 2 - Retail Rate Proceedings)
— 27.6 
Other15.6 17.0 
Entergy Texas Total$549.7 $596.6 

System Energy
 20242023
 (In Millions)
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear unit (Note 9) (b)
$224.8 $222.0 
Pension & postretirement costs (Note 11 - Qualified Pension Plans and Other Postretirement Benefits) (a)
104.4 121.6 
Removal costs - recovered through depreciation rates (Note 9)
96.9 102.1 
Unamortized loss on reacquired debt - recovered over term of debt
0.4 0.7 
System Energy Total$426.5 $446.4 

(a)Does not earn a return on investment, but is offset by related liabilities.
(b)Does not earn a return on investment.
(c)Includes $35.4 million at Entergy, $8.9 million at Entergy Louisiana, and $23.7 million at Entergy New Orleans as of December 31, 2024 of regulatory assets related to the respective natural gas distribution businesses classified as held for sale and included within “Non-current assets held for sale” on the respective consolidated balance sheets. See Note 14 to the financial statements for further discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses and the classification as held for sale.
Other Regulatory Liabilities

Entergy
20242023
(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)
$2,262.5 $1,826.2 
Securitization financing savings obligation (Note 3)
371.3 405.2 
Retail rate rider over-recovery - refunded through formula rate or rate riders as rates are redetermined by retail regulators
164.9 142.7 
Credits from resolution of the 2016-2018 IRS audit (Note 3)
163.3 98.0 
Customer rate credits from global stipulated settlement with the LPSC - returned to customers September 2024 through August 2026 (Note 2)
121.7 — 
Refund from System Energy settlement with the LPSC - to be returned to customers January 2025 through August 2027 (Note 2)
75.8 — 
Deferred tax equity partnership earnings (Note 1)
69.9 57.9 
Vidalia purchased power agreement (Note 8)
67.4 82.5 
Refund from System Energy settlement with the City Council - returned to customers over a 25-year period beginning September 2024 (Note 2)
64.7 — 
Shorter-term financing interest earnings (Note 2 - Retail Rate Proceedings) (a)
48.9 36.8 
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and the FERC
44.4 44.4 
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)
40.9 44.3 
Refund from System Energy settlement with the City Council - return to customers to be determined (Note 2)
32.0 — 
Refund from System Energy settlement with the APSC - refunded through a rate rider as rates are re-determined periodically (Note 2)
8.2 93.0 
Complaints against System Energy - potential future refunds (Note 2)
— 177.9 
Other75.2 108.0 
Entergy Total (b)
$3,611.1 $3,116.9 

Entergy Arkansas
 20242023
 (In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)
$761.3 $621.6 
Deferred tax equity partnership earnings (Note 1)
32.4 27.4 
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually
27.9 10.6 
Refund from System Energy settlement with the APSC - refunded through a rate rider as rates are re-determined periodically (Note 2)
8.2 93.0 
Internal restructuring guaranteed customer credits - returned to customers over a six-year period through December 2024
— 6.6 
Other1.4 — 
Entergy Arkansas Total$831.2 $759.2 
Entergy Louisiana
 20242023
 (In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)
$798.4 $644.0 
Securitization financing savings obligation (Note 3)
371.3 405.2 
Customer rate credits from global stipulated settlement with the LPSC - returned to customers September 2024 through August 2026 (Note 2)
121.7 — 
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually
96.3 86.4 
Refund from System Energy settlement with the LPSC - to be returned to customers January 2025 through August 2027 (Note 2)
75.8 — 
Vidalia purchased power agreement (Note 8)
67.4 82.5 
Shorter-term financing interest earnings (Note 2 - Retail Rate Proceedings) (a)
48.9 36.8 
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)
40.9 44.3 
Hurricane Ida insurance proceeds - returned to customers August 2024 to July 2025
26.0 32.3 
Credits from resolution of the 2016-2018 IRS audit - returned to customers September 2024 through August 2025 (Note 3)
25.3 38.0 
Sale-leaseback and depreciation refunds - returned to customers September 2023 through August 2024
— 14.1 
Other21.7 24.1 
Entergy Louisiana Total (b)
$1,693.7 $1,407.7 

Entergy Mississippi
20242023
 (In Millions)
Deferred tax equity partnership earnings (Note 1)
$37.5 $30.5 
Retail rate rider over-recovery - refunded through formula rate or rate riders as rates are redetermined annually
12.2 2.4 
Other postretirement benefits (Note 11 - Entergy Mississippi Other Postretirement Benefits)
7.4 — 
Other2.4 0.8 
Entergy Mississippi Total$59.5 $33.7 
Entergy New Orleans
20242023
 (In Millions)
Credits from resolution of the 2016-2018 IRS audit - to be returned to customers over a 25-year period beginning January 2025 (Note 3)
$138.0 $60.0 
Refund from System Energy settlement with the City Council - returned to customers over a 25-year period beginning September 2024 (Note 2)
64.7 — 
Refund from System Energy settlement with the City Council - return to customers to be determined (Note 2)
32.0 — 
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually
16.3 20.1 
Sale-leaseback and depreciation refunds - returned to customers over a 10-year period beginning September 2023 (Note 2)
5.2 9.8 
Other4.5 0.5 
Entergy New Orleans Total (b)
$260.7 $90.4 

Entergy Texas
 20242023
 (In Millions)
Retail rate rider over-recovery - return to customers to be determined
$12.2 $23.8 
Retail refunds - return to customers to be determined
6.2 6.2 
Rate case settlement relate back - amortized over a six-month period beginning January 2024 (Note 2 - Retail Rate Proceedings)
— 10.3 
Other 0.3 2.7 
Entergy Texas Total$18.7 $43.0 

System Energy
 20242023
 (In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)
$702.8 $560.6 
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and the FERC
44.4 44.4 
Complaints against System Energy - potential future refunds (Note 2)
— 177.9 
System Energy Total$747.2 $782.9 

(a)Offset by related asset.
(b)Includes $1.6 million at Entergy, $1.2 million at Entergy Louisiana, and $0.4 million at Entergy New Orleans as of December 31, 2024 of regulatory liabilities related to the respective natural gas distribution businesses classified as held for sale and included within other non-current liabilities on the respective consolidated balance sheets. See Note 14 to the financial statements for further discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses and the classification as held for sale.
Regulatory activity regarding the Tax Cuts and Jobs Act

See the “Other Tax Matters - Tax Cuts and Jobs Act” section in Note 3 to the financial statements for discussion of the effects of the December 2017 enactment of the Tax Cuts and Jobs Act (Tax Act), including its effects on Entergy’s and the Registrant Subsidiaries’ regulatory asset/liability for income taxes.

Entergy Louisiana

In an electric formula rate plan settlement approved by the LPSC in April 2018, the parties agreed that Entergy Louisiana would return to customers one-half of its eligible unprotected excess deferred income taxes from May 2018 through December 2018 and return to customers the other half from January 2019 through August 2022. In addition, the settlement provided that in order to flow back to customers certain other tax benefits created by the Tax Act, Entergy Louisiana established a regulatory liability effective January 1, 2018 in the amount of $9.1 million per month to reflect these tax benefits already included in retail rates until new base rates under the formula rate plan were established in September 2018, and this regulatory liability was returned to customers over the September 2018 through August 2019 formula rate plan rate-effective period. The LPSC staff and intervenors in the settlement reserved the right to obtain data from Entergy Louisiana to confirm the determination of excess accumulated deferred income taxes resulting from the Tax Act and the analysis thereof as part of the formula rate plan review proceeding for the 2017 test year filing. As discussed below in “Retail Rate Proceedings - Filings with the LPSC (Entergy Louisiana) - Retail Rates - Electric - Formula Rate Plan Global Settlement”, a global settlement resolving the outstanding issues related to the 2017 formula rate plan filing was reached in October 2023 and approved by the LPSC in November 2023.

System Energy

In a filing made with the FERC in March 2018, System Energy proposed revisions to the Unit Power Sales Agreement to reflect the effects of the Tax Act. In the filing System Energy proposed to return identified quantities of unprotected excess accumulated deferred income taxes to its customers by the end of 2018. In May 2018 the FERC accepted System Energy’s proposed tax revisions with an effective date of June 1, 2018, subject to refund and the outcome of settlement and hearing procedures. Settlement discussions were terminated in April 2019, and a hearing was held in March 2020. In December 2022 the FERC issued an order requiring System Energy to compute the amount of excess accumulated deferred income taxes associated with a previously uncertain decommissioning tax position with consideration for the resolution of the tax position by the IRS. In February 2023, System Energy submitted its compliance filing. This matter was ultimately settled as a result of System Energy’s settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” below for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.
Fuel and purchased power cost recovery

The Utility operating companies are allowed to recover fuel and purchased power costs through fuel mechanisms included in electric and gas rates that are recorded as fuel cost recovery revenues.  The difference between revenues collected and the current fuel and purchased power costs is generally recorded as “Deferred fuel costs” on the Utility operating companies’ financial statements.  The table below shows the amount of deferred fuel costs as of December 31, 2024 and 2023 that each Utility operating company expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.

 20242023
 (In Millions)
Entergy Arkansas
($45.2)($88.3)
Entergy Louisiana (a) (b)$163.4 $192.9 
Entergy Mississippi($126.3)($130.6)
Entergy New Orleans (a) (b)$8.0 $10.2 
Entergy Texas($59.3)$139.0 

(a)Includes $168.1 million in both years for Entergy Louisiana and $4.1 million in both years for Entergy New Orleans of fuel, purchased power, and capacity costs, which do not currently earn a return on investment and whose recovery periods are indeterminate but are expected to be recovered over a period greater than twelve months.
(b)Includes $0.7 million at Entergy Louisiana and $4.9 million at Entergy New Orleans as of December 31, 2024 of deferred fuel assets related to the respective natural gas distribution businesses classified as held for sale and included within “Current assets held for sale” on the respective consolidated balance sheets. See Note 14 to the financial statements for further discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses and the classification as held for sale.

Entergy Arkansas

Energy Cost Recovery Rider

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

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

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

In March 2018, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01547 per kWh to $0.01882 per kWh. The Arkansas Attorney General filed a response to Entergy Arkansas’s annual redetermination filing requesting that the APSC suspend the proposed tariff to investigate the amount of the redetermination or, alternatively, to allow recovery subject to refund. Among the reasons the Attorney General cited for suspension were questions pertaining to how Entergy Arkansas forecasted sales and potential implications of the Tax Cuts and Jobs Act. Entergy Arkansas replied to the Attorney General’s filing and stated that, to the extent there are questions pertaining to its load forecasting or the operation of the energy cost recovery rider, those issues exceed the scope of the instant rate redetermination. Entergy Arkansas also stated that potential effects of the Tax Cuts and Jobs Act are appropriately considered in the APSC’s separate proceeding regarding potential implications of the tax law. The APSC general staff filed a reply to the Attorney General’s filing and agreed that Entergy Arkansas’s filing complied with the terms of the energy cost recovery rider. The redetermined rate became effective with the first billing cycle of April 2018. Subsequently in April 2018 the APSC issued an order declining to suspend Entergy Arkansas’s energy cost recovery rider rate and declining to require further investigation at that time of the issues suggested by the Attorney General in the proceeding. Following a period of discovery, the Attorney General filed a supplemental response in October 2018 raising new issues with Entergy Arkansas’s March 2018 rate redetermination and asserting that $45.7 million of the increase should be collected subject to refund pending further investigation. Entergy Arkansas filed to dismiss the Attorney General’s supplemental response, the APSC general staff filed a motion to strike the Attorney General’s filing, and the Attorney General filed a supplemental response disputing Entergy Arkansas and the APSC staff’s filing. Applicable APSC rules and processes authorize its general staff to initiate periodic audits of Entergy Arkansas’s energy cost recovery rider. In late-2018 the APSC general staff notified Entergy Arkansas it initiated an audit of the 2017 fuel costs. The time in which the audit will be complete is uncertain at this time.

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

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

In March 2024, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease in the rate from $0.01883 per kWh to $0.00882 per kWh. Due to a change in law in the State of Arkansas, the annual redetermination included $9 million, recorded as a credit to fuel expense in first quarter 2024, for recovery attributed to net metering costs in 2023. The primary reason for the rate decrease is a large over-recovered balance as a result of lower natural gas prices in 2023. To mitigate the effect of projected increases in natural gas prices in 2024, Entergy Arkansas adjusted the over-recovered balance included in the March 2024 annual redetermination filing by $43.7 million. This adjustment is expected to reduce the rate change that will be reflected in the 2025 energy cost rate redetermination. The redetermined rate of $0.00882 per kWh became effective with the first billing cycle in April 2024 through the normal operation of the tariff.

Entergy Louisiana

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

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

In March 2020 the LPSC staff provided notice of an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2016 through 2019. The LPSC staff issued its audit report in September 2021, and although certain internal record keeping recommendations were made, the LPSC staff did not recommend any disallowances. The next step is for the LPSC to review the report, but there is not a deadline for the review.

In January 2023 the LPSC staff provided notice of an audit of Entergy Louisiana’s purchased gas adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s purchased gas adjustment clause for the period from 2021 through 2022. Discovery is ongoing, and no audit report has been filed.
In January 2023 the LPSC staff provided notice of an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2020 through 2022. Discovery is ongoing, and no audit report has been filed.

Entergy Mississippi

Entergy Mississippi’s rate schedules include an energy cost recovery rider and a power management rider, both of which are adjusted annually to reflect accumulated over- or under-recoveries. Entergy Mississippi recovers fuel and purchased energy costs through its energy cost recovery rider and recovers costs associated with natural gas hedging and capacity payments through its power management rider. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.

In November 2021, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an under-recovery of approximately $80.6 million as of September 30, 2021. In December 2021, at the request of the MPSC, Entergy Mississippi submitted a proposal to mitigate the impact of rising fuel costs on customer bills during 2022. Entergy Mississippi proposed that the deferred fuel balance as of December 31, 2021, which was $121.9 million, be amortized over three years and that the MPSC authorize Entergy Mississippi to apply its weighted-average cost of capital as the carrying cost for the unamortized fuel balance. In January 2022 the MPSC approved the amortization of $100 million of the deferred fuel balance over two years and authorized Entergy Mississippi to apply its weighted-average cost of capital as the carrying cost for the unamortized fuel balance. The MPSC approved the proposed energy cost factor effective for February 2022 bills.

See “Complaints Against System Energy - System Energy Settlement with the MPSC” below for discussion of the settlement agreement filed with the FERC in June 2022. The settlement, which was approved by the FERC in November 2022, provided for a refund of $235 million from System Energy to Entergy Mississippi. In July 2022 the MPSC directed the disbursement of settlement proceeds, ordering Entergy Mississippi to provide a one-time $80 bill credit to each of its approximately 460,000 retail customers to be effective during the September 2022 billing cycle and to apply the remaining proceeds to Entergy Mississippi’s under-recovered deferred fuel balance. In accordance with the MPSC’s directive, Entergy Mississippi provided approximately $36.7 million in customer bill credits as a result of the settlement. In November 2022, Entergy Mississippi applied the remaining settlement proceeds in the amount of approximately $198.3 million to Entergy Mississippi’s under-recovered deferred fuel balance.

Entergy Mississippi had a deferred fuel balance of approximately $291.7 million under the energy cost recovery rider as of July 31, 2022, along with an over-recovery balance of $51.1 million under the power management rider. Without further action, Entergy Mississippi anticipated a year-end deferred fuel balance of approximately $200 million after application of a portion of the System Energy settlement proceeds, as discussed above. In September 2022, Entergy Mississippi filed for interim adjustments under both the energy cost recovery rider and the power management rider. Entergy Mississippi proposed five monthly incremental adjustments to the net energy cost factor designed to collect the under-recovered fuel balance as of July 31, 2022 and to reflect the recovery of a higher natural gas price. Entergy Mississippi also proposed five monthly incremental adjustments to the power management adjustment factor designed to flow through to customers the over-recovered power management rider balance as of July 31, 2022. In October 2022 the MPSC approved modified interim adjustments to Entergy Mississippi’s energy cost recovery rider and power management rider. The MPSC approved dividing the energy cost recovery rider interim adjustment into two components that would allow Entergy Mississippi to (1) recover a natural gas fuel rate that is better aligned with current prices; and (2) recover the estimated under-recovered deferred fuel balance as of September 30, 2022 over a period of 20 months. The MPSC approved six monthly incremental adjustments to the net energy cost factor designed to reflect the recovery of a higher natural gas price. The MPSC also approved six monthly incremental adjustments to the power management adjustment factor designed to flow through to customers the over-recovered power management rider balance. In accordance
with the order of the MPSC, Entergy Mississippi did not file an annual redetermination of the energy cost recovery rider or the power management rider in November 2022.

In June 2023 the MPSC approved the joint stipulation agreement between Entergy Mississippi and the Mississippi Public Utilities Staff for Entergy Mississippi’s 2023 formula rate plan filing. The stipulation directed Entergy Mississippi to make a compliance filing to revise its power management cost adjustment factor, to revise its grid modernization cost adjustment factor, and to include a revision to reduce the net energy cost factor to a level necessary to reflect an average natural gas price of $4.50 per MMBtu. The MPSC approved the compliance filing in June 2023, effective for July 2023 bills. See “Retail Rate Proceedings - Filings with the MPSC (Entergy Mississippi) - Retail Rates - 2023 Formula Rate Plan Filing” below for further discussion of the 2023 formula rate plan filing and the joint stipulation agreement.

In November 2023 Entergy Mississippi filed its annual redeterminations of the energy cost factor and the power management cost adjustment factor. The calculation of the annual factor for the energy cost recovery rider included a projected over-recovery balance of approximately $142 million at the end of January 2024. The calculation of the annual factor for the power management rider included a projected under-recovery of $47 million at the end of January 2024. In January 2024 the MPSC approved the proposed energy cost factor and the proposed power management cost factor effective for February 2024 bills.

In June 2024 the MPSC approved the joint stipulation agreement between Entergy Mississippi and the Mississippi Public Utilities Staff for Entergy Mississippi’s 2024 formula rate plan filing. The 2024 formula rate plan filing included the conclusion of the modified interim adjustments to Entergy Mississippi’s energy cost recovery rider and power management rider, which were approved in October 2022 and allowed Entergy Mississippi to recover certain under-collected fuel balances, effective for July 2024 bills. The stipulation provided for Entergy Mississippi to reduce its net energy cost factor. See “Retail Rate Proceedings - Filings with the MPSC (Entergy Mississippi) - Retail Rates - 2024 Formula Rate Plan Filing” below for further discussion of the 2024 formula rate plan filing and the joint stipulation agreement.

In November 2024, Entergy Mississippi filed its annual redeterminations of the energy cost factor and the power management cost adjustment factor. The calculation of the annual factor for the energy cost recovery rider included a projected over-recovery balance of approximately $144.6 million as of September 2024. The calculation of the annual factor for the power management rider included a projected under-recovery of $60.1 million as of September 2024. In January 2025 the MPSC approved a revised energy cost factor, effective for February 2025 bills, that did not reflect the fuel savings associated with Entergy Mississippi’s incremental increase in its share of capacity and energy in connection with Entergy Mississippi’s assumption of Entergy Louisiana’s entitlements to Grand Gulf capacity and energy, which was subject to the MPSC’s review at such time. In February 2025 the MPSC approved Entergy Mississippi’s notice of intent for Entergy Mississippi’s assumption of Entergy Louisiana’s entitlements to Grand Gulf capacity and energy, with associated fuel savings to be reflected in Entergy Mississippi’s energy cost recovery rider, effective for March 2025 bills. Additionally, in February 2025 the MPSC approved the proposed power management cost adjustment factor, effective for March 2025 bills.

Entergy New Orleans

Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.

Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.
Entergy Texas

Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, not recovered in base rates.  Historically, semi-annual revisions of the fixed fuel factor have been made in March and September based on the market price of natural gas and changes in fuel mix.  The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. In 2023 the Texas legislature modified the Texas Utilities Code to provide that material over- and under-recovered fuel balances are to be refunded or surcharged through interim fuel adjustments and that fuel reconciliations must be filed at least once every two years. Entergy Texas expects the PUCT to undertake a rulemaking to effectuate the new legislation in 2025.

In May 2022, Entergy Texas filed an application with the PUCT to implement an interim fuel surcharge to collect the cumulative under-recovery of approximately $51.7 million, including interest, of fuel and purchased power costs incurred from May 1, 2020 through December 31, 2021. The under-recovery balance was primarily attributable to the impacts of Winter Storm Uri, including historically high natural gas prices, partially offset by settlements received by Entergy Texas from MISO related to Hurricane Laura. Entergy Texas proposed that the interim fuel surcharge be assessed over a period of six months beginning with the first billing cycle after the PUCT issues a final order, but no later than the first billing cycle of September 2022. Also in May 2022, the PUCT referred the proceeding to the State Office of Administrative Hearings. In July 2022, Entergy Texas filed on behalf of the parties an unopposed settlement resolving all issues in the proceeding. In addition, Entergy Texas filed on behalf of the parties a motion to admit evidence, to approve interim rates as requested in the initial application, and to remand the proceeding to the PUCT to consider the unopposed settlement. In August 2022 the ALJ with the State Office of Administrative Hearings issued an order granting Entergy Texas’s motion, approving interim rates effective with the first billing cycle of September 2022, and remanding the case to the PUCT for final approval. The interim fuel surcharge was approved by the PUCT in January 2023.

In September 2022, Entergy Texas filed an application with the PUCT to reconcile its fuel and purchased power costs for the period from April 2019 through March 2022. During the reconciliation period, Entergy Texas incurred approximately $1.7 billion in eligible fuel and purchased power expenses, net of certain revenues credited to such expenses and other adjustments. As of the end of the reconciliation period, Entergy Texas’s cumulative under-recovery balance was approximately $103.1 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning April 2022, pending future surcharges or refunds as approved by the PUCT. In November 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In July 2023, Entergy Texas filed an unopposed settlement, supporting testimony, and an agreed motion to admit evidence and remand the proceeding to the PUCT. Pursuant to the unopposed settlement, Entergy Texas would receive no disallowance of fuel costs incurred over the three-year reconciliation period and retain $9.3 million in margins from off-system sales made during the reconciliation period, resulting in a cumulative under-recovery balance of approximately $99.7 million, including interest, as of the end of the reconciliation period. In July 2023 the ALJ with the State Office of Administrative Hearings granted the motion to admit evidence and remanded the proceeding to the PUCT for consideration of the unopposed settlement. The PUCT approved the settlement in September 2023.

In September 2024, Entergy Texas filed an application with the PUCT to reconcile its fuel and purchased power costs for the period from April 2022 through March 2024. During the reconciliation period, Entergy Texas incurred approximately $1.6 billion in eligible fuel and purchased power expenses to generate and purchase electricity to serve its customers, net of certain revenues credited to such expenses and other adjustments. Entergy Texas’s cumulative under-recovery balance for the reconciliation period was approximately $30 million, including interest, which Entergy Texas requested authority to carry over as part of the cumulative fuel balance for the subsequent reconciliation period beginning April 2024. In November 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 procedural schedule, with a hearing on the merits scheduled for May 2025. A PUCT decision is expected in third quarter 2025.
In December 2024, Entergy Texas filed an application with the PUCT to implement an interim fuel refund of $45.5 million, including interest. Entergy Texas proposed that the interim fuel refund be implemented over a three-month period beginning with the first billing cycle in February 2025 for residential and other small customers and through a one-time credit, or surcharge depending on historical usage for the respective customer, for certain transmission voltage level and seasonal agricultural customers in February 2025. Also in December 2024 the PUCT referred the proceeding to the State Office of Administrative Hearings. In January 2025 the ALJ with the State Office of Administrative Hearings issued an order approving the interim fuel refund consistent with Entergy Texas’s application and, because no hearing was requested in the proceeding, dismissing the case from the State Office of Administrative Hearings and the PUCT.
Retail Rate Proceedings

Filings with the APSC (Entergy Arkansas)

Retail Rates

2022 Formula Rate Plan Filing

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

2023 Formula Rate Plan Filing

In July 2023, Entergy Arkansas filed with the APSC its 2023 formula rate plan filing to set its formula rate for the 2024 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2024 and a netting adjustment for the historical year 2022. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2024 projected year was 8.11% resulting in a revenue deficiency of $80.5 million. The earned rate of return on common equity for the 2022 historical year was 7.29% resulting in a $49.8 million netting adjustment. The total proposed revenue change for the 2024 projected year and 2022 historical year netting adjustment was $130.3 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $88.6 million. The APSC general staff and intervenors filed their errors and objections in October 2023, proposing certain adjustments, including the APSC general staff’s update to annual filing year revenues which lowers the constraint to $87.7 million. Entergy Arkansas filed its rebuttal in October 2023. In October 2023, Entergy
Arkansas filed with the APSC a settlement agreement reached with other parties resolving all issues in the proceeding, none of which affected Entergy Arkansas’s requested recovery up to the constraint of $87.7 million. The settlement agreement provided for amortization of the approximately $39 million regulatory asset for costs associated with the COVID-19 pandemic over a 10-year period as well as recovery of $34.9 million related to the resolution of the 2016 and 2017 IRS audits from previous tax positions that are no longer uncertain, partially offset by $24.7 million in excess accumulated deferred income taxes from reductions in state income tax rates, each before consideration of their respective tax gross-up. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit and the State of Arkansas corporate income tax rate changes. In December 2023 the APSC approved the settlement agreement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2024.

2024 Formula Rate Plan Filing

In July 2024, Entergy Arkansas filed with the APSC its 2024 formula rate plan filing to set its formula rate for the 2025 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the 2025 projected year and a netting adjustment for the 2023 historical year. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2025 projected year was 8.43% resulting in a revenue deficiency of $69.5 million. The earned rate of return on common equity for the 2023 historical year was 7.48% resulting in a $33.1 million netting adjustment. The total proposed revenue change for the 2025 projected year and 2023 historical year netting adjustment is $102.6 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $82.6 million. The APSC general staff and intervenors filed their errors and objections in October 2024, proposing certain adjustments, including the APSC general staff’s update to annual filing year revenues that increases the constraint to $83.5 million. Entergy Arkansas filed its rebuttal in October 2024, and later in October 2024 the parties submitted a joint issues list and stipulations setting forth the disputed issues and the noncontested issues. In December 2024 the APSC approved the parties’ stipulations without modification, approved Entergy Arkansas’s adjustment with respect to storm costs, directed Entergy Arkansas to adjust its projected year distribution reliability capital closings, and deferred the recoverability of Entergy Arkansas’s opportunity sales legal fees until the next general rate case. Also in December 2024 the APSC approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2025. As a result of the proceeding, the total revenue change was $82.7 million, including a $63.7 million increase for the 2025 projected year and a $31.4 million netting adjustment for the 2023 historical year. In fourth quarter 2024, Entergy Arkansas recorded a regulatory asset of $15.5 million to reflect the amount of the 2023 historical year netting adjustment that it expects to collect from its customers during the 2025 rate effective period. Pursuant to the terms of the parties’ stipulations, Entergy Arkansas made a filing with the APSC in January 2025 to refund customers $30.1 million in excess accumulated deferred income taxes resulting from the reduction in the State of Arkansas’s income tax rate from 4.8% to 4.3% in 2024. Entergy Arkansas will make this refund over a 24-month period effective with the first billing cycle of February 2025.

Grand Gulf Credit Rider

In June 2024, Entergy Arkansas filed with the APSC a tariff to provide retail customers a credit resulting from the terms of the settlement agreement between Entergy Arkansas, System Energy, additional named Entergy parties, and the APSC pertaining to System Energy’s billings for wholesale sales of energy and capacity from the Grand Gulf nuclear plant. See “Complaints Against System Energy - System Energy Settlement with the APSC” below for discussion of the settlement. In July 2024 the APSC approved the tariff, under which Entergy Arkansas will refund to retail customers a total of $100.6 million. To date, Entergy Arkansas has refunded $92.3 million of the total through one-time bill credits during the August 2024 billing cycle and is finalizing plans for the refund of the remaining regulatory liability balance.
Filings with the LPSC (Entergy Louisiana)

Retail Rates - Electric

2020 Formula Rate Plan Filing

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

In November 2023 the LPSC approved a global settlement which resolved all outstanding issues related to the 2017, 2018, and 2019 formula rate plan filings and resolved certain issues with respect to the 2020 and 2021 formula rate plan filings. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” below for further discussion.

2021 Formula Rate Plan Filing

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

In November 2023 the LPSC approved a global settlement which resolved all outstanding issues related to the 2017, 2018, and 2019 formula rate plan filings and resolved certain issues with respect to the 2020 and 2021
formula rate plan filings. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” below for further discussion.

2022 Formula Rate Plan Filing

In May 2023, Entergy Louisiana filed its formula rate plan evaluation report for its 2022 calendar year operations. The 2022 test year evaluation report produced an earned return on common equity of 8.33%, requiring an approximately $70.7 million increase to base rider revenue. Due to a cap for the 2021 and 2022 test years, however, base rider formula rate plan revenues were only increased by approximately $4.9 million, resulting in a revenue deficiency of approximately $65.9 million and providing for prospective return on common equity opportunity of approximately 8.38%. Other changes in formula rate plan revenue driven by increases in capacity costs, primarily legacy capacity costs, additions eligible for recovery through the transmission recovery mechanism and distribution recovery mechanism, and higher sales during the test period were offset by reductions in net MISO costs as well as credits for FERC-ordered refunds. Also included in the 2022 test year distribution recovery mechanism revenue requirement was a $6 million credit relating to the distribution recovery mechanism performance accountability standards and requirements. In total, the net increase in formula rate plan revenues, including base formula rate plan revenues inside the formula rate plan bandwidth and subject to the cap, as well as other formula rate plan revenues outside of the bandwidth, was $85.2 million. In August 2023 the LPSC staff filed a list of objections/reservations, including outstanding issues from the test years 2017-2021 formula rate plan filings, the calculation of certain refunds from System Energy, and certain calculations relating to the tax reform adjustment mechanism. Subject to LPSC review, the resulting net increase in formula rate plan revenues of $85.2 million became effective for bills rendered during the first billing cycle of September 2023, subject to refund. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” below for further discussion.

2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request

In August 2023, Entergy Louisiana filed an application for approval of a regulatory blueprint necessary for it to strengthen the electric grid for the State of Louisiana, which contained a dual-path request to update rates through either: (1) extension of Entergy Louisiana’s current formula rate plan (with certain modifications) for three years (the Rate Mitigation Proposal), which is Entergy Louisiana’s recommended path; or (2) implementation of rates resulting from a cost-of-service study (the Rate Case path). The application complied with Entergy Louisiana’s previous formula rate plan extension order requiring that for Entergy Louisiana to obtain another extension of its formula rate plan that included a rate reset, Entergy Louisiana would need to submit a full cost-of-service rate case. Entergy Louisiana’s filing supported the need to extend Entergy Louisiana’s formula rate plan with credit supportive mechanisms needed to facilitate investment in the distribution, transmission, and generation functions.

In July 2024, Entergy Louisiana reached an agreement in principle with the LPSC staff and the intervenors in the proceeding and filed with the LPSC a joint motion to suspend the procedural schedule to allow for all parties to finalize a stipulated settlement agreement.

In August 2024, Entergy Louisiana and the LPSC staff jointly filed a global stipulated settlement agreement for consideration by the LPSC with key terms as follows:

•continuation of the formula rate plan for 2024-2026 (test years 2023-2025);
•a base formula rate plan revenue increase of $120 million for test year 2023, effective for rates beginning September 2024;
•a $140 million cumulative cap on base formula rate plan revenue increases, if needed, for test years 2024 and 2025, excluding outside the bandwidth items;
•$184 million of customer rate credits to be given over two years, including increasing customer sharing of income tax benefits resulting from the 2016-2018 IRS audit, to resolve any remaining disputed issues stemming from formula rate plan test years prior to test year 2023, including but not limited to the investigation into Entergy Services costs billed to Entergy Louisiana. As discussed in Note 3 to the financial statements, a $38 million regulatory liability was recorded in 2023 in connection with the 2016-2018 IRS audit;
•$75.5 million of customer rate credits, as provided for in the System Energy global settlement, to be credited over three years subject to and conditioned upon FERC approval of the System Energy global settlement, which was approved in November 2024. See “Complaints Against System Energy – System Energy Settlement with the LPSC” below for further details of the System Energy global settlement;
•$5.8 million of customer rate credits provided for in the Entergy Louisiana formula rate plan global settlement agreement approved by the LPSC in November 2023 credited over one year. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement;
•an increase in the allowed midpoint return on common equity from 9.5% to 9.7%, with a bandwidth of 40 basis points above and below the midpoint, for the extended term of the formula rate plan, except that for test year 2023 in which the authorized return on common equity shall have no bearing on the change in base formula rate plan revenue described above and, for test year 2024, any earnings above the authorized return on common equity shall be returned to customers through a credit;
•an increase in nuclear depreciation rates by $15 million in each of the 2023, 2024, and 2025 test years outside of the formula rate plan bandwidth calculation; and
•for the transmission recovery mechanism and the distribution recovery mechanism, no change to the existing floors, but the caps for both would be $350 million for test year 2023, $375 million for test year 2024, and $400 million for test year 2025. Transmission projects filed with the LPSC will be exempt from the transmission recovery mechanism cap.

The global stipulated settlement agreement was unanimously approved by the LPSC in August 2024 and an order was issued by the LPSC in September 2024 reflecting the approval of the settlement.

Based on the July 2024 agreement in principle, in second quarter 2024 Entergy Louisiana recorded expenses of $151 million ($112 million net-of-tax) primarily consisting of regulatory charges to reflect the effects of the agreement in principle.

Formula Rate Plan Global Settlement

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

2023 Formula Rate Plan Filing

In August 2024, pursuant to the global stipulated settlement agreement, Entergy Louisiana filed its formula rate plan evaluation report for its 2023 calendar year operations. Consistent with the global stipulated settlement agreement, the filing reflected a 9.7% allowed return on common equity with a bandwidth of 40 basis points above and below the midpoint. For the 2023 test year, however, the bandwidth provisions of the formula rate plan were
temporarily suspended and, pursuant to the terms of the global stipulated settlement agreement, Entergy Louisiana implemented the September 2024 formula rate plan rate adjustments effective with the first billing cycle of September 2024. Those adjustments included a $120 million increase in base rider formula rate plan revenue and a $101.8 million one-time incremental net decrease consistent with the terms of the global stipulated settlement. The formula rate plan rate adjustments reflected in the evaluation report also include a redetermination of the transmission recovery mechanism, the distribution recovery mechanism, the additional capacity mechanism, the tax adjustment mechanism, the MISO cost recovery mechanism, and other one-time adjustments. In January 2025, Entergy Louisiana and the LPSC filed a joint report indicating that no disputed issues remained in the proceeding and requesting that the LPSC issue an order accepting Entergy Louisiana’s evaluation report and, ultimately, resolving this matter. Entergy Louisiana expects a decision on the joint report in first quarter 2025.

Investigation of Costs Billed by Entergy Services

In November 2018 the LPSC issued a notice of proceeding initiating an investigation into costs incurred by Entergy Services that are included in the retail rates of Entergy Louisiana. As stated in the notice of proceeding, the LPSC observed an increase in capital construction-related costs incurred by Entergy Services. Discovery was issued and included efforts to seek highly detailed information on a broad range of matters unrelated to the scope of the audit. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” above for further discussion.

COVID-19 Orders

In April 2020 the LPSC issued an order authorizing utilities to record as a regulatory asset expenses incurred from the suspension of disconnections and collection of late fees imposed by LPSC orders associated with the COVID-19 pandemic. In April 2023, Entergy Louisiana filed an application proposing to utilize approximately $1.6 billion in certain low interest debt to generate earnings to apply toward the reduction of the COVID-19 regulatory asset, as well as to conduct additional outside right-of-way vegetation management activities and fund the minor storm reserve account. In that filing, Entergy Louisiana proposed to delay repayment of certain shorter-term first mortgage bonds that were issued to finance storm restoration costs until the costs could be securitized, and to invest the funds that otherwise would be used to repay those bonds in the money pool to take advantage of the spread between prevailing interest rates on investments in the money pool and the interest rates on the bonds. The LPSC approved Entergy Louisiana’s requested relief in June 2023. In November 2024, Entergy Louisiana submitted a filing to the LPSC requesting that the LPSC review Entergy Louisiana’s computation of the COVID-19 regulatory asset as well as Entergy Louisiana’s proposal to offset the regulatory asset against the interest earned on the short-term debt funds, resulting in no increased costs to customers. At the time of the filing, Entergy Louisiana had a regulatory asset of $47.8 million for costs associated with the COVID-19 pandemic. As of December 31, 2024, Entergy Louisiana had a regulatory liability of $48.9 million for the deferred earnings related to the approximately $1.6 billion in low interest debt, which had been fully repaid by August 2024. In granting Entergy Louisiana’s requested relief in June 2023, the LPSC ordered that any amount of earnings exceeding the amount of the COVID-19 regulatory asset be transferred to Entergy Louisiana’s storm reserve escrow account.

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 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.

Filings with the MPSC (Entergy Mississippi)

Retail Rates

2022 Formula Rate Plan Filing

In March 2022, Entergy Mississippi submitted its formula rate plan 2022 test year filing and 2021 look-back filing showing Entergy Mississippi’s earned return for the historical 2021 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2022 calendar year to be below the formula rate plan bandwidth. The 2022 test year filing showed a $69 million rate increase was necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.70% return on rate base, within the formula rate plan bandwidth. The change in formula rate plan revenues, however, was capped at 4% of retail revenues, which equated to a revenue change of $48.6 million. The 2021 look-back filing compared actual 2021 results to the approved benchmark return on rate base and reflected the need for a $34.5 million interim increase in formula rate plan revenues. In fourth quarter 2021, Entergy Mississippi recorded a regulatory asset of $19 million to reflect the then-current estimate in connection with the look-back feature of the formula rate plan. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $24.3 million interim rate increase, reflecting a cap equal to 2% of 2021 retail revenues, effective in April 2022. With the implementation of the interim formula rate plan rates, Entergy Mississippi began recovery of the bad debt expense deferral resulting from the COVID-19 pandemic over a three-year period.

In June 2022, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed the 2022 test year filing that resulted in a total rate increase of $48.6 million. Pursuant to the joint stipulation, Entergy Mississippi’s 2021 look-back filing reflected an earned return on rate base of 5.99% in calendar year 2021, which was below the look-back bandwidth, resulting in a $34.3 million increase in the formula rate plan revenues on an interim basis through June 2023. In July 2022 the MPSC approved the joint stipulation with rates effective in August 2022. In July 2022, Entergy Mississippi recorded regulatory credits of $22.6 million to reflect the effects of the joint stipulation.
In July 2022 the MPSC directed Entergy Mississippi to flow $14.1 million of the power management rider over-recovery balance to customers beginning in August 2022 through December 2022 to mitigate the bill impact of the increase in formula rate plan revenues.

2023 Formula Rate Plan Filing

In March 2023, Entergy Mississippi submitted its formula rate plan 2023 test year filing and 2022 look-back filing showing Entergy Mississippi’s earned return on rate base for the historical 2022 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2023 calendar year to be below the formula rate plan bandwidth. The 2023 test year filing showed a $39.8 million rate increase was necessary to reset Entergy Mississippi’s earned return on rate base to the specified point of adjustment of 6.67%, within the formula rate plan bandwidth. The 2022 look-back filing compared actual 2022 results to the approved benchmark return on rate base and reflected the need for a $19.8 million temporary increase in formula rate plan revenues, including the refund of a $1.3 million over-recovery resulting from the demand-side management costs true-up for 2022. In fourth quarter 2022, Entergy Mississippi recorded a regulatory asset of $18.2 million in connection with the look-back feature of the formula rate plan to reflect that the 2022 estimated earned return was below the formula rate plan bandwidth. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $27.9 million interim rate increase, reflecting a cap equal to 2% of 2022 retail revenues, effective in April 2023.

In May 2023, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed a 2023 test year filing resulting in a total revenue increase of $26.5 million for 2023. Pursuant to the joint stipulation, Entergy Mississippi’s 2022 look-back filing reflected an earned return on rate base of 6.10% in calendar year 2022, which was below the look-back bandwidth, resulting in a $19.0 million increase in the formula rate plan revenues on an interim basis through June 2024. Entergy Mississippi recorded a regulatory credit of $0.8 million in June 2023 to reflect the increase in the look-back regulatory asset. In addition, certain long-term service agreement and conductor handling costs were authorized for realignment from the formula rate plan to the annual power management and grid modernization riders effective January 2023, resulting in regulatory credits recorded in June 2023 of $4.1 million and $4.3 million, respectively. Also, the amortization of Entergy Mississippi’s COVID-19 bad debt expense deferral was suspended for calendar year 2023, but resumed in July 2024. In June 2023 the MPSC approved the joint stipulation with rates effective in July 2023.

2024 Formula Rate Plan Filing

In March 2024, Entergy Mississippi submitted its formula rate plan 2024 test year filing and 2023 look-back filing showing Entergy Mississippi’s earned return on rate base for the historical 2023 calendar year to be within the formula rate plan bandwidth and projected earned return for the 2024 calendar year to be below the formula rate plan bandwidth. The 2024 test year filing showed a $63.4 million rate increase was necessary to reset Entergy Mississippi’s earned return on rate base to the specified point of adjustment of 7.10%, within the formula rate plan bandwidth. The 2023 look-back filing compared actual 2023 results to the approved benchmark return on rate base and reflected no change in formula rate plan revenues. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $32.6 million interim rate increase, reflecting a cap equal to 2% of 2023 retail revenues, effective April 2024.

In December 2014 the MPSC ordered Entergy Mississippi to file an updated depreciation study at least once every four years. Pursuant to this order and Entergy Mississippi’s filing cycle, Entergy Mississippi would have filed an updated depreciation report with its formula rate plan filing in 2023. However, in July 2022 the MPSC directed Entergy Mississippi to file its next depreciation study in connection with its 2024 formula rate plan filing notwithstanding the MPSC’s prior order. Accordingly, Entergy Mississippi filed a depreciation study in February 2024. The study showed a need for an increase in annual depreciation expense of $55.2 million. The calculated increase in annual depreciation expense was excluded from Entergy Mississippi’s 2024 formula rate plan revenue increase request because the MPSC had not yet approved the proposed depreciation rates.
In June 2024, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed the 2024 test year filing, with the exception of immaterial adjustments to certain operation and maintenance expenses. After performance adjustments, the formula rate plan reflected an earned return on rate base of 6.08% for calendar year 2024, which resulted in a total revenue increase of $64.6 million for 2024. The joint stipulation also recommended approval of a revised customer charge of $31.82 per month for residential customers and $53.10 per month for general service customers. Pursuant to the stipulation, Entergy Mississippi’s 2023 look-back filing reflected an earned return on rate base of 6.81%, resulting in an increase of $0.3 million in the formula rate plan revenues for 2023. Finally, the stipulation recommended approval of Entergy Mississippi’s proposed depreciation rates with those rates to be implemented upon request and approval at a later date. In June 2024 the MPSC approved the joint stipulation with rates effective in July 2024. The approval also included a reduction to the energy cost factor, resulting in a net bill decrease for a typical residential customer using 1,000 kWh per month. Also in June 2024, Entergy Mississippi recorded regulatory credits of $7.3 million to reflect the difference between interim rates placed in effect in April 2024 and the rates reflected in the joint stipulation.

In May 2024, Entergy Mississippi received approval from the MPSC for formula rate plan revisions that were necessary for Entergy Mississippi to comply with state legislation passed in January 2024. The legislation allows Entergy Mississippi to make interim rate adjustments 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 filed the first of its annual interim facilities rate adjustment reports in May 2024 to recover approximately $8.7 million of these costs over a six-month period with rates effective beginning in July 2024. Entergy Mississippi filed its second annual interim facilities rate adjustment report in December 2024 to recover approximately $46.7 million of these costs over a 12-month period with rates effective beginning in January 2025.

Grand Gulf Capacity Filing

In September 2024, Entergy Mississippi filed a notice of intent with the MPSC to implement revisions to its unit power cost recovery rider that would allow Entergy Mississippi to recover the first year of costs associated with the transfer of Entergy Louisiana’s entitlements to Grand Gulf capacity and energy, which consists of Energy Louisiana’s interest in and purchases of Grand Gulf capacity and energy under the revised rider schedule, effective by January 1, 2025. This notice filing related to the divestiture of Entergy Louisiana’s 14% share of Grand Gulf capacity and energy under the Unit Power Sales Agreement and 2.43% share of capacity and energy from Entergy Arkansas under the MSS-4 replacement tariff. This divestiture is being effectuated initially through Entergy Mississippi’s purchases from Entergy Louisiana pursuant to a PPA governed by the MSS-4 replacement tariff, a tariff governing the sales of energy and capacity among the Utility operating companies as described in the System Energy global settlement with the LPSC and Entergy Louisiana. The MSS-4 replacement PPA to effectuate this divestiture was approved by the FERC in November 2024. In February 2025 the MPSC approved Entergy Mississippi’s notice of intent, finding that it was just and reasonable for Entergy Mississippi to obtain Entergy Louisiana’s entitlements to Grand Gulf capacity and energy and that Entergy Mississippi should be allowed to recover the costs associated with the transfer of such entitlements to Grand Gulf capacity and energy, as described above. The MPSC approved the MSS-4 replacement PPA, effective as of January 1, 2025. See “Complaints Against System Energy – System Energy Settlement with the LPSC” below for further details of the System Energy global settlement with the LPSC and Note 8 to the financial statements for discussion of the Unit Power Sales Agreement.

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.

Filings with the City Council (Entergy New Orleans)

Retail Rates

2022 Formula Rate Plan Filing

In April 2022, Entergy New Orleans submitted to the City Council its formula rate plan 2021 test year filing. The 2021 test year evaluation report, subsequently updated in a July 2022 filing, produced an earned return on equity of 6.88% compared to the authorized return on equity of 9.35%. Entergy New Orleans sought approval of a $42.1 million rate increase based on the formula set by the City Council in the 2018 rate case. The formula resulted in an increase in authorized electric revenues of $34.1 million and an increase in authorized gas revenues of $3.3 million. Entergy New Orleans also sought to commence collecting $4.7 million in electric revenues that were previously approved by the City Council for collection through the formula rate plan. In July 2022 the City Council’s advisors issued a report seeking a reduction to Entergy New Orleans’s proposed increase of approximately $17.1 million in total for electric and gas revenues. Effective with the first billing cycle of September 2022, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council including adjustments filed in the City Council’s advisors’ report, per the approved process for formula rate plan implementation. The total formula rate plan increase implemented was $24.7 million, which includes an increase of $18.2 million in electric revenues, $4.7 million in previously approved electric revenues, and an increase of $1.8 million in gas revenues. Additionally, credits of $13.9 million funded by certain regulatory liabilities currently held by Entergy New Orleans for customers were issued over an eight-month period beginning September 2022.

2023 Formula Rate Plan Filing

In April 2023, Entergy New Orleans submitted to the City Council its formula rate plan 2022 test year filing. The 2022 test year evaluation report produced an electric earned return on equity of 7.34% and a gas earned return on equity of 3.52% compared to the authorized return on equity for each of 9.35%. Entergy New Orleans sought approval of a $25.6 million rate increase based on the formula set by the City Council in the 2018 rate case. The formula would result in an increase in authorized electric revenues of $17.4 million and an increase in authorized gas revenues of $8.2 million. Entergy New Orleans also sought to commence collecting $3.4 million in electric revenues that were previously approved by the City Council for collection through the formula rate plan. In July 2023, Entergy New Orleans filed a report to decrease its requested formula rate plan revenues by approximately $0.5 million to account for minor errors discovered after the filing. The City Council advisors issued a report seeking a reduction in the requested formula rate plan revenues of approximately $8.3 million, combined for electric and gas, due to alleged errors. The City Council advisors proposed additional rate mitigation in the amount of $12 million through offsets to the formula rate plan rate increase by certain regulatory liabilities. In September 2023 the City Council approved an agreement to settle the 2023 formula rate plan filing. Effective with the first billing cycle of September 2023, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council, per the approved process for formula rate plan implementation. The agreement provides for a total increase in electric revenues of $10.5 million and a total increase in gas revenues of
$6.9 million. The agreement also provides for a minor storm accrual of $0.5 million per year and the distribution of $8.9 million of currently held customer credits to implement the City Council advisors’ mitigation recommendations.

Request for Extension and Modification of Formula Rate Plan

In September 2023, Entergy New Orleans filed a motion seeking City Council approval of a three-year extension of Entergy New Orleans’s electric and gas formula rate plans. In October 2023 the City Council granted Entergy New Orleans’s request for an extension, subject to minor modifications which included a 55% equity ratio for rate setting purposes.

2024 Formula Rate Plan Filing

In April 2024, Entergy New Orleans submitted to the City Council its formula rate plan 2023 test year filing. Without the requested rate change in 2024, the 2023 test year evaluation report produced an electric earned return on equity of 8.66% and a gas earned return on equity of 5.87% compared to the authorized return on equity for each of 9.35%. Entergy New Orleans sought approval of a $12.6 million rate increase based on the formula set by the City Council in the 2018 rate case and approved again by the City Council in 2023. The formula would result in an increase in authorized electric revenues of $7.0 million and an increase in authorized gas revenues of $5.6 million. Following City Council review, the City Council’s advisors issued a report in July 2024 seeking a reduction in Entergy New Orleans’s requested formula rate plan revenues in an aggregate amount of approximately $1.6 million for electric and gas together due to alleged errors. Effective with the first billing cycle of September 2024, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council, per the approved process for formula rate plan implementation. The total formula rate plan increase implemented was $11.2 million, which includes an increase of $5.8 million in electric revenues and an increase of $5.4 million in gas revenues.

Filings with the PUCT and Texas Cities (Entergy Texas)

Retail Rates

2022 Base Rate Case

In July 2022, Entergy Texas filed a base rate case with the PUCT seeking a net increase in base rates of approximately $131.4 million. The base rate case was based on a 12-month test year ending December 31, 2021. Key drivers of the requested increase were changes in depreciation rates as the result of a depreciation study and an increase in the return on equity. In addition, Entergy Texas included capital additions placed into service for the period of January 1, 2018 through December 31, 2021, including those additions reflected in the then-effective distribution and transmission cost recovery factor riders and the generation cost recovery rider, all of which were reset to zero in June 2023 as a result of this proceeding. In July 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In October 2022 intervenors filed direct testimony challenging and supporting various aspects of Entergy Texas’s rate case application. The key issues addressed included the appropriate return on equity, generation plant deactivations, depreciation rates, and proposed tariffs related to electric vehicles. In November 2022 the PUCT staff filed direct testimony addressing a similar set of issues and recommending a reduction of $50.7 million to Entergy Texas’s overall cost of service associated with the requested net increase in base rates of approximately $131.4 million. Entergy Texas filed rebuttal testimony in November 2022.

In May 2023, Entergy Texas filed on behalf of the parties an unopposed settlement resolving all issues in the proceeding, except for issues related to electric vehicle charging infrastructure which were eventually severed to a separate proceeding and resolved in October 2024, and Entergy Texas filed an agreed motion for interim rates, subject to refund or surcharge to the extent that the interim rates differ from the final approved rates. The unopposed settlement reflected a net base rate increase to be effective and relate back to December 2022 of
$54 million, exclusive of, and incremental to, the costs being realigned from the distribution and transmission cost recovery factor riders and the generation cost recovery rider and $4.8 million of rate case expenses to be recovered through a rider over a period of 36 months. The net base rate increase of $54 million includes updated depreciation rates and a total annual revenue requirement of $14.5 million for the accrual of a self-insured storm reserve and the recovery of the regulatory assets for the pension and postretirement benefits expense deferral, costs associated with the COVID-19 pandemic, and retired non-advanced metering system electric meters. In May 2023 the ALJ with the State Office of Administrative Hearings granted the motion for interim rates, which became effective in June 2023. Additionally, the ALJ remanded the proceeding to the PUCT to consider the settlement. In August 2023 the PUCT issued an order approving the unopposed settlement. Concurrently, Entergy Texas recorded the reversal of $21.9 million of regulatory liabilities to reflect the recognition of certain receipts by Entergy Texas under affiliated PPAs that have been resolved.

Following the PUCT’s approval of the unopposed settlement in August 2023, Entergy Texas recorded a regulatory liability of $10.3 million, which reflected the net effects of higher depreciation and amortizations for the relate back period, partially offset by the relate back of base rate revenues that would have been collected had the approved rates been in effect for the period from December 2022 through June 2023, the date the new base rates were implemented on an interim basis. In October 2023, Entergy Texas filed a relate back surcharge rider to collect over six months beginning in January 2024 an additional approximately $24.6 million, which was the revenue requirement associated with the relate back of rates from December 2022 through June 2023, including carrying costs, as authorized by the PUCT’s August 2023 order. In November 2023, Entergy Texas filed an amended relate back surcharge rider to collect approximately $24.1 million based on a revised carrying cost rate. The amended relate back surcharge rider was approved by the PUCT in December 2023. The higher depreciation and amortizations for the relate back period were also recognized over the six months beginning in January 2024, resulting in no effect on net income from the collection of the relate back surcharge rider.

Distribution Cost Recovery Factor (DCRF) Rider

In June 2024, Entergy Texas filed with the PUCT a request to set a new DCRF rider. The new rider was designed to collect from Entergy Texas’s retail customers approximately $40.3 million annually based on its capital invested in distribution between January 1, 2022 and March 31, 2024. In September 2024 the PUCT approved the DCRF rider, consistent with Entergy Texas’s as-filed request, and rates became effective with the first billing cycle in October 2024.

In September 2024, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $48.9 million annually, or $8.6 million in incremental annual revenues beyond Entergy Texas’s then-effective DCRF rider based on its capital invested in distribution between April 1, 2024 and June 30, 2024. In December 2024, Entergy Texas filed an errata to revise its DCRF application for minor corrections, which decreased the requested annual revenue requirement to $48.5 million. The amended request represented an incremental increase of $8.2 million in annual revenues beyond Entergy Texas’s then-effective DCRF rider. Also in December 2024 the PUCT approved the DCRF rider, consistent with Entergy Texas’s filed errata, and rates became effective on December 20, 2024.

Transmission Cost Recovery Factor (TCRF) Rider

In December 2018, Entergy Texas filed with the PUCT a request to set a new TCRF rider. The new TCRF rider was designed to collect approximately $2.7 million annually from Entergy Texas’s retail customers based on its capital invested in transmission between January 1, 2018 and September 30, 2018. In April 2019 parties filed testimony proposing a load growth adjustment, which would fully offset Entergy Texas’s proposed TCRF revenue requirement. In July 2019 the PUCT granted Entergy Texas’s application as filed to begin recovery of the requested $2.7 million annual revenue requirement, rejecting opposing parties’ proposed adjustment; however, the PUCT found that the question of prudence of the actual investment costs should be determined in Entergy Texas’s next rate case similar to the procedure used for the costs recovered through the DCRF rider. In October 2019 the PUCT
issued an order on a motion for rehearing, clarifying and affirming its prior order granting Entergy Texas’s application as filed. Also in October 2019 a second motion for rehearing was filed, and Entergy Texas filed a response in opposition to the motion. The second motion for rehearing was overruled by operation of law. In December 2019, Texas Industrial Energy Consumers filed an appeal to the PUCT order in district court alleging that the PUCT erred in declining to apply a load growth adjustment.

In October 2021, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $66.1 million annually, or $15.1 million in incremental annual revenues beyond Entergy Texas’s then-effective TCRF rider based on its capital invested in transmission between September 1, 2020 and July 31, 2021 and changes in approved transmission charges. In January 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In February 2022 the parties filed an unopposed settlement recommending that Entergy Texas be allowed to collect its full requested TCRF revenue requirement with interim rates effective March 2022. In February 2022 the ALJ granted the motion for interim rates, admitted evidence, and remanded the case to the PUCT for consideration of a final order at a future open meeting. In June 2022 the PUCT issued an order approving the settlement.

In October 2024, Entergy Texas filed with the PUCT a request to amend its TCRF rider, which was previously reset to zero in June 2023 as a result of the 2022 base rate case. The proposed rider is designed to collect from Entergy Texas’s retail customers approximately $9.7 million annually based on its capital invested in transmission between January 1, 2022 and June 30, 2024 and changes in other transmission charges. In December 2024 the PUCT staff filed a recommendation that the PUCT approve Entergy Texas’s as-filed application. In February 2025 the PUCT staff issued a proposed order that, if approved by the PUCT, would approve Entergy Texas’s TCRF rider as filed.

Generation Cost Recovery Rider

In October 2020, Entergy Texas filed an application to establish a generation cost recovery rider to begin recovering a return of and on its generation capital investment in the Montgomery County Power Station. Entergy Texas filed an unopposed settlement agreement in December 2020, and the PUCT approved the generation cost recovery rider settlement rates on an interim basis in January 2021. In March 2021, Entergy Texas filed to update its generation cost recovery rider, and an unopposed settlement agreement filed by Entergy Texas on behalf of the parties in October 2021 was approved by the PUCT in January 2022. In February 2022, Entergy Texas filed a relate-back rider to collect over five months an additional approximately $5 million, which was the difference between the interim revenue requirement approved in January 2021 and the revenue requirement approved in January 2022 reflecting Entergy Texas’s full generation capital investment and ownership in Montgomery County Power Station on January 1, 2021, plus carrying costs from January 2021 through January 2022 when the updated revenue requirement took effect. The PUCT approved the relate-back rider consistent with Entergy Texas’s as-filed request, and rates became effective over a five-month period, in August 2022.

In December 2020, Entergy Texas also filed an application to amend its generation cost recovery rider to reflect its acquisition of the Hardin County Peaking Facility, which closed in June 2021. Because Hardin was to be acquired in the future, the initial generation cost recovery rider rates proposed in the application represented no change from the generation cost recovery rider rates established in Entergy Texas’s previous generation cost recovery rider proceeding. In July 2021 the PUCT issued an order approving the application. In August 2021, Entergy Texas filed an update application to recover its actual investment in the acquisition of the Hardin County Peaking Facility, and in January 2022, Entergy Texas filed an update to its application to align the requested revenue requirement with the terms of the generation cost recovery rider settlement approved by the PUCT in January 2022. In April 2022, Entergy Texas filed on behalf of the parties a unanimous settlement agreement that would adjust its generation cost recovery rider to recover an annual revenue requirement of approximately $92.8 million, which was $4.5 million in incremental annual revenue above the revenue requirement approved in January 2022 described above and related to Entergy Texas’s investment in the Montgomery County Power Station. The PUCT approved the settlement agreement and rates became effective in August 2022. In September 2022,
Entergy Texas filed a relate-back rider designed to collect over three months an additional approximately $5.7 million, which is the revenue requirement, plus carrying costs, associated with Entergy Texas’s acquisition of Hardin County Peaking Facility from June 2021 through August 2022 when the updated revenue requirement took effect. In April 2023 the PUCT approved Entergy Texas’s as-filed request with rates effective over three months beginning in May 2023.
Entergy Arkansas Opportunity Sales Proceeding

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

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

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

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

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

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

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

In October 2018 the FERC issued an order addressing the ALJ’s July 2017 initial decision. The FERC reversed the ALJ’s decision to cap the reduction in Entergy Arkansas’s payment to account for the increased bandwidth payments that Entergy Arkansas made to the other operating companies. The FERC also reversed the ALJ’s decision that Grand Gulf sales from January through September 2000 should be included in the calculation of Entergy Arkansas’s payment. The FERC affirmed on other grounds the ALJ’s rejection of the LPSC’s claim that certain joint account sales should be accounted for as part of the calculation of Entergy Arkansas’s payment. In November 2018 the LPSC requested rehearing of the FERC’s October 2018 decision. In December 2019 the FERC denied the LPSC’s request for rehearing. In January 2020 the LPSC appealed the December 2019 decision to the D.C. Circuit.
In December 2018, Entergy made a compliance filing in response to the FERC’s October 2018 order. The compliance filing provided a final calculation of Entergy Arkansas’s payments to the other Utility operating companies, including interest. No protests were filed in response to the December 2018 compliance filing. Refunds and interest in the following amounts were paid by Entergy Arkansas to the other operating companies in December 2018:
 Total refunds including interest
Payment/(Receipt)
 (In Millions)
PrincipalInterestTotal
Entergy Arkansas$68$67$135
Entergy Louisiana($30)($29)($59)
Entergy Mississippi($18)($18)($36)
Entergy New Orleans($3)($4)($7)
Entergy Texas($17)($16)($33)

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

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

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

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

In July 2020 the APSC issued a decision finding that Entergy Arkansas’s application is not in the public interest. The order also directed Entergy Arkansas to refund to its retail customers within 30 days of the order the FERC-determined over-collection of $13.7 million, plus interest, associated with a recalculated bandwidth remedy. In addition to these primary findings, the order also denied the Attorney General’s request for Entergy Arkansas to prepare a compliance filing detailing all of the retail impacts from the opportunity sales and denied a request by the Arkansas Electric Energy Consumers to recalculate all costs using the revised responsibility ratio. Entergy Arkansas filed a motion for temporary stay of the 30-day requirement to allow Entergy Arkansas a reasonable opportunity to seek rehearing of the APSC order, but in July 2020 the APSC denied Entergy Arkansas’s request for a stay and directed Entergy Arkansas to refund to its retail customers the component of the total FERC-determined opportunity sales payment that was associated with increased bandwidth remedy payments of $13.7 million, plus interest. The refunds were issued in the August 2020 billing cycle. While the APSC denied Entergy Arkansas’s stay request, Entergy Arkansas believes its actions were prudent and, therefore, the costs, including the $13.7 million, plus interest, are recoverable. In July 2020, Entergy Arkansas requested rehearing of the APSC order, which rehearing was denied by the APSC in August 2020. In September 2020, Entergy Arkansas filed a complaint in the U.S. District Court for the Eastern District of Arkansas challenging the APSC’s order denying Entergy Arkansas’s request to recover the costs of these payments. In October 2020 the APSC filed a motion to dismiss Entergy Arkansas’s complaint, to which Entergy Arkansas responded. Also in December 2020, Entergy Arkansas and the APSC held a pre-trial conference, and filed a report with the court in January 2021. The court held a hearing in February 2021 regarding issues addressed in the pre-trial conference report, and in June 2021 the court stayed all discovery until it rules on pending motions, after which the court will issue an amended schedule if necessary. In March 2022 the court denied the APSC’s motion to dismiss, and, in April 2022, issued a scheduling order including a trial date in February 2023. In June 2022, Entergy Arkansas filed a motion asserting that it is entitled to summary judgment because Entergy Arkansas’s position that the APSC’s order is pre-empted by the filed rate doctrine and violates the Dormant Commerce Clause is premised on facts that are not subject to genuine dispute. In July 2022, Arkansas Electric Energy Consumers, Inc., an industrial customer association, filed a motion to intervene and to hold Entergy Arkansas’s motion for summary judgment in abeyance pending a ruling on the motion to intervene. Entergy Arkansas filed a consolidated opposition to both motions. In August 2022 the APSC filed a motion for summary judgment arguing that there is no genuine issue as to any material fact and the APSC is entitled to judgment as a matter of law. In September 2022, Entergy Arkansas filed an opposition to the motion. In October 2022 the APSC filed a motion asking the court to hold further proceedings in abeyance pending a decision on the motions for summary judgment filed by Entergy Arkansas and the APSC. Also in October 2022, Entergy Arkansas filed an opposition to the motion, and the APSC filed a reply in support of its motion for summary judgment. In January 2023 the judge assigned to the case, on her own motion, identified facts that may present a conflict and recused herself; a new judge was assigned to the case, but he also recused due to a conflict. The case again was reassigned to a new judge. In January 2023 the court denied all pending motions (including those described above) except for a motion by the APSC to exclude certain testimony and further ruled that the matter would proceed to trial. In January 2023, Arkansas Electric Energy Consumers, Inc. filed a notice of appeal of the court’s order denying its motion to intervene to the United States Court of Appeals for the Eighth Circuit and a motion with the district court to stay the proceedings pending the appeal, which was denied. In February 2023, Arkansas Electric Energy Consumers, Inc. filed a motion with the United States Court of Appeals for the Eighth Circuit to stay the proceedings pending the appeal, which also was denied. The trial was held in February 2023. Following the trial, Entergy Arkansas filed a motion with the United States Court of Appeals for the Eighth Circuit to expedite the appeal filed by Arkansas Electric Energy Consumers, Inc. The United States Court of Appeals for
the Eighth Circuit granted Entergy Arkansas’s request, and oral arguments were held in June 2023. In August 2023 the United States Court of Appeals for the Eighth Circuit affirmed the order of the court denying Arkansas Electric Energy Consumers, Inc.’s motion to intervene.

In March 2024 the U.S. District Court for the Eastern District of Arkansas issued a judgment in favor of the APSC and against Entergy Arkansas. In March 2024 Entergy Arkansas filed a notice of appeal and a motion to expedite oral arguments with the United States Court of Appeals for the Eighth Circuit and the court granted the motion to expedite. Briefing to the United States Court of Appeals for the Eighth Circuit concluded in July 2024 and oral arguments concluded in September 2024. As a result of the adverse decision by the U.S. District Court for the Eastern District of Arkansas, Entergy Arkansas concluded that it could no longer support the recognition of its $131.8 million regulatory asset reflecting the previously-expected recovery of a portion of the costs at issue in the opportunity sales proceeding and recorded a $131.8 million ($99.1 million net-of-tax) charge to earnings in first quarter 2024. In December 2024 the United States Court of Appeals for the Eighth Circuit affirmed the decision of the U.S. District Court for the Eastern District of Arkansas, and Entergy Arkansas filed a petition for rehearing en banc. In January 2025 the United States Court of Appeals for the Eighth Circuit denied Entergy Arkansas’s petition. Entergy Arkansas is evaluating a petition for certiorari with the United States Supreme Court.
MSS-4 Replacement Tariff – Net Operating Loss Carryforward Proceeding

In January 2021, pursuant to section 205 of the Federal Power Act, Entergy Services filed an amendment to the MSS-4 replacement tariff, a tariff governing the sales of energy and capacity among the Utility operating companies, in order to provide for the inclusion of specified accumulated deferred income taxes, including net operating loss carryforward accumulated deferred income taxes (NOLC ADIT), in the rate for sales of energy among the Utility operating companies on a prospective basis. In March 2021, the FERC accepted the filing, subject to refund and hearing procedures.

In October 2021 the LPSC filed a complaint with the FERC alleging that Entergy Services improperly excluded NOLC ADIT from MSS-4 replacement tariff rates in the period before March 20, 2021. The LPSC argued that sales from Entergy Louisiana to Entergy Texas and Entergy New Orleans were charged at rates lower than they otherwise should have been, and it accordingly seeks surcharges for the period prior to March 20, 2021. The FERC set the complaint for hearing procedures and subsequently the hearing for this complaint proceeding was consolidated with the hearing procedures for Entergy Services’ January 2021 NOLC ADIT filing.

Testimony was filed by parties in 2023, and the hearing before a FERC ALJ was concluded in February 2024. In June 2024, the FERC ALJ issued an initial decision addressing three major issues: (1) whether Entergy Services’ proposed prospective inclusion and allocation of NOLC ADIT in MSS-4 replacement tariff rates using a modified with-and-without methodology is just and reasonable; (2) whether Entergy Services correctly calculated excess and deficient accumulated deferred income taxes in accordance with the terms of a prior settlement; and (3) whether NOLC ADIT should have been included in MSS-4 replacement tariff rates prior to the effective date of the January 2021 MSS-4 replacement tariff filing.

With respect to issues (1) and (2), the presiding ALJ concluded that Entergy Services’ proposed methodology for allocating and including NOLC ADIT in MSS-4 replacement tariff rates was just and reasonable and that Entergy Services correctly performed the excess and deficient accumulated deferred income taxes calculations. With respect to issue (3), however, the presiding ALJ agreed with the LPSC that NOLC ADIT should have been included in MSS-4 replacement tariff rates since September 1, 2016, and as a result, the presiding ALJ ordered that Entergy Louisiana and Entergy Arkansas recalculate bills for the period of September 1, 2016 through November 11, 2023 with surcharges expected to be due to those operating companies from the purchasing operating companies, Entergy New Orleans, Entergy Texas, and Entergy Louisiana (for some Entergy Arkansas sales). The presiding ALJ also ordered Entergy Services to pay the interest owed to Entergy Louisiana on these surcharges.
The surcharge methodology that the presiding ALJ recommended in connection with issue (3) was not supported by any participant in the hearing. As part of their exceptions to the initial decision, all parties to the proceeding opposed the use of the ALJ’s methodology, except for the FERC trial staff, which took no position. During the hearing, the LPSC and the FERC trial staff advocated that the alleged tariff violation should be remedied by the application of Entergy Services’ January 2021 proposed methodology. All other parties, including the PUCT, the City Council, and Entergy Services, opposed any surcharges for the period prior to the March 20, 2021 effective date of the January 2021 filing.

Entergy Services disputes the presiding ALJ's rulings on issue (3) and filed exceptions to these rulings in July 2024. The ALJ's initial decision is not binding on the FERC and is an interim step in the hearing process. No refunds will be owed in connection with this proceeding unless and until the FERC requires them in a final order.
Complaints Against System Energy

System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf.  System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. System Energy and the Unit Power Sales Agreement have been the subject of several litigation proceedings at the FERC, including challenges with respect to System Energy’s authorized return on equity and capital structure, renewal of its sale-leaseback arrangement, treatment of uncertain tax positions, a broader investigation of rates under the Unit Power Sales Agreement, and two prudence complaints, one challenging the extended power uprate completed at Grand Gulf in 2012 and the operation and management of Grand Gulf, particularly in the 2016-2020 time period, and the second challenging the operation and management of Grand Gulf in the 2021-2022 time period. Settlements that resolve all significant aspects of these complaints have been reached with the MPSC, the APSC, the City Council, and the LPSC, and these settlements have been approved by the FERC. Following are discussions of the proceedings.

Return on Equity and Capital Structure Complaints

In January 2017 the APSC and the MPSC filed a complaint with the FERC against System Energy. The complaint sought a reduction in the return on equity component of the Unit Power Sales Agreement pursuant to which System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. Entergy Arkansas also sells some of its Grand Gulf capacity and energy to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under separate agreements. The return on equity under the Unit Power Sales Agreement at the time of the complaint was 10.94%, which was established in a rate proceeding that became final in July 2001.

The APSC and the MPSC complaint alleged that the return on equity was unjust and unreasonable because capital market and other considerations indicated that it was excessive. The complaint requested proceedings to investigate the return on equity and establish a lower return on equity, and also requested that the FERC establish January 23, 2017 as a refund effective date. The complaint included a return on equity analysis that purported to establish that the range of reasonable return on equity for System Energy was between 8.37% and 8.67%. System Energy answered the complaint in February 2017 and disputed that a return on equity of 8.37% to 8.67% was just and reasonable. The LPSC and the City Council intervened in the proceeding expressing support for the complaint. In September 2017 the FERC established a refund effective date of January 23, 2017 and directed the parties to engage in settlement proceedings before an ALJ. The parties were unable to settle the return on equity issue and a FERC hearing judge was assigned in July 2018. The 15-month refund period in connection with the APSC/MPSC complaint expired on April 23, 2018.

In April 2018 the LPSC filed a complaint with the FERC against System Energy seeking an additional 15-month refund period.  The LPSC complaint requested similar relief from the FERC with respect to System Energy’s
return on equity and also requested the FERC to investigate System Energy’s capital structure.  The APSC, the MPSC, and the City Council intervened in the proceeding, filed an answer expressing support for the complaint, and asked the FERC to consolidate this proceeding with the proceeding initiated by the complaint of the APSC and the MPSC in January 2017. System Energy answered the LPSC complaint in May 2018 and also filed a motion to dismiss the complaint. In August 2018 the FERC issued an order dismissing the LPSC’s request to investigate System Energy’s capital structure and setting for hearing the return on equity complaint, with a refund effective date of April 27, 2018. The 15-month refund period in connection with the LPSC return on equity complaint expired on July 26, 2019.

The portion of the LPSC’s complaint dealing with return on equity was subsequently consolidated with the APSC and the MPSC complaint for hearing. The parties also addressed an order (issued in a separate FERC proceeding involving New England transmission owners) that proposed modifying the FERC’s standard methodology for determining return on equity. In September 2018 the LPSC filed an amended complaint raising the same capital structure claim the FERC had earlier dismissed. The FERC initiated a new proceeding for the amended capital structure complaint, and System Energy answered the complaint in October 2018. In January 2019 the FERC set the amended complaint for settlement and hearing proceedings. Settlement proceedings in the capital structure proceeding commenced in February 2019, but were terminated in June 2019, and the amended capital structure complaint was consolidated with the ongoing return on equity proceeding. The 15-month refund period in connection with the capital structure complaint was from September 24, 2018 to December 23, 2019.

Several rounds of testimony were filed by the parties in these proceedings between January 2019 and August 2020. Some of these rounds of testimony were precipitated by developments in an unrelated proceeding in which the FERC issued orders addressing the methodology for determining the return on equity applicable to transmission owners in MISO (Opinion Nos. 569 and 569-A). The final positions of the parties, after the submission of all pre-filed testimony, were as follows. With regard to the return on equity complaints for the first refund period, based on their respective interpretations and applications of the Opinion No. 569-A methodology, the LPSC argued for an authorized return on equity for System Energy of 7.97%; the MPSC and the APSC argued for an authorized return on equity of 9.24%; and the FERC trial staff argued for an authorized return on equity of 9.49%. For the second refund period and on a prospective basis, based on their respective interpretations and applications of the Opinion No. 569-A methodology, the LPSC argued for an authorized return on equity for System Energy of 7.78%; the MPSC and the APSC argued that an authorized return on equity of 9.15% may be appropriate if the second complaint was not dismissed; and the FERC trial staff argued for an authorized return on equity of 9.09% if the second complaint was not dismissed. The LPSC also continued to support as its primary recommendation, based on an alternative analysis to the Opinion No. 569-A methodology, an authorized return on equity for System Energy as low as 7.56% for the first complaint refund period and as low as 7.18% for the second complaint refund period and prospectively. The MPSC and the APSC also continued to support as their primary recommendation, based on an alternative analysis to the Opinion No. 569-A methodology, an authorized return on equity for System Energy as low as 8.26% for the first complaint refund period and as low as 8.32% for the second complaint refund period and prospectively. System Energy argued that strict application of the Opinion No. 569-A methodology produces results inconsistent with investor requirements and does not provide a sound basis on which to evaluate System Energy’s authorized return on equity. Therefore, as its primary recommendation, System Energy argued for the use of a methodology that incorporates four separate financial models and, based on application of this recommended methodology, an authorized return on equity of 10.12% for the first refund period, which also fell within the presumptively just and reasonable range calculated for the second refund period and prospectively. Under the Opinion No. 569-A methodology, System Energy calculated an authorized return on equity of 9.44% for the first refund period, which also fell within the presumptively just and reasonable range calculated for the second refund period and prospectively.

With regard to the capital structure, the LPSC’s primary recommendation was that the FERC establish a hypothetical capital structure for System Energy for ratemaking purposes, according to which System Energy’s common equity ratio would be set to Entergy Corporation’s equity ratio of 37% equity and 63% debt. The APSC and the MPSC recommended that 35.98% be set as the common equity ratio for System Energy. The FERC trial
staff argued that the average capital structure of the proxy group used to develop System Energy’s return on equity should be used to establish the capital structure. Using this approach, the FERC trial staff calculated the average capital structure for its proposed proxy group of 46.74% common equity and 53.26% debt. System Energy disputed all of these recommendations and argued that the use of its actual capital structure was just and reasonable.

After conducting a hearing, in March 2021 the FERC ALJ issued an initial decision. With regard to System Energy’s authorized return on equity, the ALJ determined that the existing return on equity of 10.94% was no longer just and reasonable, and that the replacement authorized return on equity, based on application of the Opinion No. 569-A methodology, should be 9.32%. The ALJ further determined that System Energy should pay refunds for a fifteen-month refund period (January 2017-April 2018) based on the difference between the current return on equity and the replacement authorized return on equity. The ALJ determined that the April 2018 complaint concerning the authorized return on equity should be dismissed, and that no refunds for a second fifteen-month refund period should be due. With regard to System Energy’s capital structure, the ALJ determined that System Energy’s actual equity ratio was excessive and that the just and reasonable equity ratio was 48.15% equity, based on the average equity ratio of the proxy group used to evaluate the return on equity for the second complaint. The ALJ further determined that System Energy should pay refunds for a fifteen-month refund period (September 2018-December 2019) based on the difference between the actual equity ratio and the 48.15% equity ratio.

In April 2021, System Energy filed its brief on exceptions, in which it challenged the initial decision’s findings on both the return on equity and capital structure issues. Also in April 2021 the LPSC, the APSC, the MPSC, the City Council, and the FERC trial staff filed briefs on exceptions. Reply briefs opposing exceptions were filed in May 2021 by System Energy, the FERC trial staff, the LPSC, the APSC, the MPSC, and the City Council.

As discussed below in “System Energy Settlement with the MPSC,” “System Energy Settlement with the APSC,” “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the MPSC, the APSC, the City Council, and the LPSC have settled their claims related to these proceedings. As part of the settlements with their respective retail regulators, effective July 2022 for Entergy Mississippi, November 2023 for Entergy Arkansas, June 2024 for Entergy New Orleans, and September 2024 for Entergy Louisiana, bills issued under the Unit Power Sales Agreement reflect a return on equity of 9.65% and a capital structure not to exceed 52% equity.

In August 2022 the D.C. Circuit issued an order addressing appeals of FERC’s Opinion No. 569 and 569-A, which established the methodology applied in the ALJ’s initial decision in the proceeding against System Energy discussed above. The appellate order addressed the methodology for determining the return on equity applicable to transmission owners in MISO. The D.C. Circuit found the FERC’s use of the Risk Premium model as part of the methodology to be arbitrary and capricious, and remanded the case back to the FERC. In October 2024, after System Energy had reached settlements with each of the retail regulators involved in the return on equity and capital structure proceeding discussed above, the FERC issued a remand order in the MISO transmission owners’ return on equity case, concluding that the record supported the methodology that it originally directed in Opinion No. 569 utilizing an equal weighting of the two-step discounted cash flow model and capital asset pricing model. As a result, it determined that the just and reasonable return on equity for the MISO transmission owners is 9.98%. In light of the System Energy settlements detailed below, the FERC’s changes to its return on equity methodology in the decision on the MISO transmission owners’ return on equity will not have any immediate effect on System Energy’s return on equity because System Energy’s return on equity has been set at 9.65% through the global settlement through the end of June 2026.

Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue

In May 2018 the LPSC filed a complaint against System Energy and Entergy Services related to System Energy’s renewal of a sale-leaseback transaction originally entered into in December 1988 for an 11.5% undivided interest in Grand Gulf Unit 1. The complaint alleged that System Energy violated the filed rate and the FERC’s ratemaking and accounting requirements when it included in Unit Power Sales Agreement billings the cost of
capital additions associated with the sale-leaseback interest, and that System Energy was double-recovering costs by including both the lease payments and the capital additions in Unit Power Sales Agreement billings. The complaint also claimed that System Energy was imprudent in entering into the sale-leaseback renewal because the Utility operating companies that purchase Grand Gulf’s output from System Energy could have obtained cheaper capacity and energy in the MISO markets. The complaint further alleged that System Energy violated various other reporting and accounting requirements and should have sought prior FERC approval of the lease renewal. The complaint sought various forms of relief from the FERC, including refunds for capital addition costs for all years in which they were recorded in allegedly non-formula accounts or, alternatively, the disallowance of the return on equity for the capital additions in those years plus interest; a disallowance and refund of the lease costs of the sale-leaseback renewal on grounds of imprudence; an investigation into System Energy’s treatment of a DOE litigation payment; and the imposition of certain forward-looking procedural protections, including audit rights for retail regulators of the Unit Power Sales Agreement formula rates. The APSC, the MPSC, and the City Council intervened in the proceeding.

In June 2018, System Energy and Entergy Services filed a motion to dismiss and an answer to the LPSC complaint denying that System Energy’s treatment of the sale-leaseback renewal and capital additions violated the terms of the filed rate or any other FERC ratemaking, accounting, or legal requirements or otherwise constituted double recovery. The response also argued that the complaint was inconsistent with a FERC-approved settlement to which the LPSC is a party and that explicitly authorized System Energy to recover its lease payments. Finally, the response argued that both the capital additions and the sale-leaseback renewal were prudent investments and the LPSC complaint failed to justify any disallowance or refunds. The response also offered to submit formula rate protocols for the Unit Power Sales Agreement similar to the procedures used for reviewing transmission rates under the MISO tariff. In September 2018 the FERC issued an order setting the complaint for hearing and settlement proceedings and establishing a refund effective date of May 18, 2018.

In February 2019 the presiding ALJ ruled that the hearing ordered by the FERC includes the issue of whether specific subcategories of accumulated deferred income tax should be included in, or excluded from, System Energy’s formula rate. Testimony was filed by the LPSC, the MPSC, the APSC, the City Council, the FERC trial staff, and System Energy between March 2019 and October 2019. The final positions of the parties, after all pre-filed testimony was submitted, were as follows. The LPSC sought refunds that included the renewal lease payments (approximately $17.2 million per year since July 2015), rate base reductions for accumulated deferred income tax associated with uncertain tax positions (with a corresponding refund of approximately $512 million), and the cost of capital additions associated with the sale-leaseback interest, as well as interest on those amounts. The LPSC also argued that adjustments to depreciation rates should require retroactive depreciation expense refunds but only prospective rate base adjustments. The APSC, the MPSC, and the City Council generally agreed with the LPSC’s positions. The FERC trial staff argued for refunds for rate base reductions for liabilities associated with uncertain tax positions, and also argued that System Energy recovered $32 million more than it should have in depreciation expense for capital additions. System Energy filed testimony asking the FERC to reject all of the LPSC’s claims for refunds and opposing the FERC trial staff’s position regarding the uncertain tax position issue. System Energy also argued that the FERC trial staff’s position regarding depreciation rates for capital additions was not unreasonable, but any change in depreciation expense is only one element of a Unit Power Sales Agreement re-billing calculation. Adjustments to depreciation expense in any re-billing under the Unit Power Sales Agreement formula rate would also involve changes to accumulated depreciation, accumulated deferred income taxes, and other formula elements as needed.

After holding a hearing in November 2019, in April 2020 the FERC ALJ issued the initial decision. Among other things, the ALJ determined that refunds were due on three main issues. First, with regard to the lease renewal payments, the ALJ determined that System Energy was recovering an unjust acquisition premium through the lease renewal payments, and that System Energy’s recovery from customers through rates should be limited to the cost of service based on the remaining net book value of the leased assets, which was approximately $70 million. The ALJ found that the remedy for this issue should be the refund of lease payments (approximately $17.2 million per year since July 2015) with interest determined at the FERC quarterly interest rate, which would be offset by the addition
of the net book value of the leased assets in the cost of service. The ALJ did not calculate a value for the refund expected as a result of this remedy. In addition, System Energy would no longer recover the lease payments in rates prospectively. Second, with regard to the liabilities associated with uncertain tax positions, the ALJ determined that the liabilities are accumulated deferred income taxes and that System Energy’s rate base should have been reduced for those liabilities. The ALJ also found that System Energy should include liabilities associated with uncertain tax positions as a rate base reduction going forward. Third, with regard to the depreciation expense adjustments, the ALJ found that System Energy should correct for the error in re-billings retroactively and prospectively, but that System Energy should not be permitted to recover interest on any retroactive return on enhanced rate base resulting from such corrections.

In June 2020, System Energy, the LPSC, and the FERC trial staff filed briefs on exceptions, challenging several of the initial decision’s findings. System Energy’s brief on exceptions challenged the initial decision’s limitations on recovery of the lease renewal payments, its proposed rate base refund for the liabilities associated with uncertain tax positions, and its proposal to asymmetrically treat interest on bill corrections for depreciation expense adjustments. The LPSC’s and the FERC trial staff’s briefs on exceptions each challenged the initial decision’s allowance for recovery of the cost of service associated with the lease renewal based on the remaining net book value of the leased assets, its calculation of the remaining net book value of the leased assets, and the amount of the initial decision’s proposed rate base refund for the liabilities associated with uncertain tax positions. The LPSC’s brief on exceptions also challenged the initial decision’s proposal that depreciation expense adjustments include retroactive adjustments to rate base and its finding that section 203 of the Federal Power Act did not apply to the lease renewal. The FERC trial staff’s brief on exceptions also challenged the initial decision’s finding that the FERC need not institute a formal investigation into System Energy’s tariff. In October 2020, System Energy, the LPSC, the MPSC, the APSC, and the City Council filed briefs opposing exceptions. System Energy opposed the exceptions filed by the LPSC and the FERC trial staff. The LPSC, the MPSC, the APSC, the City Council, and the FERC trial staff opposed the exceptions filed by System Energy. Also in October 2020 the MPSC, the APSC, and the City Council filed briefs adopting the exceptions of the LPSC and the FERC trial staff.

In addition, in September 2020, the IRS issued a Notice of Proposed Adjustment (NOPA) and Entergy executed it. The NOPA memorialized the IRS’s decision to adjust the 2015 consolidated federal income tax return of Entergy Corporation and certain of its subsidiaries, including System Energy, with regard to the uncertain decommissioning tax position. Pursuant to the audit resolution documented in the NOPA, the IRS allowed System Energy’s inclusion of $102 million of future nuclear decommissioning costs in System Energy’s cost of goods sold for the 2015 tax year, roughly 10% of the requested deduction, but disallowed the balance of the position. In September 2020, System Energy filed a motion to lodge the NOPA into the record in the FERC proceeding. In October 2020 the LPSC, the APSC, the MPSC, the City Council, and the FERC trial staff filed oppositions to System Energy’s motion. As a result of the NOPA issued by the IRS in September 2020, System Energy filed, in October 2020, a new Federal Power Act section 205 filing at FERC to establish an ongoing rate base credit for the accumulated deferred income taxes resulting from the decommissioning uncertain tax position. On a prospective basis beginning with the October 2020 bill, System Energy proposed to include the accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position as a credit to rate base under the Unit Power Sales Agreement. In November 2020 the LPSC, the APSC, the MPSC, and the City Council filed a protest to the filing, and System Energy responded.

In November 2020 the IRS issued a Revenue Agent’s Report (RAR) for the 2014/2015 tax year and in December 2020 Entergy executed it. The RAR contained the same adjustment to the uncertain nuclear decommissioning tax position as that which the IRS had announced in the NOPA. In December 2020, System Energy filed a motion to lodge the RAR into the record in the FERC proceeding addressing the uncertain tax position rate base issue. In January 2021 the LPSC, the APSC, the MPSC, and the City Council filed a protest to the motion.

As a result of the RAR, in December 2020, System Energy filed amendments to its new Federal Power Act section 205 filings to establish an ongoing rate base credit for the accumulated deferred income taxes resulting from
the decommissioning uncertain tax position and to credit excess accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position. The amendments both proposed the inclusion of the RAR as support for the filings. In December 2020 the LPSC, the APSC, and the City Council filed protests to the amendments. In February 2021 the FERC issued an order accepting System Energy’s Federal Power Act section 205 filings subject to refund, setting them for hearing, and holding the hearing in abeyance.

In December 2020, System Energy filed a new Federal Power Act section 205 filing to provide a one-time, historical credit of $25.2 million for the accumulated deferred income taxes that would have been created by the decommissioning uncertain tax position if the IRS’s decision had been known in 2016. In January 2021 the LPSC, APSC, MPSC, and City Council filed a protest to the filing. In February 2021 the FERC issued an order accepting System Energy’s Federal Power Act section 205 filing subject to refund, setting it for hearing, and holding the hearing in abeyance. System Energy provided the one-time credit during the first quarter 2021.

In December 2022 the FERC issued an order on the ALJ’s initial decision, which affirmed it in part and modified it in part. The FERC’s order directed System Energy to calculate refunds on three issues, and to provide a compliance report detailing the calculations. The FERC’s order also disallowed the future recovery of sale-leaseback renewal costs, which is estimated at approximately $11.5 million annually for purchases from Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans through July 2036. The three refund issues were rental expenses related to the renewal of the sale-leaseback arrangements; refunds, if any, for the revenue requirement impact of including accumulated deferred income taxes resulting from the decommissioning uncertain tax positions from 2004 through the present; and refunds for the net effect of correcting the depreciation inputs for capital additions attributable to the portion of plant subject to the sale-leaseback.

As a result of the FERC order’s directives regarding the recovery of the sale-leaseback transaction, in December 2022 System Energy reduced the Grand Gulf sale-leaseback regulatory liability by $56 million, reduced the related accumulated deferred income tax asset by $94 million, and reduced the Grand Gulf sale-leaseback accumulated deferred income tax regulatory liability by $25 million, resulting in an increase in income tax expense of $13 million. In addition, the FERC determined that System Energy recognized excess depreciation expense related to property subject to the sale-leaseback. As a result, in December 2022, System Energy recorded a reduction in depreciation expense and the related accumulated depreciation of $33 million.

In January 2023, System Energy filed its compliance report with the FERC. With respect to the sale-leaseback renewal costs, System Energy calculated a refund of $89.8 million, which represented all of the sale-leaseback renewal rental costs that System Energy recovered in rates, with interest. With respect to the decommissioning uncertain tax position issue, System Energy calculated that no additional refunds were owed because it had already provided a one-time historical credit (for the period January 2016 through September 2020) of $25.2 million based on the accumulated deferred income taxes that resulted from the IRS’s partial acceptance of the decommissioning tax position, and because it has been providing an ongoing rate base credit for the accumulated deferred income taxes that resulted from the IRS’s partial acceptance of the decommissioning tax position since October 2020. With respect to the depreciation refund, System Energy calculated a refund of $13.7 million, which is the net total of a refund to customers for excess depreciation expense previously collected, plus interest, offset by the additional return on rate base that System Energy previously did not collect, without interest. See “System Energy Settlement with the MPSC” below for discussion of the regulatory charge and corresponding regulatory liability recorded in June 2022 related to these proceedings. In January 2023, System Energy paid the refunds of $103.5 million, which included refunds of $41.7 million to Entergy Arkansas, $27.8 million to Entergy Louisiana, and $34 million to Entergy New Orleans.

In February 2023 the LPSC, the APSC, and the City Council filed protests to System Energy’s January 2023 compliance report, in which they challenged System Energy’s calculation of the refunds associated with the decommissioning tax position but did not protest the other components of the compliance report. Each of them argued that System Energy should have paid additional refunds for the decommissioning tax position issue, and the City Council estimated the total additional refunds owed to customers of Entergy Louisiana, Entergy New Orleans,
and Entergy Arkansas for that issue as $493 million, including interest (and without factoring in the $25.2 million refund that System Energy already paid in 2021).

In January 2023, System Energy filed a request for rehearing of the FERC’s determinations in the December 2022 order on sale-leaseback refund issues and future lease cost disallowances, the FERC’s prospective policy on uncertain tax positions, and the proper accounting of System Energy’s accumulated deferred income taxes adjustment for the Tax Cuts and Jobs Act of 2017; and a motion for confirmation of its interpretation of the December 2022 order’s remedy concerning the decommissioning tax position. In January 2023 the retail regulators filed a motion for confirmation of their interpretation of the refund requirement in the December 2022 FERC order and a provisional request for rehearing. In February 2023 the FERC issued a notice that the rehearing requests were denied by operation of law. In March 2023, System Energy filed in the United States Court of Appeals for the Fifth Circuit a petition for review of the December 2022 order. In March 2023, System Energy also filed an unopposed motion to stay the proceeding in the Fifth Circuit pending the FERC’s disposition of the pending motions, and the court granted the motion to stay.

In February 2023, System Energy submitted a tariff compliance filing with the FERC to clarify that, consistent with the releases provided in the MPSC settlement, Entergy Mississippi will continue to be charged for its allocation of the sale-leaseback renewal costs under the Unit Power Sales Agreement. See “System Energy Settlement with the MPSC” below for discussion of the settlement. In March 2023 the MPSC filed a protest to System Energy’s tariff compliance filing. The MPSC argues that the settlement did not specifically address post-settlement sale-leaseback renewal costs and that the sale-leaseback renewal costs may not be recovered under the Unit Power Sales Agreement. Entergy Mississippi’s allocated sale-leaseback renewal costs are estimated at $5.7 million annually for the remaining term of the sale-leaseback renewal.

In August 2023 the FERC issued an order addressing arguments raised on rehearing and partially setting aside the prior order (rehearing order). The rehearing order addressed rehearing requests that were filed in January 2023 separately by System Energy and the LPSC, the APSC, and the City Council.

In the rehearing order, the FERC directed System Energy to recalculate refunds for two issues: (1) refunds of rental expenses related to the renewal of the sale-leaseback arrangements and (2) refunds for the net effect of correcting the depreciation inputs for capital additions associated with the sale-leaseback. With regard to the sale-leaseback renewal rental expenses, the rehearing order allowed System Energy to recover an implied return of and on the depreciated cost of the portion of the plant subject to the sale-leaseback as of the expiration of the initial lease term. With regard to the depreciation input issue, the rehearing order allowed System Energy to offset refunds so that System Energy may collect interest on the rate base recalculations that were part of the overall depreciation rate recalculations. The rehearing order further directed System Energy to submit within 60 days of the date of the rehearing order an additional compliance filing to revise the total refunds for these two issues. As discussed above, System Energy’s January 2023 compliance filing calculated $103.5 million in total refunds, and the refunds were paid in January 2023. In October 2023, System Energy filed its compliance report with the FERC as directed in the August 2023 rehearing order. The October 2023 compliance report reflected recalculated refunds totaling $35.7 million for the two issues resulting in $67.8 million in refunds that could be recouped by System Energy. As discussed below in “System Energy Settlement with the APSC,” System Energy reached a settlement in principle with the APSC to resolve several pending cases under the FERC’s jurisdiction, including this one, pursuant to which it agreed not to recoup the $27.3 million calculated for Entergy Arkansas in the compliance filing. As a result of the FERC’s rulings on the sale-leaseback and depreciation input issues in the August 2023 rehearing order, in third quarter 2023, System Energy recorded a regulatory asset and corresponding regulatory credit of $40 million to reflect the portion of the January 2023 refunds to be recouped from Entergy Louisiana and Entergy New Orleans. Consistent with the compliance filing, in October 2023, Entergy Louisiana and Entergy New Orleans paid recoupment amounts of $18.2 million and $22.3 million, respectively, to System Energy.
On the third refund issue identified in the rehearing requests, concerning the decommissioning uncertain tax positions, the rehearing order denied all rehearing requests, re-affirmed the remedy contained in the December 2022 order, and did not direct System Energy to recalculate refunds or to submit an additional compliance filing.

In September 2023, System Energy filed a protective appeal of the rehearing order with the United States Court of Appeals for the Fifth Circuit. The appeal was consolidated with System Energy’s prior appeal of the December 2022 order.

In September 2023 the LPSC filed with the FERC a request for rehearing and clarification of the rehearing order. The LPSC requested that the FERC reverse its determination in the rehearing order that System Energy may collect an implied return of and on the depreciated cost of the portion of the plant subject to the sale-leaseback, as of the expiration of the initial lease term, as well as its determination in the rehearing order that System Energy may offset the refunds for the depreciation rate input issue and collect interest on the rate base recalculations that were part of the overall depreciation rate recalculations. In addition, the LPSC requested that the FERC either confirm the LPSC’s interpretation of the refund associated with the decommissioning uncertain tax positions or explain why it is not doing so. In October 2023 the FERC issued a notice that the rehearing request was deemed denied by operation of law. In November 2023 the FERC issued a further notice stating that it would not issue any further order addressing the rehearing request. Also in November 2023 the LPSC filed with the United States Court of Appeals for the Fifth Circuit a petition for review of the FERC’s August 2023 rehearing order and denials of the September 2023 rehearing request.

In December 2023 the United States Court of Appeals for the Fifth Circuit lifted the abeyance on the consolidated System Energy appeals and it also consolidated the LPSC’s appeal with the System Energy appeals. Briefing of the appeals occurred between March 2024 and July 2024. In September 2024 the parties filed a joint motion to continue and stay oral argument, previously scheduled for October 2024, pending the FERC’s decision whether to approve the settlement between System Energy and the LPSC, and the United States Court of Appeals for the Fifth Circuit granted the motion. In November 2024, after the FERC issued the order approving the settlement between System Energy and the LPSC, System Energy, the LPSC, the APSC, and the FERC filed a joint stipulation to dismiss the pending appeals, which the United States Court of Appeals for the Fifth Circuit granted.

As discussed below in “System Energy Settlement with the MPSC,” “System Energy Settlement with the APSC,” “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the MPSC, the APSC, the City Council, and the LPSC have settled their claims related to this proceeding.

LPSC Additional Complaints

In May 2020 the LPSC authorized its staff to file additional complaints at the FERC related to the rates charged by System Energy for Grand Gulf energy and capacity supplied to Entergy Louisiana under the Unit Power Sales Agreement. The LPSC directive noted that the initial decision issued by the presiding ALJ in the Grand Gulf sale-leaseback complaint proceeding did not address, for procedural reasons, certain rate issues raised by the LPSC and declined to order further investigation of rates charged by System Energy.

Unit Power Sales Agreement Complaint

The first of the additional complaints was filed by the LPSC, the APSC, the MPSC, and the City Council in September 2020. The first complaint raised two sets of rate allegations: violations of the filed rate and a corresponding request for refunds for prior periods; and elements of the Unit Power Sales Agreement are unjust and unreasonable and a corresponding request for refunds for the 15-month refund period and changes to the Unit Power Sales Agreement prospectively. Several of the filed rate allegations overlapped with the previous complaints. The filed rate allegations not previously raised were that System Energy: failed to provide a rate base credit to customers for the “time value” of sale-leaseback lease payments collected from customers in advance of the time those payments were due to the owner-lessors; improperly included certain sale-leaseback transaction costs in rate base as
prepayments; improperly included nuclear refueling outage costs in rate base; wrongly included categories of accumulated deferred income taxes as increases to rate base; charged customers based on a higher equity ratio than would be appropriate due to excessive retained earnings; and did not correctly reflect money pool investments and imprudently invested cash into the money pool. The elements of the Unit Power Sales Agreement that the complaint alleged were unjust and unreasonable include: the current cash working capital allowance of zero, uncapped recovery of incentive and executive compensation, lack of an equity re-opener, and recovery of lobbying and private airplane travel expenses. The complaint also requested a rate investigation into the Unit Power Sales Agreement and System Energy’s billing practices pursuant to section 206 of the Federal Power Act, including any issue relevant to the Unit Power Sales Agreement and its inputs. System Energy filed its answer opposing the complaint in November 2020. In its answer, System Energy argued that all of the claims raised in the complaint should be dismissed and agreed that bill adjustment with respect to two discrete issues were justified. System Energy argued that dismissal was warranted because all claims fell into one or more of the following categories: the claims had been raised and were being litigated in another proceeding; the claims did not present a prima facie case and did not satisfy the threshold burden to establish a complaint proceeding; the claims were premised on a theory or request relief that is incompatible with federal law or FERC policy; the claims request relief that is inconsistent with the filed rate; the claims were barred or waived by the legal doctrine of laches; and/or the claims had been fully addressed and do not warrant further litigation. In December 2020, System Energy filed a bill adjustment report indicating that $3.4 million had been credited to customers in connection with the two discrete issues concerning the inclusion of certain accumulated deferred income taxes balances in rates.

In May 2021 the FERC issued an order addressing the complaint, establishing a refund effective date of September 21, 2020, establishing hearing procedures, and holding those procedures in abeyance pending the FERC’s review of the initial decision in the Grand Gulf sale-leaseback renewal complaint discussed above. System Energy agreed that the hearing should be held in abeyance but sought rehearing of FERC’s decision as related to matters set for hearing that were beyond the scope of FERC’s jurisdiction or authority. The complainants sought rehearing of FERC’s decision to hold the hearing in abeyance and filed a motion to proceed, which motion System Energy opposed. In June 2021, System Energy’s request for rehearing was denied by operation of law, and System Energy filed an appeal of FERC’s orders in the Court of Appeals for the Fifth Circuit. In November 2021 the Fifth Circuit dismissed the appeal as premature.

In August 2021 the FERC issued an order addressing System Energy’s and the complainants’ rehearing requests. The FERC dismissed part of the complaint seeking an equity re-opener, maintained the abeyance for issues related to the proceeding addressing the sale-leaseback renewal and uncertain tax positions, lifted the abeyance for issues unrelated to that proceeding, and clarified the scope of the hearing.

In November 2021 the LPSC, the APSC, and the City Council filed direct testimony and requested the FERC to order refunds for prior periods and prospective amendments to the Unit Power Sales Agreement. The LPSC’s refund claims included, among other things, allegations that: (1) System Energy should not have included certain sale-leaseback transaction costs in prepayments; (2) System Energy should have credited rate base to reflect the time value of money associated with the advance collection of lease payments; (3) System Energy incorrectly included refueling outage costs that were recorded in account 174 in rate base; and (4) System Energy should have excluded several accumulated deferred income tax balances in account 190 from rate base. The LPSC also sought a retroactive adjustment to retained earnings and capital structure in conjunction with the implementation of its proposed refunds. In addition, the LPSC sought amendments to the Unit Power Sales Agreement going forward to address below-the-line costs, incentive compensation, the working capital allowance, litigation expenses, and the 2019 termination of the capital funds agreement. The APSC argued that: (1) System Energy should have included borrowings from the Entergy system money pool in its determination of short-term debt in its cost of capital; and (2) System Energy should credit customers with System Energy’s allocation of earnings on money pool investments. The City Council alleged that System Energy has maintained excess cash on hand in the money pool and that retention of excess cash was imprudent. Based on this allegation, the City Council’s witness recommended a refund of approximately $98.8 million for the period 2004-September 2021 or other alternative relief. The City Council
further recommended that the FERC impose a hypothetical equity ratio such as 48.15% equity to capital on a prospective basis.

In January 2022, System Energy filed answering testimony arguing that the FERC should not order refunds for prior periods or any prospective amendments to the Unit Power Sales Agreement. In response to the LPSC’s refund claims, System Energy argued, among other things, that: (1) the inclusion of sale-leaseback transaction costs in prepayments was correct; (2) that the filed rate doctrine bars the request for a retroactive credit to rate base for the time value of money associated with the advance collection of lease payments; (3) that an accounting misclassification for deferred refueling outage costs had been corrected, caused no harm to customers, and requires no refunds; and (4) that its accounting and ratemaking treatment of specified accumulated deferred income tax balances in account 190 had been correct. System Energy further responded that no retroactive adjustment to retained earnings or capital structure should be ordered because there was no general policy requiring such a remedy, and there was no showing that the retained earnings element of the capital structure was incorrectly implemented. Further, System Energy presented evidence that all of the costs that were being challenged were long known to the retail regulators and were approved by them for inclusion in retail rates, and the attempt to retroactively challenge these costs, some of which had been included in rates for decades, was unjust and unreasonable. In response to the LPSC’s proposed going-forward adjustments, System Energy presented evidence to show that none of the proposed adjustments were needed. On the issue of below-the-line expenses, during discovery procedures System Energy identified a historical allocation error in certain months and agreed to provide a bill credit to customers to correct the error. In response to the APSC’s claims, System Energy argued that the Unit Power Sales Agreement did not include System Energy’s borrowings from the Entergy system money pool or earnings on deposits to the Entergy system money pool in the determination of the cost of capital; and accordingly, no refunds were appropriate on those issues. In response to the City Council’s claims, System Energy argued that it has reasonably managed its cash and that the City Council’s theory of cash management was defective because it failed to adequately consider the relevant cash needs of System Energy and it made faulty presumptions about the operation of the Entergy system money pool. System Energy further pointed out that the issue of its capital structure was already subject to pending FERC litigation.

In March 2022 the FERC trial staff filed direct and answering testimony in response to the LPSC, the APSC, and the City Council’s direct testimony. In its testimony, the FERC trial staff recommended refunds for two primary reasons: (1) it concluded that System Energy should have excluded specified accumulated deferred income tax balances in account 190 associated with rate refunds; and (2) it concluded that System Energy should have excluded specified accumulated deferred income tax balances in account 190 associated with a deemed contract satisfaction and reissuance that occurred in 2005. The FERC trial staff recommended refunds of $84.1 million, exclusive of any tax gross-up or FERC interest. In addition, the FERC trial staff recommended the following prospective modifications to the Unit Power Sales Agreement: (1) inclusion of a rate base credit to recognize the time value of money associated with the advance collection of lease payments; (2) exclusion of executive incentive compensation costs for members of the Office of the Chief Executive and long-term performance unit costs where awards are based solely or primarily on financial metrics; and (3) exclusion of unvested, accrued amounts for stock options, performance units, and restricted stock awards. With respect to issues that ultimately concerned the reasonableness of System Energy’s rate of return, the FERC trial staff stated that it was unnecessary to consider such issues in the proceeding, in light of the pending case concerning System Energy’s return on equity and capital structure. On all other material issues raised by the LPSC, the APSC, and the City Council, the FERC trial staff recommended either no refunds or no modification to the Unit Power Sales Agreement.

In April 2022, System Energy filed cross-answering testimony in response to the FERC trial staff’s recommendations of refunds for the accumulated deferred income taxes issues and proposed modifications to the Unit Power Sales Agreement for the executive incentive compensation issues. In June 2022 the FERC trial staff submitted revised answering testimony, in which it recommended additional refunds associated with the accumulated deferred income tax balances in account 190 associated with a deemed contract satisfaction and reissuance that occurred in 2005. Based on the testimony revisions, the FERC trial staff’s recommended refunds total $106.6 million, exclusive of any tax gross-up or FERC awarded interest. Also in June 2022, System Energy
filed revised and supplemental cross-answering testimony to respond to the FERC trial staff’s testimony and oppose its revised recommendation.

In May 2022 the LPSC, the APSC, and the City Council filed rebuttal testimony. The LPSC’s testimony asserted new claims, including that: (1) certain of the sale-leaseback transaction costs may have been imprudently incurred; (2) accumulated deferred income taxes associated with sale-leaseback transaction costs should have been included in rate base; (3) accumulated deferred income taxes associated with federal investment tax credits should have been excluded from rate base; (4) monthly net operating loss accumulated deferred income taxes should have been excluded from rate base; and (5) several categories of proposed rate changes, including executive incentive compensation, air travel, industry dues, and legal costs, also warranted historical refunds. The LPSC’s rebuttal testimony argued that refunds for the alleged tariff violations and other claims must be calculated by rerunning the Unit Power Sales Agreement formula rate; however, it included estimates of refunds associated with some, but not all, of its claims, totaling $286 million without interest. The City Council’s rebuttal testimony also proposed a new, alternate theory and claim for relief regarding System Energy’s participation in the Entergy system money pool, under which it calculates estimated refunds of approximately $51.7 million. The APSC’s rebuttal testimony agreed with the LPSC’s direct testimony that retained earnings should be adjusted in a comprehensive refund calculation. The testimony quantified the estimated impacts of three issues: (1) a $1.5 million reduction in the revenue requirement under the Unit Power Sales Agreement if System Energy’s borrowings from the money pool were included in short-term debt; (2) a $1.9 million reduction in the revenue requirement if System Energy’s allocated share of money pool earnings were credited through the Unit Power Sales Agreement; and (3) a $1.9 million reduction in the revenue requirement for every $50 million of refunds ordered in a given year, without interest. In total, excluding the settled issues noted below, the claims sought more than $700 million in refunds and interest, based on charges to all Unit Power Sales Agreement purchasers including Entergy Mississippi. The hearing before a FERC ALJ occurred between September and December 2022.

In November 2022, System Energy filed a partial settlement agreement with the APSC, the City Council, and the LPSC that resolved the following issues raised in the Unit Power Sales Agreement complaint: advance collection of lease payments, aircraft costs, executive incentive compensation, money pool borrowings, advertising expenses, deferred nuclear refueling outage costs, industry association dues, and termination of the capital funds agreement. The settlement provided that System Energy would provide a black box refund of $18 million (inclusive of interest), plus additional refund amounts with interest to be calculated for certain issues to be distributed to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans as the Utility operating companies other than Entergy Mississippi purchasing under the Unit Power Sales Agreement. The settlement further provided that if the APSC, the City Council, or the LPSC agreed to the global settlement System Energy entered into with the MPSC (discussed below), and such global settlement included a black box refund amount, then the black box refund for this settlement agreement would not be incremental or in addition to the global black box refund amount. The settlement agreement addressed other matters as well, including adjustments to rate base beginning in October 2022, exclusion of certain other costs, and inclusion of money pool borrowings, if any, in short-term debt within the cost of capital calculation used in the Unit Power Sales Agreement. In April 2023 the FERC approved the settlement agreement. The refund provided for in the settlement agreement was included in the May 2023 service month bills under the Unit Power Sales Agreement.

In May 2023 the presiding ALJ issued an initial decision finding that System Energy should have excluded multiple identified categories of accumulated deferred income taxes from rate base when calculating Unit Power Sales Agreement bills. The initial decision also found that the Unit Power Sales Agreement should be modified such that a cash working capital allowance of negative $36.4 million is applied prospectively. On the other non-settled issues for which the complainants sought refunds or changes to the Unit Power Sales Agreement, the initial decision ruled against the complainants.

System Energy disagreed with the ALJ’s findings concerning the accumulated deferred income taxes issues and cash working capital. In July 2023, System Energy filed a brief on exceptions to the initial decision’s accumulated deferred income taxes findings. Also in July 2023, the APSC, the LPSC, the City Council, and the
FERC trial staff filed separate briefs on exceptions. In August 2023 all parties filed separate briefs opposing exceptions.

As discussed below in “System Energy Settlement with the MPSC,” “System Energy Settlement with the APSC,” and “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the MPSC, the APSC, and the City Council, and the LPSC have settled their claims related to this proceeding.

Grand Gulf Prudence Complaints

The second of the additional complaints was filed at the FERC in March 2021 by the LPSC, the APSC, and the City Council against System Energy, Entergy Services, Entergy Operations, and Entergy Corporation. The second complaint contained two primary allegations. First, it alleged that, based on the plant’s capacity factor and alleged safety performance, System Energy and the other respondents imprudently operated Grand Gulf during the period 2016-2020, and it sought refunds of at least $360 million in alleged replacement energy costs, in addition to other costs, including those that could only be identified upon further investigation. Second, it alleged that the performance and/or management of the 2012 extended power uprate of Grand Gulf was imprudent, and it sought refunds of all costs of the 2012 uprate that were determined to result from imprudent planning or management of the project. In addition to the requested refunds, the complaint asked that the FERC modify the Unit Power Sales Agreement to provide for full cost recovery only if certain performance indicators were met and to require pre-authorization of capital improvement projects in excess of $125 million before related costs could be passed through to customers in rates. In April 2021, System Energy and the other respondents filed their motion to dismiss and answer to the complaint. System Energy requested that the FERC dismiss the claims within the complaint. With respect to the claim concerning operations, System Energy argued that the complaint did not meet its legal burden because, among other reasons, it failed to allege any specific imprudent conduct. With respect to the claim concerning the uprate, System Energy argued that the complaint failed because, among other reasons, the complainants’ own conduct prevented them from raising a serious doubt as to the prudence of the uprate. System Energy also requested that the FERC dismiss other elements of the complaint, including the proposed modifications to the Unit Power Sales Agreement, because they were not warranted. In February 2023 the FERC issued an order denying rehearing and thereby affirming its order setting the complaint for settlement and hearing procedures. In July 2023 the FERC chief ALJ terminated settlement procedures and appointed a presiding ALJ to oversee hearing procedures. In September 2023 a procedural schedule for hearing procedures was established. Also in September 2023 the LPSC authorized its staff to file an additional complaint concerning the prudence of System Energy’s operation and management of Grand Gulf in the year 2022. In October 2023 the LPSC, the APSC, and the City Council filed what they styled as an amended and supplemental complaint with the FERC against System Energy, Entergy Services, and Entergy Operations. In November 2023, System Energy answered the amended and supplemental complaint. Pursuant to the procedural schedule, the complainants’ testimony in the original complaint proceeding was filed in December 2023. System Energy’s answering testimony was filed in May 2024, and the FERC trial staff’s direct and answering testimony was filed in June 2024.

As discussed below in “System Energy Settlement with the APSC,” “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the APSC, the City Council, and the LPSC have settled all of their claims related to this proceeding.

System Energy Settlement with the MPSC

In June 2022, System Energy, Entergy Mississippi, and additional named Entergy parties involved in thirteen docketed proceedings before the FERC filed with the FERC a partial settlement agreement and offer of settlement. The settlement memorialized the Entergy parties’ agreement with the MPSC to globally resolve all actual and potential claims between the Entergy parties and the MPSC associated with those FERC proceedings and with System Energy’s past implementation of the Unit Power Sales Agreement. The Unit Power Sales Agreement is a FERC-jurisdictional formula rate tariff for sales of energy and capacity from System Energy’s owned and
leased share of Grand Gulf to Entergy Mississippi, Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans. Entergy Mississippi purchases the greatest single amount, nearly 40% of System Energy’s share of Grand Gulf, after its additional purchases from affiliates are considered.

The settlement provided for a black box refund of $235 million from System Energy to Entergy Mississippi. In addition, beginning with the July 2022 service month, the settlement provided for Entergy Mississippi’s bills from System Energy to be adjusted to reflect: an authorized rate of return on equity of 9.65%, a capital structure not to exceed 52% equity, a rate base reduction for the advance collection of sale-leaseback rental costs, and the exclusion of certain long-term incentive plan performance unit costs from rates. The settlement was approved by the MPSC in June 2022 and the FERC in November 2022.

System Energy had previously recorded a provision and associated liability of $37 million for elements of the applicable litigation. In June 2022, System Energy recorded a regulatory charge of $551 million ($413 million net-of-tax), increasing the regulatory liability to $588 million, which consisted of $235 million for the settlement with the MPSC and $353 million for potential future refunds to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans. System Energy paid the black box refund of $235 million to Entergy Mississippi in November 2022.

System Energy Settlement with the APSC

In October 2023, System Energy, Entergy Arkansas, and additional named Entergy parties involved in multiple docketed proceedings pending before the FERC reached a settlement in principle with the APSC to globally resolve all of their actual and potential claims in those dockets and with System Energy’s past implementation of the Unit Power Sales Agreement. The settlement also covered the amended and supplemental complaint, discussed above in “Grand Gulf Prudence Complaint,” filed at the FERC in October 2023. System Energy, Entergy Arkansas, additional Entergy parties, and the APSC filed the settlement agreement and supporting materials with the FERC in November 2023.

The terms of the settlement with the APSC aligned with the $588 million global black box settlement reached between System Energy and the MPSC in June 2022 and provided for Entergy Arkansas to receive a black box refund of $142 million from System Energy, inclusive of $49.5 million already received by Entergy Arkansas from System Energy. In addition, beginning with the November 2023 service month, the settlement provided for Entergy Arkansas’s bills from System Energy to be adjusted to reflect an authorized rate of return on equity of 9.65% and a capital structure not to exceed 52% equity. In March 2024 the FERC approved the settlement, and System Energy paid the remaining black box refund of $93 million to Entergy Arkansas in 2024.

System Energy Settlement with the City Council

In April 2024, System Energy, Entergy New Orleans, and additional named Entergy parties involved in multiple docketed proceedings pending before the FERC reached a settlement in principle with the City Council to globally resolve all of their actual and potential claims in those dockets and with System Energy’s past implementation of the Unit Power Sales Agreement. The settlement also covered the amended and supplemental complaint, discussed in “Grand Gulf Prudence Complaints” above, filed by the LPSC, the APSC, and the City Council at the FERC in October 2023. In May 2024, System Energy, Entergy New Orleans, additional named Entergy parties, and the City Council filed the settlement agreement and supporting materials with the FERC.

The terms of the settlement with the City Council aligned with the $588 million global black box settlement amount reflected in the prior settlements reached between System Energy and the MPSC in June 2022 and between System Energy and the APSC in November 2023. The settlement provided for Entergy New Orleans to receive a black box refund of $116 million from System Energy, inclusive of approximately $18 million already received by Entergy New Orleans from System Energy. In addition, beginning with the June 2024 service month, the settlement provided for Entergy New Orleans’s bills from System Energy to be adjusted to reflect an authorized rate of return on equity of 9.65% and a capital structure not to exceed 52% equity. In August 2024 the FERC approved the
settlement, and System Energy paid the remaining black box refund of $98 million to Entergy New Orleans in October 2024.

System Energy Settlement with the LPSC

In July 2024, System Energy and the LPSC staff reached a settlement in principle to globally resolve all of the LPSC’s actual and potential claims in multiple docketed proceedings pending before the FERC (including all docketed proceedings resolved by the MPSC, the APSC, and the City Council settlements) and with System Energy’s past implementation of the Unit Power Sales Agreement. The settlement also covered the amended and supplemental complaint, discussed above in “Grand Gulf Prudence Complaints,” filed by the LPSC, the APSC, and the City Council at the FERC in October 2023. In August 2024 the LPSC approved the settlement. In September 2024 the settling parties filed the settlement for approval by the FERC.

The terms of the settlement with the LPSC staff aligned with the $588 million global black box settlement amount reflected in the prior settlements reached between System Energy and the MPSC in June 2022, between System Energy and the APSC in November 2023, and between System Energy and the City Council in April 2024. The settlement in principle provided for Entergy Louisiana to receive a black box refund of $95 million from System Energy, inclusive of approximately $15 million already received by Entergy Louisiana from System Energy. In addition, beginning with the September 2024 service month, the settlement provided for Entergy Louisiana’s bills from System Energy to be adjusted to reflect an authorized rate of return on equity of 9.65% and a capital structure not to exceed 52% equity. In November 2024 the FERC approved the settlement, and System Energy paid the remaining black box refund of $80 million to Entergy Louisiana in December 2024.

The settlement also included an agreement that, subject to the receipt of necessary regulatory approvals, Entergy Louisiana will divest to Entergy Mississippi all of its interest in Grand Gulf capacity and energy under the Unit Power Sales Agreement and its purchases from Entergy Arkansas under the MSS-4 replacement tariff. In October 2024 Entergy Louisiana and Entergy Mississippi filed with the FERC a PPA under which Entergy Mississippi would purchase Entergy Louisiana’s purchases of Grand Gulf capacity and energy. The PPA is governed by the MSS-4 replacement tariff, a tariff governing the sales of energy and capacity among the Utility operating companies. The requisite approvals for the PPA were issued by the FERC in November 2024 and the MPSC in February 2025. The divestiture is effective as of January 1, 2025.

System Energy Regulatory Liability for Pending Complaints

Prior to June 2022, System Energy recorded a provision and associated liability of $37 million for elements of the complaints against System Energy. In June 2022, as discussed in “System Energy Settlement with the MPSC” above, System Energy recorded a regulatory charge of $551 million ($413 million net-of-tax), increasing System Energy’s regulatory liability to $588 million, which consisted of $235 million for the settlement with the MPSC and $353 million for potential future refunds to Entergy Arkansas, Entergy New Orleans, and Entergy Louisiana. System Energy paid the black box refund of $235 million to Entergy Mississippi in November 2022. As discussed above in “Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue,” in January 2023 System Energy paid refunds of $103.5 million as a result of the FERC’s order in December 2022 in that proceeding and recouped $40.5 million of the $103.5 million from Entergy Louisiana and Entergy New Orleans in October 2023. In addition, as discussed above in “Unit Power Sales Agreement Complaint,” a black box refund of $18 million was made by System Energy in 2023 in connection with a partial settlement in that proceeding. Based on analysis of the then-pending complaints against System Energy and potential future settlement negotiations with the LPSC and the City Council, in third quarter 2023, System Energy recorded a regulatory charge of $40 million to increase System Energy’s regulatory liability related to complaints against System Energy. In December 2023 the $93 million black box refund to Entergy Arkansas was reclassified from the regulatory liability to accounts payable - associated companies on System Energy’s balance sheet. System Energy paid the remaining black box refunds of $93 million to Entergy Arkansas, $98 million to Entergy New Orleans, and $80 million to Entergy Louisiana in 2024.
Unit Power Sales Agreement

System Energy Formula Rate Annual Protocols Formal Challenge Concerning 2020 Calendar Year Bills

System Energy’s Unit Power Sales Agreement includes formula rate protocols that provide for the disclosure of cost inputs, an opportunity for informal discovery procedures, and a challenge process. In February 2022, pursuant to the protocols procedures, the LPSC, the APSC, the MPSC, the City Council, and the Mississippi Public Utilities Staff filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2020. This formal challenge was ultimately settled as a result of System Energy’s global settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” above for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.

System Energy Formula Rate Annual Protocols Formal Challenge Concerning 2021 Calendar Year Bills

In March 2023, pursuant to the protocols procedures discussed above, the LPSC, the APSC, and the City Council filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2021. This formal challenge was ultimately settled as a result of System Energy’s global settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” above for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.

System Energy Formula Rate Annual Protocols Formal Challenge Concerning 2022 Calendar Year Bills

In February 2024, pursuant to the protocols procedures, the LPSC and the City Council filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2022. This formal challenge was ultimately settled as a result of System Energy’s global settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” above for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.

Depreciation Amendment Proceeding

In December 2021, System Energy submitted to the FERC proposed amendments to the Unit Power Sales Agreement to adopt updated rates for use in calculating Grand Gulf plant depreciation and amortization expenses. The proposed amendments would result in higher charges to the Utility operating companies that buy capacity and energy from System Energy under the Unit Power Sales Agreement. In February 2022 the FERC accepted System Energy’s proposed increased depreciation rates with an effective date of March 1, 2022, subject to refund pending the outcome of the settlement and/or hearing procedures. In June 2023 System Energy filed with the FERC an unopposed offer of settlement that it had negotiated with intervenors to the proceeding. In August 2023 the FERC approved the settlement, which resolves the proceeding. In third quarter 2023, System Energy recorded a reduction in depreciation expense of $41 million representing the cumulative difference in depreciation expense resulting from the depreciation rates used from March 2022 through June 2023 and the depreciation rates included in the settlement filing approved by the FERC. In October 2023, System Energy filed a refund report with the FERC. The refund provided for in the refund report was included in the September 2023 service month bills under the Unit Power Sales Agreement. No comments or protests to the refund report were filed.

Pension Costs Amendment Proceeding

In October 2021, System Energy submitted to the FERC proposed amendments to the Unit Power Sales Agreement to include in rate base the prepaid and accrued pension costs associated with System Energy’s qualified pension plans. Based on data ending in 2020, the increased annual revenue requirement associated with the filing is approximately $8.9 million. In March 2022 the FERC accepted System Energy’s proposed amendments with an
effective date of December 1, 2021, subject to refund pending the outcome of the settlement and/or hearing procedures. In August 2023 the FERC chief ALJ terminated settlement procedures and designated a presiding ALJ to oversee hearing procedures. Testimony was filed by the parties from October 2023 through April 2024, and the hearing concluded in June 2024.

In September 2024 the presiding ALJ issued an initial decision recommending that the FERC approve inclusion of a line item in rate base for prepaid and accrued pension costs; however, the presiding ALJ did not agree with System Energy’s proposed methodology to calculate the value of the prepaid and accrued pension cost input. Instead, the presiding ALJ recommended limiting System Energy’s recovery to the prepaid and accrued pension costs that were incurred beginning in 2015 and later.

System Energy disputes the presiding ALJ's determination concerning the methodology used to calculate the prepaid and accrued pension input, and System Energy filed exceptions to these rulings in October 2024. In October 2024, the LPSC, the APSC, and the FERC trial staff filed separate briefs on exceptions; these parties generally argue that the presiding ALJ should have rejected System Energy’s filing entirely, rather than limit System Energy’s recovery of the prepaid and accrued pension costs. Later in October 2024, System Energy, the LPSC, the APSC, and the FERC trial staff filed separate briefs opposing exceptions.

If the ALJ’s determination is affirmed by the FERC, System Energy estimates refunds, including interest through December 31, 2024, of approximately $16 million to $21 million would be owed. The ALJ's initial decision is not binding on the FERC and is an interim step in the hearing process. No refunds will be owed in connection with this proceeding and no changes to System Energy’s pension cost recovery methodology will be implemented unless and until the FERC requires them in a final order. This proceeding is not covered by the global settlements described above.
Storm Cost Recovery Filings with Retail Regulators

Entergy Louisiana

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.

In December 2024, and subsequently amended in an errata filed in February 2025, Entergy Louisiana submitted an application to the LPSC seeking a determination that approximately $183.6 million in storm restoration costs associated with Hurricane Francine were reasonable and necessary and, therefore, eligible for recovery from customers, as well as approval to recover approximately $3.6 million in certain carrying costs from customers. The $183.6 million includes approximately $152.8 million in distribution capital costs and approximately $29.8 million in non-capital costs; the balance consists of transmission and generation capital costs. Entergy Louisiana proposes in its application to recover its distribution-related capital costs of $152.8 million through the distribution recovery mechanism of its formula rate plan. Entergy Louisiana has further requested the LPSC to authorize recovery of these distribution-related capital expenses through an interim rate adjustment, subject to true-up and refund, that would begin with the first billing cycle of March 2025. Entergy Louisiana also requested to recover, from its storm reserve escrow account, $33.5 million, which consists of non-capital costs and certain carrying costs. Entergy Louisiana has also proposed to recover the transmission and generation capital costs through separate ratemaking proceedings. In February 2025, Entergy Louisiana withdrew the $33.5 million from its storm reserve escrow account. The period for intervention has expired, and a status conference for the purpose of establishing a procedural schedule has been set for March 2025.
Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida

In August 2020 and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of Entergy Louisiana’s service area. The storms resulted in widespread outages, significant damage to distribution and transmission infrastructure, and the loss of sales during the outages. Additionally, as a result of Hurricane Laura’s extensive damage to the grid infrastructure serving the impacted area, large portions of the underlying transmission system required nearly a complete rebuild.

In October 2020, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments in connection with the issuance of shorter-term mortgage bonds to provide interim financing for restoration costs associated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta. Subsequently, Entergy Louisiana and the LPSC staff filed a joint motion seeking approval to exclude from the derivation of Entergy Louisiana’s capital structure and cost rate of debt for ratemaking purposes, including the allowance for funds used during construction, shorter-term debt up to $1.1 billion issued by Entergy Louisiana to fund costs associated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta costs on an interim basis. In November 2020 the LPSC issued an order approving the joint motion, and Entergy Louisiana issued $1.1 billion of 0.62% Series mortgage bonds due November 2023. Also in November 2020, Entergy Louisiana withdrew $257 million from its funded storm reserves.

In February 2021 two winter storms (collectively, Winter Storm Uri) brought freezing rain and ice to Louisiana. Ice accumulation sagged or downed trees, limbs, and power lines, causing damage to Entergy Louisiana’s transmission and distribution systems. The additional weight of ice caused trees and limbs to fall into power lines and other electric equipment. When the ice melted, it affected vegetation and electrical equipment, causing additional outages. Entergy Louisiana recovered the incremental fuel costs associated with Winter Storm Uri over a five-month period from April 2021 through August 2021.

In April 2021, Entergy Louisiana filed an application with the LPSC relating to Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri restoration costs and in July 2021, Entergy Louisiana made a supplemental filing updating the total restoration costs. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by these storms were estimated to be approximately $2.06 billion, including approximately $1.68 billion in capital costs and approximately $380 million in non-capital costs. Including carrying costs through January 2022, Entergy Louisiana sought an LPSC determination that $2.11 billion was prudently incurred and, therefore, was eligible for recovery from customers. Additionally, Entergy Louisiana requested that the LPSC determine that re-establishment of a storm escrow account to the previously authorized amount of $290 million was appropriate. In July 2021, Entergy Louisiana supplemented the application with a request regarding the financing and recovery of the recoverable storm restoration costs. Specifically, Entergy Louisiana requested approval to securitize its restoration costs pursuant to Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021.

In August 2021, Hurricane Ida caused extensive damage to Entergy Louisiana’s distribution and, to a lesser extent, transmission systems resulting in widespread power outages. In September 2021, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments in connection with the issuance of approximately $1 billion of shorter-term mortgage bonds to provide interim financing for restoration costs associated with Hurricane Ida, which bonds were issued in October 2021. Also in September 2021, Entergy Louisiana sought approval for the creation and funding of a $1 billion restricted escrow account for Hurricane Ida related restoration costs, subject to a subsequent prudence review.

After filing of testimony by the LPSC staff and intervenors, which generally supported or did not oppose Entergy Louisiana’s requests in regard to Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida, the parties negotiated and executed an uncontested stipulated settlement which was filed with the LPSC in February 2022. The settlement agreement contained the following key terms: $2.1 billion of restoration costs from Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri were prudently incurred and
eligible for recovery; carrying costs of $51 million were recoverable; a $290 million cash storm reserve should be re-established; a $1 billion reserve should be established to partially pay for Hurricane Ida restoration costs; and Entergy Louisiana was authorized to finance $3.186 billion utilizing the securitization process authorized by Act 55, as supplemented by Act 293. The LPSC issued an order approving the settlement in March 2022. As a result of the financing order, Entergy Louisiana reclassified $1.942 billion from utility plant to other regulatory assets.

In May 2022 the securitization financing closed, resulting in the issuance of $3.194 billion principal amount of bonds by Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA), a political subdivision of the State of Louisiana. The securitization was authorized pursuant to the Louisiana Utilities Restoration Corporation Act, Part VIII of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana legislature approved in 2021. The LCDA loaned the proceeds to the LURC. Pursuant to Act 293, the LURC contributed the net bond proceeds to a State legislatively authorized and LURC-sponsored trust, Restoration Law Trust I (the storm trust I).

Pursuant to Act 293, the net proceeds of the bonds were used by the storm trust I to purchase 31,635,718.7221 Class A preferred, non-voting membership interest units (the preferred membership interests) issued by Entergy Finance Company. Entergy Finance Company is required to make annual distributions (dividends) commencing on December 15, 2022 on the preferred membership interests issued to the storm trust I. These annual dividends received by the storm trust I will be distributed to Entergy Louisiana and the LURC, as beneficiaries of the storm trust I. Specifically, 1% of the annual dividends received by the storm trust I will be distributed to the LURC, for the benefit of customers, and 99% will be distributed to Entergy Louisiana, net of storm trust expenses. The preferred membership interests have a stated annual cumulative cash dividend rate of 7% and a liquidation price of $100 per unit. The terms of the preferred membership interests include certain financial covenants to which Entergy Finance Company is subject. Semi-annual redemptions of the preferred membership interests, subject to certain conditions, are expected to occur over the next 15 years.

Entergy and Entergy Louisiana do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA. The bonds are secured by system restoration property, which is the right granted by law to the LURC to collect a system restoration charge from customers. The system restoration charge is adjusted at least semi-annually to ensure that it is sufficient to service the bonds. Entergy Louisiana collects the system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee. Entergy Louisiana began collecting the system restoration charge effective with the first billing cycle of June 2022 and the system restoration charge is expected to remain in place for up to 15 years. Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as a billing and collection agent for the LCDA and the LURC. In the remote possibility that the system restoration charge, as well as any funds in the excess subaccount and funds in the debt service reserve account, are insufficient to service the bonds resulting in a payment default, the storm trust I is required to liquidate Entergy Finance Company preferred membership interests in an amount equal to what would be required to cure the default. The estimated value of this indirect guarantee is immaterial.

From the proceeds from the issuance of the preferred membership interests, Entergy Finance Company distributed $1.4 billion to its parent, Entergy Holdings Company, LLC, a company wholly-owned and consolidated by Entergy. Subsequently, Entergy Holdings Company liquidated, distributing the $1.4 billion it received from Entergy Finance Company to Entergy Louisiana as holder of 6,843,780.24 units of Class A, 4,126,940.15 units of Class B, and 2,935,152.69 units of Class C preferred membership interests. Entergy Louisiana had acquired these preferred membership interests with proceeds from previous securitizations of storm restoration costs. Entergy Finance Company loaned the remaining $1.7 billion from the preferred membership interests proceeds to Entergy which used the cash to redeem $650 million of 4.00% Series senior notes due July 2022 and indirectly contributed $1 billion to Entergy Louisiana as a capital contribution.

Entergy Louisiana used the $1 billion capital contribution to fund its Hurricane Ida escrow account and subsequently withdrew the $1 billion from the escrow account. With a portion of the $1 billion withdrawn from the
escrow account and the $1.4 billion from the Entergy Holdings Company liquidation, Entergy Louisiana deposited $290 million in a restricted escrow account as a storm damage reserve for future storms, used $1.2 billion to repay its unsecured term loan due June 2023, and used $435 million to redeem a portion of its 0.62% Series mortgage bonds due November 2023.

As discussed in Note 3 to the financial statements, the securitization resulted in recognition of a reduction of income tax expense of approximately $290 million by Entergy Louisiana. Entergy’s recognition of reduced income tax expense was partially offset by other tax charges resulting in a net reduction of income tax expense of $283 million. In recognition of obligations described in an LPSC ancillary order issued as part of the securitization regulatory proceeding, Entergy Louisiana recorded a $224 million ($165 million net-of-tax) regulatory charge and a corresponding regulatory liability to reflect its obligation to provide credits to its customers.

As discussed in Note 6 and Note 17 to the financial statements, Entergy Louisiana consolidates the storm trust I as a variable interest entity and the LURC’s 1% beneficial interest is presented as noncontrolling interest in the financial statements. In second quarter 2022, Entergy Louisiana recorded a charge of $31.6 million in other income to reflect the LURC’s beneficial interest in the storm trust I.

In April 2022, Entergy Louisiana filed an application with the LPSC relating to Hurricane Ida restoration costs. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by Hurricane Ida were estimated to be approximately $2.54 billion, including approximately $1.96 billion in capital costs and approximately $586 million in non-capital costs. Including carrying costs of $57 million through December 2022, Entergy Louisiana was seeking an LPSC determination that $2.60 billion was prudently incurred and, therefore, eligible for recovery from customers. As part of this filing, Entergy Louisiana also was seeking an LPSC determination that an additional $32 million in costs associated with the restoration of Entergy Louisiana’s electric facilities damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta as well as Winter Storm Uri was prudently incurred. This amount was exclusive of the requested $3 million in carrying costs through December 2022. In total, Entergy Louisiana was requesting an LPSC determination that $2.64 billion was prudently incurred and, therefore, eligible for recovery from customers. As discussed above, in March 2022 the LPSC approved financing of a $1 billion storm escrow account from which funds were withdrawn to finance costs associated with Hurricane Ida restoration. In June 2022, Entergy Louisiana supplemented the application with a request regarding the financing and recovery of the recoverable storm restoration costs. Specifically, Entergy Louisiana requested approval to securitize its restoration costs pursuant to Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021. In October 2022 the LPSC staff recommended a finding that the requested storm restoration costs of $2.64 billion, including associated carrying costs of $59.1 million, were prudently incurred and eligible for recovery from customers. The LPSC staff further recommended approval of Entergy Louisiana’s plans to securitize these costs, net of the $1 billion in funds withdrawn from the storm escrow account described above. The parties negotiated and executed an uncontested stipulated settlement which was filed with the LPSC in December 2022. The settlement agreement contains the following key terms: $2.57 billion of restoration costs from Hurricane Ida, Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri were prudently incurred and eligible for recovery; carrying costs of $59.2 million were recoverable; and Entergy Louisiana was authorized to finance $1.657 billion utilizing the securitization process authorized by Act 55, as supplemented by Act 293. A procedural motion to consider the uncontested settlement at the December 2022 LPSC meeting did not pass and the settlement was not voted on. In January 2023 an ALJ with the LPSC conducted a settlement hearing to receive the uncontested settlement and supporting testimony into evidence and issued a report of proceedings, which allows the LPSC to consider the uncontested settlement without the procedural motion that did not pass in December. In January 2023 the LPSC approved the stipulated settlement subject to certain modifications. These modifications include the recognition of accumulated deferred income tax benefits related to damaged assets and system restoration costs as a reduction of the amount authorized to be financed utilizing the securitization process authorized by Act 55, as supplemented by Act 293, from $1.657 billion to $1.491 billion. These modifications did not affect the LPSC’s conclusion that all system restoration costs sought by Entergy Louisiana were reasonable and prudent. In February 2023 the Louisiana Bond Commission voted to authorize the LCDA to issue the bonds authorized in the LPSC’s financing order.
In March 2023 the Hurricane Ida securitization financing closed, resulting in the issuance of approximately $1.491 billion principal amount of bonds by the LCDA and a remaining regulatory asset of $180 million to be recovered through the exclusion of the accumulated deferred income taxes related to damaged assets and system restoration costs from the determination of future rates. The securitization was authorized pursuant to the Louisiana Utilities Restoration Corporation Act, Part VIII of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021. The LCDA loaned the proceeds to the LURC. Pursuant to Act 293, the LURC contributed the net bond proceeds to a State legislatively authorized and LURC-sponsored trust, Restoration Law Trust II (the storm trust II).

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

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

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

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

As discussed in Note 6 and Note 17 to the financial statements, Entergy Louisiana consolidates the storm trust II as a variable interest entity and the LURC’s 1% beneficial interest is presented as noncontrolling interest in
the financial statements. In first quarter 2023, Entergy Louisiana recorded a charge of $14.6 million in other income to reflect the LURC’s beneficial interest in the storm trust II.

Hurricane Isaac

In August 2012, Hurricane Isaac caused extensive damage to Entergy Louisiana’s service area.  In June 2014 the LPSC authorized Entergy Louisiana to utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs.  Entergy Louisiana committed to pass on to customers a minimum of $30.8 million of customer benefits through annual customer credits of approximately $6.2 million for five years. Approvals for the Act 55 financings were obtained from the LURC and the Louisiana State Bond Commission.

In August 2014 the LCDA issued $314.85 million in bonds under Louisiana Act 55.  From the $309 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $16 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $293 million directly to Entergy Louisiana.  Entergy Louisiana used the $293 million received from the LURC to acquire 2,935,152.69 Class C preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 7.5% annual distribution rate. Distributions were payable quarterly commencing on September 15, 2014, and the membership interests had a liquidation price of $100 per unit. The preferred membership interests were callable at the option of Entergy Holdings Company after ten years under the terms of the LLC agreement. The terms of the membership interests included certain financial covenants to which Entergy Holdings Company was subject, including the requirement to maintain a net worth of at least $1.75 billion. As discussed above in “Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida”, in May 2022, Entergy Holdings Company liquidated and distributed cash to Entergy Louisiana as holder of the 2,935,152.69 units of Class C preferred membership interests.

Entergy and Entergy Louisiana do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA and there is no recourse against Entergy or Entergy Louisiana in the event of a bond default.  To service the bonds, Entergy Louisiana collects a system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee.  Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as the billing and collection agent for the state.

Hurricane Gustav and Hurricane Ike

In September 2008, Hurricane Gustav and Hurricane Ike caused catastrophic damage to Entergy Louisiana’s service territory.  In December 2009, Entergy Louisiana entered into a stipulation agreement with the LPSC staff regarding its storm costs.  In March and April 2010, Entergy Louisiana and other parties to the proceeding filed with the LPSC an uncontested stipulated settlement that included Entergy Louisiana’s proposal to utilize Act 55 financing, which included a commitment to pass on to customers a minimum of $43.3 million of customer benefits through a prospective annual rate reduction of $8.7 million for five years.  In April 2010 the LPSC approved the settlement and subsequently issued financing orders and a ratemaking order intended to facilitate the implementation of the Act 55 financings.  In June 2010 the Louisiana State Bond Commission approved the Act 55 financing. The settlement agreement allowed for an adjustment to the credits if there was a change in the applicable federal or state income tax rate. As a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, and the lowering of the federal corporate income tax rate from 35% to 21%, the Louisiana Act 55 financing savings obligation regulatory liability related to Hurricane Gustav and Hurricane Ike was reduced by $2.7 million, with a corresponding increase to Other regulatory credits on the income statement. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.

In July 2010 the LCDA issued two series of bonds totaling $713.0 million under Act 55.  From the $702.7 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $290 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $412.7 million directly to Entergy Louisiana.  From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana
used $412.7 million to acquire 4,126,940.15 Class B preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 9% annual distribution rate. Distributions were payable quarterly commencing on September 15, 2010, and the membership interests had a liquidation price of $100 per unit. The preferred membership interests were callable at the option of Entergy Holdings Company after ten years under the terms of the LLC agreement.  The terms of the membership interests included certain financial covenants to which Entergy Holdings Company was subject, including the requirement to maintain a net worth of at least $1 billion. As discussed above in “Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida”, in May 2022, Entergy Holdings Company liquidated and distributed cash to Entergy Louisiana as holder of the 4,126,940.15 units of Class B preferred membership interests.

The bonds were repaid in 2022. Entergy and Entergy Louisiana did not report the bonds issued by the LCDA on their balance sheets because the bonds were the obligation of the LCDA, and there was no recourse against Entergy or Entergy Louisiana in the event of a bond default.  To service the bonds, Entergy Louisiana collected a system restoration charge on behalf of the LURC and remitted the collections to the bond indenture trustee.  Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as the billing and collection agent for the state.

Hurricane Katrina and Hurricane Rita

In August and September 2005, Hurricanes Katrina and Rita caused catastrophic damage to Entergy Louisiana’s service territory. In March 2008, Entergy Louisiana and the LURC filed at the LPSC an application requesting that the LPSC grant a financing order authorizing the financing of Entergy Louisiana storm costs, storm reserves, and issuance costs pursuant to Louisiana Act 55.  Entergy Louisiana also filed an application requesting LPSC approval for ancillary issues including the mechanism to flow charges and savings to customers via a storm cost offset rider.  In April 2008 the Louisiana Public Facilities Authority (LPFA), which is the issuer of the bonds pursuant to the Act 55 financing, approved requests for the Act 55 financing.  Also in April 2008, Entergy Louisiana and the LPSC staff filed with the LPSC an uncontested stipulated settlement that included Entergy Louisiana’s proposal under the Act 55 financing, which included a commitment to pass on to customers a minimum of $40 million of customer benefits through a prospective annual rate reduction of $8 million for five years.  The LPSC subsequently approved the settlement and issued two financing orders and one ratemaking order intended to facilitate implementation of the Act 55 financing.  In May 2008 the Louisiana State Bond Commission granted final approval of the Act 55 financing. The settlement agreement allowed for an adjustment to the credits if there was a change in the applicable federal or state income tax rate. As a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, and the lowering of the federal corporate income tax rate from 35% to 21%, the Louisiana Act 55 financing savings obligation regulatory liability related to Hurricanes Katrina and Rita was reduced by $22.3 million, with a corresponding increase to Other regulatory credits on the income statement. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.

In July 2008 the LPFA issued $687.7 million in bonds under the aforementioned Act 55.  From the $679 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $152 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $527 million directly to Entergy Louisiana.  From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $545 million, including $17.8 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 5,449,861.85 Class A preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 10% annual distribution rate.  In August 2008 the LPFA issued $278.4 million in bonds under the aforementioned Act 55.  From the $274.7 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $87 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $187.7 million directly to Entergy Louisiana.  From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $189.4 million, including $1.7 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 1,893,918.39 Class A preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 10% annual distribution rate.  Distributions were payable quarterly commencing on September 15, 2008 and had a
liquidation price of $100 per unit.  The preferred membership interests were callable at the option of Entergy Holdings Company after ten years under the terms of the LLC agreement.  The terms of the membership interests included certain financial covenants to which Entergy Holdings Company was subject, including the requirement to maintain a net worth of at least $1 billion.  In February 2012, Entergy Louisiana sold 500,000 of its Class A preferred membership units in Entergy Holdings Company to a third party. Those preferred membership units were subsequently repurchased by Entergy Holdings Company in March 2019. As discussed above in “Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida”, in May 2022, Entergy Holdings Company liquidated and distributed cash to Entergy Louisiana as holder of the remaining 6,843,780.24 units of Class A preferred membership interests.

The bonds were repaid in 2018. Entergy and Entergy Louisiana did not report the bonds issued by the LPFA on their balance sheets because the bonds were the obligation of the LPFA, and there was no recourse against Entergy or Entergy Louisiana in the event of a bond default.  To service the bonds, Entergy Louisiana collected a system restoration charge on behalf of the LURC and remitted the collections to the bond indenture trustee.  Entergy and Entergy Louisiana did not report the collections as revenue because Entergy Louisiana was merely acting as the billing and collection agent for the state.

Entergy Mississippi

Prior to June 2024, Entergy Mississippi had approval from the MPSC to collect a storm damage provision of $1.75 million per month. If Entergy Mississippi’s accumulated storm damage provision balance exceeded $15 million, the collection of the storm damage provision ceased until such time that the accumulated storm damage provision became less than $10 million. Entergy Mississippi’s storm damage provision balance had been less than $10 million since May 2019, and Entergy Mississippi had been billing the monthly storm damage provision since July 2019.

In December 2023, Entergy Mississippi filed a Notice of Storm Escrow Disbursement and Request for Interim Relief notifying the MPSC that Entergy Mississippi had requested disbursement of approximately $34.5 million of storm escrow funds from its restricted storm escrow account. The filing also requested authorization from the MPSC, on a temporary basis, that the $34.5 million of storm escrow funds be credited to Entergy Mississippi’s storm damage provision, pending the MPSC’s review of Entergy Mississippi’s storm-related costs, and that Entergy Mississippi continue to bill its monthly storm damage provision without suspension in the event the storm damage provision balance exceeded $15 million, in anticipation of a subsequent filing by Entergy Mississippi in this proceeding. The storm damage provision exceeded $15 million upon receipt of the storm escrow funds. Because the MPSC had not entered an order on Entergy Mississippi’s filing on the requested relief to continue billing this provision, Entergy Mississippi suspended billing the monthly storm damage provision effective with February 2024 bills.

In March 2024, Entergy Mississippi made a combined dual filing which included a notice of intent to make routine change in rates and schedules and a motion for determination relating to the above-described notice of storm escrow disbursement. The notice of intent proposed a new storm damage mitigation and restoration rider to supersede both the then-current storm damage rate schedule and the vegetation management rider schedule, in which the collection of both expenses would be combined. The proposal requested that the MPSC authorize Entergy Mississippi to collect approximately $5.2 million per month for vegetation management and a storm damage provision. Furthermore, if Entergy Mississippi’s accumulated vegetation management and storm damage provision balance were to exceed $70 million, collection under the storm damage mitigation and restoration rider would cease until such time that the accumulated vegetation management and storm damage provision would become less than $60 million.

The Mississippi Public Utilities Staff reviewed the storm-related costs submitted by Entergy Mississippi and found them prudent. In June 2024 the MPSC considered and unanimously granted the relief sought by Entergy Mississippi, including authorization to credit any remaining funds in the storm escrow account to Entergy
Mississippi’s storm damage provision and to close the storm escrow account and approving the new storm damage mitigation and restoration rider. Entergy Mississippi’s storm escrow account was liquidated in July 2024, and the new combined storm damage mitigation and restoration rider became effective with the July 2024 billing cycle. Additionally, Entergy Mississippi made a compliance filing to cease billing under the existing vegetation management rider schedule as of the same billing cycle.

Entergy New Orleans

Hurricane Ida

In August 2021, Hurricane Ida caused significant damage to Entergy New Orleans’s service area, including Entergy’s electrical grid. The storm resulted in widespread power outages, including the loss of 100% of Entergy New Orleans’s load and damage to distribution and transmission infrastructure, including the loss of connectivity to the eastern interconnection. In September 2021, Entergy New Orleans withdrew $39 million from its funded storm reserves. In June 2022, Entergy New Orleans filed an application with the City Council requesting approval and certification that storm restoration costs associated with Hurricane Ida of approximately $170 million, which included $11 million in estimated costs, were reasonable, necessary, and prudently incurred to enable Entergy New Orleans to restore electric service to its customers and to repair Entergy New Orleans’s electric utility infrastructure. In addition, estimated carrying costs through December 2022 related to Hurricane Ida restoration costs were $9 million. Also, Entergy New Orleans requested approval that the $39 million withdrawal from its funded storm reserve in September 2021 and $7 million in excess storm reserve escrow withdrawals related to Hurricane Zeta in October 2020 and prior miscellaneous storms were properly applied to Hurricane Ida storm restoration costs, the application of which reduced the amount to be recovered from Entergy New Orleans customers by $46 million.

Additionally, in February 2022, Entergy New Orleans and the LURC filed with the City Council a securitization application requesting that the City Council review Entergy New Orleans’s storm reserve and increase the storm reserve funding level to $150 million, to be funded through securitization. In August 2022 the City Council’s advisors recommended that the City Council authorize a single securitization bond issuance to fund Entergy New Orleans’s storm recovery reserves to an amount sufficient to: (1) allow recovery of all of Entergy New Orleans’s unrecovered storm recovery costs following Hurricane Ida, subject to City Council review and certification; (2) provide initial funding of storm recovery reserves for future storms to a level of $75 million; and (3) fund the storm recovery bonds’ upfront financing costs. In September 2022, Entergy New Orleans and the City Council’s advisors entered into an agreement in principle, which was approved by the City Council along with a financing order in October 2022, which authorized Entergy New Orleans and the LURC to proceed with a single securitization bond issuance of approximately $206 million (subject to further adjustment and review pursuant to the Final Issuance Advice Letter process set forth in the financing order), with $125 million of that total to be used for interim recovery, subject to City Council review and certification, to be allocated to unrecovered Hurricane Ida storm recovery costs; $75 million of that total to provide for a storm recovery reserve for future storms; and the remainder to fund the recovery of the storm recovery bonds’ upfront financing costs.

In December 2022, Entergy New Orleans and the LURC filed with the City Council the Final Issuance Advice Letter for a securitization bond issuance in the amount of $209.3 million, the final structuring, terms, and pricing of which were approved by the City Council in accordance with the financing order. Also in December 2022 the LCDA issued $209.3 million in bonds pursuant to the Louisiana Electric Utility Storm Recovery Securitization Act, Part V-B of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana Regular Session of 2021. The LCDA loaned $201.8 million of bond proceeds, net of certain debt service and issuance costs, to the LURC. The LURC used the proceeds to purchase from Entergy New Orleans the storm recovery property, which is the right to collect storm recovery charges sufficient to pay the storm recovery bonds and associated financing costs, and Entergy New Orleans deposited $200 million in a restricted storm reserve escrow account as a storm damage reserve for Entergy New Orleans and received directly $1.8 million in estimated upfront financing costs. Subsequently, Entergy New Orleans withdrew $125 million from the newly securitized
storm reserve to cover Hurricane Ida storm recovery costs, subject to a final determination from the City Council regarding the prudency of the storm recovery costs.

Entergy and Entergy New Orleans do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA, and there is no recourse against Entergy or Entergy New Orleans in the event of a bond default. To service the bonds, Entergy New Orleans collects a storm recovery charge on behalf of the LURC and remits the collections to the bond indenture trustee. Entergy and Entergy New Orleans do not report the collections as revenue because Entergy New Orleans is merely acting as the billing and collection agent for the LURC.

In August 2023 the City Council advisors issued a report recommending that the City Council find that Entergy New Orleans prudently incurred approximately $164.1 million in storm restoration costs and $7.5 million in carrying charges and that such costs have already been properly recovered by Entergy New Orleans through withdrawals from the storm reserve escrow account. The City Council advisors also recommended that the City Council find that approximately $1.2 million in storm restoration costs had already been recovered through Entergy New Orleans’s base rates and that approximately $0.9 million in unused credits be applied against future storm costs. In August 2023 the City Council hearing officer certified the evidentiary record. In December 2023 the City Council approved a resolution adopting the advisors’ report and recommendations.

Entergy Texas

Hurricane Laura, Hurricane Delta, and Winter Storm Uri

In August 2020 and October 2020, Hurricane Laura and Hurricane Delta caused extensive damage to Entergy Texas’s service area. In February 2021, Winter Storm Uri also caused damage to Entergy Texas’s service area. The storms resulted in widespread power outages, significant damage primarily to distribution and transmission infrastructure, and the loss of sales during the power outages. In April 2021, Entergy Texas filed an application with the PUCT requesting a determination that approximately $250 million of system restoration costs associated with Hurricane Laura, Hurricane Delta, and Winter Storm Uri, including approximately $200 million in capital costs and approximately $50 million in non-capital costs, were reasonable and necessary to enable Entergy Texas to restore electric service to its customers and Entergy Texas’s electric utility infrastructure. The filing also included the projected balance of approximately $13 million of a regulatory asset containing previously approved system restoration costs related to Hurricane Harvey. In September 2021 the parties filed an unopposed settlement agreement, pursuant to which Entergy Texas removed from the amount to be securitized approximately $4.3 million that will instead be charged to its storm reserve, $5 million related to no particular issue, of which Entergy Texas would be permitted to seek recovery in a future proceeding, and approximately $300 thousand related to attestation costs. In December 2021 the PUCT issued an order approving the unopposed settlement and determining system restoration costs of $243 million related to Hurricane Laura, Hurricane Delta, and Winter Storm Uri and the $13 million projected remaining balance of the Hurricane Harvey system restoration costs were eligible for securitization. The order also determines that Entergy Texas can recover carrying costs on the system restoration costs related to Hurricane Laura, Hurricane Delta, and Winter Storm Uri.

In July 2021, Entergy Texas filed with the PUCT an application for a financing order to approve the securitization of the system restoration costs that are the subject of the April 2021 application. In November 2021 the parties filed an unopposed settlement agreement supporting the issuance of a financing order consistent with Entergy Texas’s application and with minor adjustments to certain upfront and ongoing costs to be incurred to facilitate the issuance and serving of system restoration bonds. In January 2022 the PUCT issued a financing order consistent with the unopposed settlement. As a result of the financing order, Entergy Texas reclassified $153 million from utility plant to other regulatory assets.

In April 2022, Entergy Texas Restoration Funding II, LLC, a company wholly-owned and consolidated by Entergy Texas, issued $290.85 million of senior secured system restoration bonds (securitization bonds). With the
proceeds, Entergy Texas Restoration Funding II purchased from Entergy Texas the transition property, which is the right to recover from customers through a system restoration charge amounts sufficient to service the securitization bonds. Entergy Texas began cost recovery through the system restoration charge effective with the first billing cycle of May 2022 and the system restoration charge is expected to remain in place up to 15 years. See Note 5 to the financial statements for a discussion of the April 2022 issuance of the securitization bonds.
System Energy [Member]  
Public Utilities Disclosure [Text Block] RATE AND REGULATORY MATTERS (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Regulatory Assets and Regulatory 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. In addition to the regulatory assets and liabilities that are specifically disclosed on the face of the balance sheets, the tables below provide detail of “Other regulatory assets” and “Other regulatory liabilities” that are included on Entergy’s and the Registrant Subsidiaries’ balance sheets as of December 31, 2024 and 2023 (as noted in footnotes to the tables, a portion of these regulatory assets and regulatory liabilities is classified as held for sale in the balance sheets as of December 31, 2024):

Other Regulatory Assets

Entergy
20242023
 (In Millions)
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
$1,387.6 $1,655.5 
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or shutdown of non-nuclear power plants and solar facilities (Note 9) (a)
1,358.7 1,285.0 
Removal costs (Note 9)
1,107.6 1,010.7 
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators and Note 5 - Securitization Bonds)
547.3 536.9 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
227.1 250.9 
Retail rate deferrals - recovered through formula rates or rate riders as rates are redetermined by retail regulators
195.1 248.6 
Retired electric and gas meters - recovered through retail rates as determined by retail regulators (Note 2 - Retail Rate Proceedings)
135.7 153.8 
Deferred COVID-19 costs - recovered through retail rates as determined by retail regulators (Note 2 - Retail Rate Proceedings)
104.0 118.0 
Unamortized loss on reacquired debt - recovered over term of debt
57.9 63.1 
Advanced metering system surcharge for residential customers - recovered through December 2029
39.7 20.2 
Formula rate plan historical year rate adjustment (Note 2 - Retail Rate Proceedings) (b)
15.5 — 
Pension & postretirement benefits expense deferral - recovered through retail rates (Note 2 - Retail Rate Proceedings and Note 11 - Entergy Texas Reserve)
15.0 32.7 
Rate case depreciation relate back deferral - recovered over a six-month period beginning January 2024 (Note 2 - Retail Rate Proceedings)
— 27.6 
Opportunity sales - (Note 2 - Entergy Arkansas Opportunity Sales Proceeding) (b)
— 131.8 
Other99.7 134.6 
Entergy Total (c)
$5,290.9 $5,669.4 
Entergy Arkansas
 20242023
 (In Millions)
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or shutdown of non-nuclear power plants and solar facilities (Note 9) (a)
$693.0 $639.1 
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
433.3 536.6 
Removal costs (Note 9)
337.9 319.7 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
75.8 84.1 
Deferred COVID-19 costs - recovered over a 10-year period through December 2033
35.1 39.0 
Retired electric meters - recovered over a 15-year period through March 2034
32.8 36.3 
Storm damage costs - recovered through retail rates
29.8 33.1 
Unamortized loss on reacquired debt - recovered over term of debt
18.6 19.9 
Formula rate plan historical year rate adjustment (Note 2 - Retail Rate Proceedings) (b)
15.5 — 
Retail rate deferrals - recovered through rate riders as rates are redetermined annually (b)
13.6 24.9 
ANO Fukushima and Flood Barrier costs - recovered through retail rates through February 2026 (b)
2.1 3.8 
Opportunity sales - (Note 2 - Entergy Arkansas Opportunity Sales Proceeding) (b)
— 131.8 
Other12.6 17.1 
Entergy Arkansas Total$1,700.1 $1,885.4 

Entergy Louisiana
 20242023
 (In Millions)
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or shutdown of non-nuclear power plants (Note 9) (a)
$421.5 $408.7 
Pension & postretirement costs (Note 11 - Qualified Pension Plans and Non-Qualified Pension Plans) (a)
367.7 412.0 
Removal costs (Note 9)
323.2 262.3 
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)
226.6 202.6 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
111.4 123.0 
Retired electric and gas meters - recovered over a 22-year period through July 2041
78.5 83.2 
Deferred COVID-19 costs - recovery period to be determined (Note 2 - Retail Rate Proceedings) (a)
47.8 47.8 
Unamortized loss on reacquired debt - recovered over term of debt
21.7 23.4 
Other48.5 85.9 
Entergy Louisiana Total (c)
$1,646.9 $1,648.9 
Entergy Mississippi
 20242023
(In Millions)
Removal costs (Note 9)
$184.8 $188.0 
Retail rate deferrals - recovered through formula rates or rate riders as rates are redetermined annually
162.5 192.8 
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
112.1 127.6 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
29.1 32.0 
Asset retirement obligation - recovery dependent upon timing of shutdown of non-nuclear power plants and solar facility (Note 9) (a)
9.4 6.8 
Unamortized loss on reacquired debt - recovered over term of debt
9.1 10.0 
Attorney General litigation costs - recovered over a six-year period through March 2026 (b)
6.0 10.9 
Other12.8 11.0 
Entergy Mississippi Total$525.8 $579.1 

Entergy New Orleans
 20242023
 (In Millions)
Removal costs (Note 9)
$62.5 $61.1 
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
22.9 41.4 
Retired electric and gas meters - recovered over a 12-year period through July 2031 (b)
13.5 15.5 
Gas cross-boring costs - recovered through formula rates as rates are redetermined by retail regulators
11.9 10.9 
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)
10.8 11.8 
Deferred COVID-19 costs - recovered over a five-year period through August 2028 (b)
10.2 13.0 
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators and Note 5 - Entergy New Orleans Securitization Bonds - Hurricane Isaac)
4.0 3.9 
Unamortized loss on reacquired debt - recovered over term of debt
0.5 0.8 
Other20.7 24.0 
Entergy New Orleans Total (c)
$157.0 $182.4 
Entergy Texas
 20242023
 (In Millions)
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators and Note 5 - Entergy Texas Securitization Bonds - Hurricane Laura, Hurricane Delta, and Winter Storm Uri)
$286.5 $297.3 
Removal costs (Note 9)
102.3 77.5 
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
62.9 85.6 
Advanced metering system surcharge for residential customers - recovered through December 2029
39.7 20.2 
Pension & postretirement benefits expense deferral - recovered through retail rates (Note 2 - Retail Rate Proceedings and Note 11 - Entergy Texas Reserve)
15.0 32.7 
Retired electric meters - recovered through retail rates (Note 2 - Retail Rate Proceedings)
10.9 18.8 
Neches and Sabine costs - recovered over a 10-year period through September 2028
9.2 11.6 
Unamortized loss on reacquired debt - recovered over term of debt
7.6 8.3 
Rate case depreciation relate back deferral - recovered over a six-month period beginning January 2024 (Note 2 - Retail Rate Proceedings)
— 27.6 
Other15.6 17.0 
Entergy Texas Total$549.7 $596.6 

System Energy
 20242023
 (In Millions)
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear unit (Note 9) (b)
$224.8 $222.0 
Pension & postretirement costs (Note 11 - Qualified Pension Plans and Other Postretirement Benefits) (a)
104.4 121.6 
Removal costs - recovered through depreciation rates (Note 9)
96.9 102.1 
Unamortized loss on reacquired debt - recovered over term of debt
0.4 0.7 
System Energy Total$426.5 $446.4 

(a)Does not earn a return on investment, but is offset by related liabilities.
(b)Does not earn a return on investment.
(c)Includes $35.4 million at Entergy, $8.9 million at Entergy Louisiana, and $23.7 million at Entergy New Orleans as of December 31, 2024 of regulatory assets related to the respective natural gas distribution businesses classified as held for sale and included within “Non-current assets held for sale” on the respective consolidated balance sheets. See Note 14 to the financial statements for further discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses and the classification as held for sale.
Other Regulatory Liabilities

Entergy
20242023
(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)
$2,262.5 $1,826.2 
Securitization financing savings obligation (Note 3)
371.3 405.2 
Retail rate rider over-recovery - refunded through formula rate or rate riders as rates are redetermined by retail regulators
164.9 142.7 
Credits from resolution of the 2016-2018 IRS audit (Note 3)
163.3 98.0 
Customer rate credits from global stipulated settlement with the LPSC - returned to customers September 2024 through August 2026 (Note 2)
121.7 — 
Refund from System Energy settlement with the LPSC - to be returned to customers January 2025 through August 2027 (Note 2)
75.8 — 
Deferred tax equity partnership earnings (Note 1)
69.9 57.9 
Vidalia purchased power agreement (Note 8)
67.4 82.5 
Refund from System Energy settlement with the City Council - returned to customers over a 25-year period beginning September 2024 (Note 2)
64.7 — 
Shorter-term financing interest earnings (Note 2 - Retail Rate Proceedings) (a)
48.9 36.8 
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and the FERC
44.4 44.4 
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)
40.9 44.3 
Refund from System Energy settlement with the City Council - return to customers to be determined (Note 2)
32.0 — 
Refund from System Energy settlement with the APSC - refunded through a rate rider as rates are re-determined periodically (Note 2)
8.2 93.0 
Complaints against System Energy - potential future refunds (Note 2)
— 177.9 
Other75.2 108.0 
Entergy Total (b)
$3,611.1 $3,116.9 

Entergy Arkansas
 20242023
 (In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)
$761.3 $621.6 
Deferred tax equity partnership earnings (Note 1)
32.4 27.4 
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually
27.9 10.6 
Refund from System Energy settlement with the APSC - refunded through a rate rider as rates are re-determined periodically (Note 2)
8.2 93.0 
Internal restructuring guaranteed customer credits - returned to customers over a six-year period through December 2024
— 6.6 
Other1.4 — 
Entergy Arkansas Total$831.2 $759.2 
Entergy Louisiana
 20242023
 (In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)
$798.4 $644.0 
Securitization financing savings obligation (Note 3)
371.3 405.2 
Customer rate credits from global stipulated settlement with the LPSC - returned to customers September 2024 through August 2026 (Note 2)
121.7 — 
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually
96.3 86.4 
Refund from System Energy settlement with the LPSC - to be returned to customers January 2025 through August 2027 (Note 2)
75.8 — 
Vidalia purchased power agreement (Note 8)
67.4 82.5 
Shorter-term financing interest earnings (Note 2 - Retail Rate Proceedings) (a)
48.9 36.8 
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)
40.9 44.3 
Hurricane Ida insurance proceeds - returned to customers August 2024 to July 2025
26.0 32.3 
Credits from resolution of the 2016-2018 IRS audit - returned to customers September 2024 through August 2025 (Note 3)
25.3 38.0 
Sale-leaseback and depreciation refunds - returned to customers September 2023 through August 2024
— 14.1 
Other21.7 24.1 
Entergy Louisiana Total (b)
$1,693.7 $1,407.7 

Entergy Mississippi
20242023
 (In Millions)
Deferred tax equity partnership earnings (Note 1)
$37.5 $30.5 
Retail rate rider over-recovery - refunded through formula rate or rate riders as rates are redetermined annually
12.2 2.4 
Other postretirement benefits (Note 11 - Entergy Mississippi Other Postretirement Benefits)
7.4 — 
Other2.4 0.8 
Entergy Mississippi Total$59.5 $33.7 
Entergy New Orleans
20242023
 (In Millions)
Credits from resolution of the 2016-2018 IRS audit - to be returned to customers over a 25-year period beginning January 2025 (Note 3)
$138.0 $60.0 
Refund from System Energy settlement with the City Council - returned to customers over a 25-year period beginning September 2024 (Note 2)
64.7 — 
Refund from System Energy settlement with the City Council - return to customers to be determined (Note 2)
32.0 — 
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually
16.3 20.1 
Sale-leaseback and depreciation refunds - returned to customers over a 10-year period beginning September 2023 (Note 2)
5.2 9.8 
Other4.5 0.5 
Entergy New Orleans Total (b)
$260.7 $90.4 

Entergy Texas
 20242023
 (In Millions)
Retail rate rider over-recovery - return to customers to be determined
$12.2 $23.8 
Retail refunds - return to customers to be determined
6.2 6.2 
Rate case settlement relate back - amortized over a six-month period beginning January 2024 (Note 2 - Retail Rate Proceedings)
— 10.3 
Other 0.3 2.7 
Entergy Texas Total$18.7 $43.0 

System Energy
 20242023
 (In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)
$702.8 $560.6 
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and the FERC
44.4 44.4 
Complaints against System Energy - potential future refunds (Note 2)
— 177.9 
System Energy Total$747.2 $782.9 

(a)Offset by related asset.
(b)Includes $1.6 million at Entergy, $1.2 million at Entergy Louisiana, and $0.4 million at Entergy New Orleans as of December 31, 2024 of regulatory liabilities related to the respective natural gas distribution businesses classified as held for sale and included within other non-current liabilities on the respective consolidated balance sheets. See Note 14 to the financial statements for further discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses and the classification as held for sale.
Regulatory activity regarding the Tax Cuts and Jobs Act

See the “Other Tax Matters - Tax Cuts and Jobs Act” section in Note 3 to the financial statements for discussion of the effects of the December 2017 enactment of the Tax Cuts and Jobs Act (Tax Act), including its effects on Entergy’s and the Registrant Subsidiaries’ regulatory asset/liability for income taxes.

Entergy Louisiana

In an electric formula rate plan settlement approved by the LPSC in April 2018, the parties agreed that Entergy Louisiana would return to customers one-half of its eligible unprotected excess deferred income taxes from May 2018 through December 2018 and return to customers the other half from January 2019 through August 2022. In addition, the settlement provided that in order to flow back to customers certain other tax benefits created by the Tax Act, Entergy Louisiana established a regulatory liability effective January 1, 2018 in the amount of $9.1 million per month to reflect these tax benefits already included in retail rates until new base rates under the formula rate plan were established in September 2018, and this regulatory liability was returned to customers over the September 2018 through August 2019 formula rate plan rate-effective period. The LPSC staff and intervenors in the settlement reserved the right to obtain data from Entergy Louisiana to confirm the determination of excess accumulated deferred income taxes resulting from the Tax Act and the analysis thereof as part of the formula rate plan review proceeding for the 2017 test year filing. As discussed below in “Retail Rate Proceedings - Filings with the LPSC (Entergy Louisiana) - Retail Rates - Electric - Formula Rate Plan Global Settlement”, a global settlement resolving the outstanding issues related to the 2017 formula rate plan filing was reached in October 2023 and approved by the LPSC in November 2023.

System Energy

In a filing made with the FERC in March 2018, System Energy proposed revisions to the Unit Power Sales Agreement to reflect the effects of the Tax Act. In the filing System Energy proposed to return identified quantities of unprotected excess accumulated deferred income taxes to its customers by the end of 2018. In May 2018 the FERC accepted System Energy’s proposed tax revisions with an effective date of June 1, 2018, subject to refund and the outcome of settlement and hearing procedures. Settlement discussions were terminated in April 2019, and a hearing was held in March 2020. In December 2022 the FERC issued an order requiring System Energy to compute the amount of excess accumulated deferred income taxes associated with a previously uncertain decommissioning tax position with consideration for the resolution of the tax position by the IRS. In February 2023, System Energy submitted its compliance filing. This matter was ultimately settled as a result of System Energy’s settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” below for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.
Fuel and purchased power cost recovery

The Utility operating companies are allowed to recover fuel and purchased power costs through fuel mechanisms included in electric and gas rates that are recorded as fuel cost recovery revenues.  The difference between revenues collected and the current fuel and purchased power costs is generally recorded as “Deferred fuel costs” on the Utility operating companies’ financial statements.  The table below shows the amount of deferred fuel costs as of December 31, 2024 and 2023 that each Utility operating company expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.

 20242023
 (In Millions)
Entergy Arkansas
($45.2)($88.3)
Entergy Louisiana (a) (b)$163.4 $192.9 
Entergy Mississippi($126.3)($130.6)
Entergy New Orleans (a) (b)$8.0 $10.2 
Entergy Texas($59.3)$139.0 

(a)Includes $168.1 million in both years for Entergy Louisiana and $4.1 million in both years for Entergy New Orleans of fuel, purchased power, and capacity costs, which do not currently earn a return on investment and whose recovery periods are indeterminate but are expected to be recovered over a period greater than twelve months.
(b)Includes $0.7 million at Entergy Louisiana and $4.9 million at Entergy New Orleans as of December 31, 2024 of deferred fuel assets related to the respective natural gas distribution businesses classified as held for sale and included within “Current assets held for sale” on the respective consolidated balance sheets. See Note 14 to the financial statements for further discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses and the classification as held for sale.

Entergy Arkansas

Energy Cost Recovery Rider

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

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

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

In March 2018, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01547 per kWh to $0.01882 per kWh. The Arkansas Attorney General filed a response to Entergy Arkansas’s annual redetermination filing requesting that the APSC suspend the proposed tariff to investigate the amount of the redetermination or, alternatively, to allow recovery subject to refund. Among the reasons the Attorney General cited for suspension were questions pertaining to how Entergy Arkansas forecasted sales and potential implications of the Tax Cuts and Jobs Act. Entergy Arkansas replied to the Attorney General’s filing and stated that, to the extent there are questions pertaining to its load forecasting or the operation of the energy cost recovery rider, those issues exceed the scope of the instant rate redetermination. Entergy Arkansas also stated that potential effects of the Tax Cuts and Jobs Act are appropriately considered in the APSC’s separate proceeding regarding potential implications of the tax law. The APSC general staff filed a reply to the Attorney General’s filing and agreed that Entergy Arkansas’s filing complied with the terms of the energy cost recovery rider. The redetermined rate became effective with the first billing cycle of April 2018. Subsequently in April 2018 the APSC issued an order declining to suspend Entergy Arkansas’s energy cost recovery rider rate and declining to require further investigation at that time of the issues suggested by the Attorney General in the proceeding. Following a period of discovery, the Attorney General filed a supplemental response in October 2018 raising new issues with Entergy Arkansas’s March 2018 rate redetermination and asserting that $45.7 million of the increase should be collected subject to refund pending further investigation. Entergy Arkansas filed to dismiss the Attorney General’s supplemental response, the APSC general staff filed a motion to strike the Attorney General’s filing, and the Attorney General filed a supplemental response disputing Entergy Arkansas and the APSC staff’s filing. Applicable APSC rules and processes authorize its general staff to initiate periodic audits of Entergy Arkansas’s energy cost recovery rider. In late-2018 the APSC general staff notified Entergy Arkansas it initiated an audit of the 2017 fuel costs. The time in which the audit will be complete is uncertain at this time.

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

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

In March 2024, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease in the rate from $0.01883 per kWh to $0.00882 per kWh. Due to a change in law in the State of Arkansas, the annual redetermination included $9 million, recorded as a credit to fuel expense in first quarter 2024, for recovery attributed to net metering costs in 2023. The primary reason for the rate decrease is a large over-recovered balance as a result of lower natural gas prices in 2023. To mitigate the effect of projected increases in natural gas prices in 2024, Entergy Arkansas adjusted the over-recovered balance included in the March 2024 annual redetermination filing by $43.7 million. This adjustment is expected to reduce the rate change that will be reflected in the 2025 energy cost rate redetermination. The redetermined rate of $0.00882 per kWh became effective with the first billing cycle in April 2024 through the normal operation of the tariff.

Entergy Louisiana

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

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

In March 2020 the LPSC staff provided notice of an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2016 through 2019. The LPSC staff issued its audit report in September 2021, and although certain internal record keeping recommendations were made, the LPSC staff did not recommend any disallowances. The next step is for the LPSC to review the report, but there is not a deadline for the review.

In January 2023 the LPSC staff provided notice of an audit of Entergy Louisiana’s purchased gas adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s purchased gas adjustment clause for the period from 2021 through 2022. Discovery is ongoing, and no audit report has been filed.
In January 2023 the LPSC staff provided notice of an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2020 through 2022. Discovery is ongoing, and no audit report has been filed.

Entergy Mississippi

Entergy Mississippi’s rate schedules include an energy cost recovery rider and a power management rider, both of which are adjusted annually to reflect accumulated over- or under-recoveries. Entergy Mississippi recovers fuel and purchased energy costs through its energy cost recovery rider and recovers costs associated with natural gas hedging and capacity payments through its power management rider. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.

In November 2021, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an under-recovery of approximately $80.6 million as of September 30, 2021. In December 2021, at the request of the MPSC, Entergy Mississippi submitted a proposal to mitigate the impact of rising fuel costs on customer bills during 2022. Entergy Mississippi proposed that the deferred fuel balance as of December 31, 2021, which was $121.9 million, be amortized over three years and that the MPSC authorize Entergy Mississippi to apply its weighted-average cost of capital as the carrying cost for the unamortized fuel balance. In January 2022 the MPSC approved the amortization of $100 million of the deferred fuel balance over two years and authorized Entergy Mississippi to apply its weighted-average cost of capital as the carrying cost for the unamortized fuel balance. The MPSC approved the proposed energy cost factor effective for February 2022 bills.

See “Complaints Against System Energy - System Energy Settlement with the MPSC” below for discussion of the settlement agreement filed with the FERC in June 2022. The settlement, which was approved by the FERC in November 2022, provided for a refund of $235 million from System Energy to Entergy Mississippi. In July 2022 the MPSC directed the disbursement of settlement proceeds, ordering Entergy Mississippi to provide a one-time $80 bill credit to each of its approximately 460,000 retail customers to be effective during the September 2022 billing cycle and to apply the remaining proceeds to Entergy Mississippi’s under-recovered deferred fuel balance. In accordance with the MPSC’s directive, Entergy Mississippi provided approximately $36.7 million in customer bill credits as a result of the settlement. In November 2022, Entergy Mississippi applied the remaining settlement proceeds in the amount of approximately $198.3 million to Entergy Mississippi’s under-recovered deferred fuel balance.

Entergy Mississippi had a deferred fuel balance of approximately $291.7 million under the energy cost recovery rider as of July 31, 2022, along with an over-recovery balance of $51.1 million under the power management rider. Without further action, Entergy Mississippi anticipated a year-end deferred fuel balance of approximately $200 million after application of a portion of the System Energy settlement proceeds, as discussed above. In September 2022, Entergy Mississippi filed for interim adjustments under both the energy cost recovery rider and the power management rider. Entergy Mississippi proposed five monthly incremental adjustments to the net energy cost factor designed to collect the under-recovered fuel balance as of July 31, 2022 and to reflect the recovery of a higher natural gas price. Entergy Mississippi also proposed five monthly incremental adjustments to the power management adjustment factor designed to flow through to customers the over-recovered power management rider balance as of July 31, 2022. In October 2022 the MPSC approved modified interim adjustments to Entergy Mississippi’s energy cost recovery rider and power management rider. The MPSC approved dividing the energy cost recovery rider interim adjustment into two components that would allow Entergy Mississippi to (1) recover a natural gas fuel rate that is better aligned with current prices; and (2) recover the estimated under-recovered deferred fuel balance as of September 30, 2022 over a period of 20 months. The MPSC approved six monthly incremental adjustments to the net energy cost factor designed to reflect the recovery of a higher natural gas price. The MPSC also approved six monthly incremental adjustments to the power management adjustment factor designed to flow through to customers the over-recovered power management rider balance. In accordance
with the order of the MPSC, Entergy Mississippi did not file an annual redetermination of the energy cost recovery rider or the power management rider in November 2022.

In June 2023 the MPSC approved the joint stipulation agreement between Entergy Mississippi and the Mississippi Public Utilities Staff for Entergy Mississippi’s 2023 formula rate plan filing. The stipulation directed Entergy Mississippi to make a compliance filing to revise its power management cost adjustment factor, to revise its grid modernization cost adjustment factor, and to include a revision to reduce the net energy cost factor to a level necessary to reflect an average natural gas price of $4.50 per MMBtu. The MPSC approved the compliance filing in June 2023, effective for July 2023 bills. See “Retail Rate Proceedings - Filings with the MPSC (Entergy Mississippi) - Retail Rates - 2023 Formula Rate Plan Filing” below for further discussion of the 2023 formula rate plan filing and the joint stipulation agreement.

In November 2023 Entergy Mississippi filed its annual redeterminations of the energy cost factor and the power management cost adjustment factor. The calculation of the annual factor for the energy cost recovery rider included a projected over-recovery balance of approximately $142 million at the end of January 2024. The calculation of the annual factor for the power management rider included a projected under-recovery of $47 million at the end of January 2024. In January 2024 the MPSC approved the proposed energy cost factor and the proposed power management cost factor effective for February 2024 bills.

In June 2024 the MPSC approved the joint stipulation agreement between Entergy Mississippi and the Mississippi Public Utilities Staff for Entergy Mississippi’s 2024 formula rate plan filing. The 2024 formula rate plan filing included the conclusion of the modified interim adjustments to Entergy Mississippi’s energy cost recovery rider and power management rider, which were approved in October 2022 and allowed Entergy Mississippi to recover certain under-collected fuel balances, effective for July 2024 bills. The stipulation provided for Entergy Mississippi to reduce its net energy cost factor. See “Retail Rate Proceedings - Filings with the MPSC (Entergy Mississippi) - Retail Rates - 2024 Formula Rate Plan Filing” below for further discussion of the 2024 formula rate plan filing and the joint stipulation agreement.

In November 2024, Entergy Mississippi filed its annual redeterminations of the energy cost factor and the power management cost adjustment factor. The calculation of the annual factor for the energy cost recovery rider included a projected over-recovery balance of approximately $144.6 million as of September 2024. The calculation of the annual factor for the power management rider included a projected under-recovery of $60.1 million as of September 2024. In January 2025 the MPSC approved a revised energy cost factor, effective for February 2025 bills, that did not reflect the fuel savings associated with Entergy Mississippi’s incremental increase in its share of capacity and energy in connection with Entergy Mississippi’s assumption of Entergy Louisiana’s entitlements to Grand Gulf capacity and energy, which was subject to the MPSC’s review at such time. In February 2025 the MPSC approved Entergy Mississippi’s notice of intent for Entergy Mississippi’s assumption of Entergy Louisiana’s entitlements to Grand Gulf capacity and energy, with associated fuel savings to be reflected in Entergy Mississippi’s energy cost recovery rider, effective for March 2025 bills. Additionally, in February 2025 the MPSC approved the proposed power management cost adjustment factor, effective for March 2025 bills.

Entergy New Orleans

Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.

Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.
Entergy Texas

Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, not recovered in base rates.  Historically, semi-annual revisions of the fixed fuel factor have been made in March and September based on the market price of natural gas and changes in fuel mix.  The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. In 2023 the Texas legislature modified the Texas Utilities Code to provide that material over- and under-recovered fuel balances are to be refunded or surcharged through interim fuel adjustments and that fuel reconciliations must be filed at least once every two years. Entergy Texas expects the PUCT to undertake a rulemaking to effectuate the new legislation in 2025.

In May 2022, Entergy Texas filed an application with the PUCT to implement an interim fuel surcharge to collect the cumulative under-recovery of approximately $51.7 million, including interest, of fuel and purchased power costs incurred from May 1, 2020 through December 31, 2021. The under-recovery balance was primarily attributable to the impacts of Winter Storm Uri, including historically high natural gas prices, partially offset by settlements received by Entergy Texas from MISO related to Hurricane Laura. Entergy Texas proposed that the interim fuel surcharge be assessed over a period of six months beginning with the first billing cycle after the PUCT issues a final order, but no later than the first billing cycle of September 2022. Also in May 2022, the PUCT referred the proceeding to the State Office of Administrative Hearings. In July 2022, Entergy Texas filed on behalf of the parties an unopposed settlement resolving all issues in the proceeding. In addition, Entergy Texas filed on behalf of the parties a motion to admit evidence, to approve interim rates as requested in the initial application, and to remand the proceeding to the PUCT to consider the unopposed settlement. In August 2022 the ALJ with the State Office of Administrative Hearings issued an order granting Entergy Texas’s motion, approving interim rates effective with the first billing cycle of September 2022, and remanding the case to the PUCT for final approval. The interim fuel surcharge was approved by the PUCT in January 2023.

In September 2022, Entergy Texas filed an application with the PUCT to reconcile its fuel and purchased power costs for the period from April 2019 through March 2022. During the reconciliation period, Entergy Texas incurred approximately $1.7 billion in eligible fuel and purchased power expenses, net of certain revenues credited to such expenses and other adjustments. As of the end of the reconciliation period, Entergy Texas’s cumulative under-recovery balance was approximately $103.1 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning April 2022, pending future surcharges or refunds as approved by the PUCT. In November 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In July 2023, Entergy Texas filed an unopposed settlement, supporting testimony, and an agreed motion to admit evidence and remand the proceeding to the PUCT. Pursuant to the unopposed settlement, Entergy Texas would receive no disallowance of fuel costs incurred over the three-year reconciliation period and retain $9.3 million in margins from off-system sales made during the reconciliation period, resulting in a cumulative under-recovery balance of approximately $99.7 million, including interest, as of the end of the reconciliation period. In July 2023 the ALJ with the State Office of Administrative Hearings granted the motion to admit evidence and remanded the proceeding to the PUCT for consideration of the unopposed settlement. The PUCT approved the settlement in September 2023.

In September 2024, Entergy Texas filed an application with the PUCT to reconcile its fuel and purchased power costs for the period from April 2022 through March 2024. During the reconciliation period, Entergy Texas incurred approximately $1.6 billion in eligible fuel and purchased power expenses to generate and purchase electricity to serve its customers, net of certain revenues credited to such expenses and other adjustments. Entergy Texas’s cumulative under-recovery balance for the reconciliation period was approximately $30 million, including interest, which Entergy Texas requested authority to carry over as part of the cumulative fuel balance for the subsequent reconciliation period beginning April 2024. In November 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 procedural schedule, with a hearing on the merits scheduled for May 2025. A PUCT decision is expected in third quarter 2025.
In December 2024, Entergy Texas filed an application with the PUCT to implement an interim fuel refund of $45.5 million, including interest. Entergy Texas proposed that the interim fuel refund be implemented over a three-month period beginning with the first billing cycle in February 2025 for residential and other small customers and through a one-time credit, or surcharge depending on historical usage for the respective customer, for certain transmission voltage level and seasonal agricultural customers in February 2025. Also in December 2024 the PUCT referred the proceeding to the State Office of Administrative Hearings. In January 2025 the ALJ with the State Office of Administrative Hearings issued an order approving the interim fuel refund consistent with Entergy Texas’s application and, because no hearing was requested in the proceeding, dismissing the case from the State Office of Administrative Hearings and the PUCT.
Retail Rate Proceedings

Filings with the APSC (Entergy Arkansas)

Retail Rates

2022 Formula Rate Plan Filing

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

2023 Formula Rate Plan Filing

In July 2023, Entergy Arkansas filed with the APSC its 2023 formula rate plan filing to set its formula rate for the 2024 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2024 and a netting adjustment for the historical year 2022. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2024 projected year was 8.11% resulting in a revenue deficiency of $80.5 million. The earned rate of return on common equity for the 2022 historical year was 7.29% resulting in a $49.8 million netting adjustment. The total proposed revenue change for the 2024 projected year and 2022 historical year netting adjustment was $130.3 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $88.6 million. The APSC general staff and intervenors filed their errors and objections in October 2023, proposing certain adjustments, including the APSC general staff’s update to annual filing year revenues which lowers the constraint to $87.7 million. Entergy Arkansas filed its rebuttal in October 2023. In October 2023, Entergy
Arkansas filed with the APSC a settlement agreement reached with other parties resolving all issues in the proceeding, none of which affected Entergy Arkansas’s requested recovery up to the constraint of $87.7 million. The settlement agreement provided for amortization of the approximately $39 million regulatory asset for costs associated with the COVID-19 pandemic over a 10-year period as well as recovery of $34.9 million related to the resolution of the 2016 and 2017 IRS audits from previous tax positions that are no longer uncertain, partially offset by $24.7 million in excess accumulated deferred income taxes from reductions in state income tax rates, each before consideration of their respective tax gross-up. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit and the State of Arkansas corporate income tax rate changes. In December 2023 the APSC approved the settlement agreement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2024.

2024 Formula Rate Plan Filing

In July 2024, Entergy Arkansas filed with the APSC its 2024 formula rate plan filing to set its formula rate for the 2025 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the 2025 projected year and a netting adjustment for the 2023 historical year. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2025 projected year was 8.43% resulting in a revenue deficiency of $69.5 million. The earned rate of return on common equity for the 2023 historical year was 7.48% resulting in a $33.1 million netting adjustment. The total proposed revenue change for the 2025 projected year and 2023 historical year netting adjustment is $102.6 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $82.6 million. The APSC general staff and intervenors filed their errors and objections in October 2024, proposing certain adjustments, including the APSC general staff’s update to annual filing year revenues that increases the constraint to $83.5 million. Entergy Arkansas filed its rebuttal in October 2024, and later in October 2024 the parties submitted a joint issues list and stipulations setting forth the disputed issues and the noncontested issues. In December 2024 the APSC approved the parties’ stipulations without modification, approved Entergy Arkansas’s adjustment with respect to storm costs, directed Entergy Arkansas to adjust its projected year distribution reliability capital closings, and deferred the recoverability of Entergy Arkansas’s opportunity sales legal fees until the next general rate case. Also in December 2024 the APSC approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2025. As a result of the proceeding, the total revenue change was $82.7 million, including a $63.7 million increase for the 2025 projected year and a $31.4 million netting adjustment for the 2023 historical year. In fourth quarter 2024, Entergy Arkansas recorded a regulatory asset of $15.5 million to reflect the amount of the 2023 historical year netting adjustment that it expects to collect from its customers during the 2025 rate effective period. Pursuant to the terms of the parties’ stipulations, Entergy Arkansas made a filing with the APSC in January 2025 to refund customers $30.1 million in excess accumulated deferred income taxes resulting from the reduction in the State of Arkansas’s income tax rate from 4.8% to 4.3% in 2024. Entergy Arkansas will make this refund over a 24-month period effective with the first billing cycle of February 2025.

Grand Gulf Credit Rider

In June 2024, Entergy Arkansas filed with the APSC a tariff to provide retail customers a credit resulting from the terms of the settlement agreement between Entergy Arkansas, System Energy, additional named Entergy parties, and the APSC pertaining to System Energy’s billings for wholesale sales of energy and capacity from the Grand Gulf nuclear plant. See “Complaints Against System Energy - System Energy Settlement with the APSC” below for discussion of the settlement. In July 2024 the APSC approved the tariff, under which Entergy Arkansas will refund to retail customers a total of $100.6 million. To date, Entergy Arkansas has refunded $92.3 million of the total through one-time bill credits during the August 2024 billing cycle and is finalizing plans for the refund of the remaining regulatory liability balance.
Filings with the LPSC (Entergy Louisiana)

Retail Rates - Electric

2020 Formula Rate Plan Filing

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

In November 2023 the LPSC approved a global settlement which resolved all outstanding issues related to the 2017, 2018, and 2019 formula rate plan filings and resolved certain issues with respect to the 2020 and 2021 formula rate plan filings. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” below for further discussion.

2021 Formula Rate Plan Filing

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

In November 2023 the LPSC approved a global settlement which resolved all outstanding issues related to the 2017, 2018, and 2019 formula rate plan filings and resolved certain issues with respect to the 2020 and 2021
formula rate plan filings. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” below for further discussion.

2022 Formula Rate Plan Filing

In May 2023, Entergy Louisiana filed its formula rate plan evaluation report for its 2022 calendar year operations. The 2022 test year evaluation report produced an earned return on common equity of 8.33%, requiring an approximately $70.7 million increase to base rider revenue. Due to a cap for the 2021 and 2022 test years, however, base rider formula rate plan revenues were only increased by approximately $4.9 million, resulting in a revenue deficiency of approximately $65.9 million and providing for prospective return on common equity opportunity of approximately 8.38%. Other changes in formula rate plan revenue driven by increases in capacity costs, primarily legacy capacity costs, additions eligible for recovery through the transmission recovery mechanism and distribution recovery mechanism, and higher sales during the test period were offset by reductions in net MISO costs as well as credits for FERC-ordered refunds. Also included in the 2022 test year distribution recovery mechanism revenue requirement was a $6 million credit relating to the distribution recovery mechanism performance accountability standards and requirements. In total, the net increase in formula rate plan revenues, including base formula rate plan revenues inside the formula rate plan bandwidth and subject to the cap, as well as other formula rate plan revenues outside of the bandwidth, was $85.2 million. In August 2023 the LPSC staff filed a list of objections/reservations, including outstanding issues from the test years 2017-2021 formula rate plan filings, the calculation of certain refunds from System Energy, and certain calculations relating to the tax reform adjustment mechanism. Subject to LPSC review, the resulting net increase in formula rate plan revenues of $85.2 million became effective for bills rendered during the first billing cycle of September 2023, subject to refund. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” below for further discussion.

2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request

In August 2023, Entergy Louisiana filed an application for approval of a regulatory blueprint necessary for it to strengthen the electric grid for the State of Louisiana, which contained a dual-path request to update rates through either: (1) extension of Entergy Louisiana’s current formula rate plan (with certain modifications) for three years (the Rate Mitigation Proposal), which is Entergy Louisiana’s recommended path; or (2) implementation of rates resulting from a cost-of-service study (the Rate Case path). The application complied with Entergy Louisiana’s previous formula rate plan extension order requiring that for Entergy Louisiana to obtain another extension of its formula rate plan that included a rate reset, Entergy Louisiana would need to submit a full cost-of-service rate case. Entergy Louisiana’s filing supported the need to extend Entergy Louisiana’s formula rate plan with credit supportive mechanisms needed to facilitate investment in the distribution, transmission, and generation functions.

In July 2024, Entergy Louisiana reached an agreement in principle with the LPSC staff and the intervenors in the proceeding and filed with the LPSC a joint motion to suspend the procedural schedule to allow for all parties to finalize a stipulated settlement agreement.

In August 2024, Entergy Louisiana and the LPSC staff jointly filed a global stipulated settlement agreement for consideration by the LPSC with key terms as follows:

•continuation of the formula rate plan for 2024-2026 (test years 2023-2025);
•a base formula rate plan revenue increase of $120 million for test year 2023, effective for rates beginning September 2024;
•a $140 million cumulative cap on base formula rate plan revenue increases, if needed, for test years 2024 and 2025, excluding outside the bandwidth items;
•$184 million of customer rate credits to be given over two years, including increasing customer sharing of income tax benefits resulting from the 2016-2018 IRS audit, to resolve any remaining disputed issues stemming from formula rate plan test years prior to test year 2023, including but not limited to the investigation into Entergy Services costs billed to Entergy Louisiana. As discussed in Note 3 to the financial statements, a $38 million regulatory liability was recorded in 2023 in connection with the 2016-2018 IRS audit;
•$75.5 million of customer rate credits, as provided for in the System Energy global settlement, to be credited over three years subject to and conditioned upon FERC approval of the System Energy global settlement, which was approved in November 2024. See “Complaints Against System Energy – System Energy Settlement with the LPSC” below for further details of the System Energy global settlement;
•$5.8 million of customer rate credits provided for in the Entergy Louisiana formula rate plan global settlement agreement approved by the LPSC in November 2023 credited over one year. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement;
•an increase in the allowed midpoint return on common equity from 9.5% to 9.7%, with a bandwidth of 40 basis points above and below the midpoint, for the extended term of the formula rate plan, except that for test year 2023 in which the authorized return on common equity shall have no bearing on the change in base formula rate plan revenue described above and, for test year 2024, any earnings above the authorized return on common equity shall be returned to customers through a credit;
•an increase in nuclear depreciation rates by $15 million in each of the 2023, 2024, and 2025 test years outside of the formula rate plan bandwidth calculation; and
•for the transmission recovery mechanism and the distribution recovery mechanism, no change to the existing floors, but the caps for both would be $350 million for test year 2023, $375 million for test year 2024, and $400 million for test year 2025. Transmission projects filed with the LPSC will be exempt from the transmission recovery mechanism cap.

The global stipulated settlement agreement was unanimously approved by the LPSC in August 2024 and an order was issued by the LPSC in September 2024 reflecting the approval of the settlement.

Based on the July 2024 agreement in principle, in second quarter 2024 Entergy Louisiana recorded expenses of $151 million ($112 million net-of-tax) primarily consisting of regulatory charges to reflect the effects of the agreement in principle.

Formula Rate Plan Global Settlement

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

2023 Formula Rate Plan Filing

In August 2024, pursuant to the global stipulated settlement agreement, Entergy Louisiana filed its formula rate plan evaluation report for its 2023 calendar year operations. Consistent with the global stipulated settlement agreement, the filing reflected a 9.7% allowed return on common equity with a bandwidth of 40 basis points above and below the midpoint. For the 2023 test year, however, the bandwidth provisions of the formula rate plan were
temporarily suspended and, pursuant to the terms of the global stipulated settlement agreement, Entergy Louisiana implemented the September 2024 formula rate plan rate adjustments effective with the first billing cycle of September 2024. Those adjustments included a $120 million increase in base rider formula rate plan revenue and a $101.8 million one-time incremental net decrease consistent with the terms of the global stipulated settlement. The formula rate plan rate adjustments reflected in the evaluation report also include a redetermination of the transmission recovery mechanism, the distribution recovery mechanism, the additional capacity mechanism, the tax adjustment mechanism, the MISO cost recovery mechanism, and other one-time adjustments. In January 2025, Entergy Louisiana and the LPSC filed a joint report indicating that no disputed issues remained in the proceeding and requesting that the LPSC issue an order accepting Entergy Louisiana’s evaluation report and, ultimately, resolving this matter. Entergy Louisiana expects a decision on the joint report in first quarter 2025.

Investigation of Costs Billed by Entergy Services

In November 2018 the LPSC issued a notice of proceeding initiating an investigation into costs incurred by Entergy Services that are included in the retail rates of Entergy Louisiana. As stated in the notice of proceeding, the LPSC observed an increase in capital construction-related costs incurred by Entergy Services. Discovery was issued and included efforts to seek highly detailed information on a broad range of matters unrelated to the scope of the audit. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” above for further discussion.

COVID-19 Orders

In April 2020 the LPSC issued an order authorizing utilities to record as a regulatory asset expenses incurred from the suspension of disconnections and collection of late fees imposed by LPSC orders associated with the COVID-19 pandemic. In April 2023, Entergy Louisiana filed an application proposing to utilize approximately $1.6 billion in certain low interest debt to generate earnings to apply toward the reduction of the COVID-19 regulatory asset, as well as to conduct additional outside right-of-way vegetation management activities and fund the minor storm reserve account. In that filing, Entergy Louisiana proposed to delay repayment of certain shorter-term first mortgage bonds that were issued to finance storm restoration costs until the costs could be securitized, and to invest the funds that otherwise would be used to repay those bonds in the money pool to take advantage of the spread between prevailing interest rates on investments in the money pool and the interest rates on the bonds. The LPSC approved Entergy Louisiana’s requested relief in June 2023. In November 2024, Entergy Louisiana submitted a filing to the LPSC requesting that the LPSC review Entergy Louisiana’s computation of the COVID-19 regulatory asset as well as Entergy Louisiana’s proposal to offset the regulatory asset against the interest earned on the short-term debt funds, resulting in no increased costs to customers. At the time of the filing, Entergy Louisiana had a regulatory asset of $47.8 million for costs associated with the COVID-19 pandemic. As of December 31, 2024, Entergy Louisiana had a regulatory liability of $48.9 million for the deferred earnings related to the approximately $1.6 billion in low interest debt, which had been fully repaid by August 2024. In granting Entergy Louisiana’s requested relief in June 2023, the LPSC ordered that any amount of earnings exceeding the amount of the COVID-19 regulatory asset be transferred to Entergy Louisiana’s storm reserve escrow account.

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 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.

Filings with the MPSC (Entergy Mississippi)

Retail Rates

2022 Formula Rate Plan Filing

In March 2022, Entergy Mississippi submitted its formula rate plan 2022 test year filing and 2021 look-back filing showing Entergy Mississippi’s earned return for the historical 2021 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2022 calendar year to be below the formula rate plan bandwidth. The 2022 test year filing showed a $69 million rate increase was necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.70% return on rate base, within the formula rate plan bandwidth. The change in formula rate plan revenues, however, was capped at 4% of retail revenues, which equated to a revenue change of $48.6 million. The 2021 look-back filing compared actual 2021 results to the approved benchmark return on rate base and reflected the need for a $34.5 million interim increase in formula rate plan revenues. In fourth quarter 2021, Entergy Mississippi recorded a regulatory asset of $19 million to reflect the then-current estimate in connection with the look-back feature of the formula rate plan. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $24.3 million interim rate increase, reflecting a cap equal to 2% of 2021 retail revenues, effective in April 2022. With the implementation of the interim formula rate plan rates, Entergy Mississippi began recovery of the bad debt expense deferral resulting from the COVID-19 pandemic over a three-year period.

In June 2022, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed the 2022 test year filing that resulted in a total rate increase of $48.6 million. Pursuant to the joint stipulation, Entergy Mississippi’s 2021 look-back filing reflected an earned return on rate base of 5.99% in calendar year 2021, which was below the look-back bandwidth, resulting in a $34.3 million increase in the formula rate plan revenues on an interim basis through June 2023. In July 2022 the MPSC approved the joint stipulation with rates effective in August 2022. In July 2022, Entergy Mississippi recorded regulatory credits of $22.6 million to reflect the effects of the joint stipulation.
In July 2022 the MPSC directed Entergy Mississippi to flow $14.1 million of the power management rider over-recovery balance to customers beginning in August 2022 through December 2022 to mitigate the bill impact of the increase in formula rate plan revenues.

2023 Formula Rate Plan Filing

In March 2023, Entergy Mississippi submitted its formula rate plan 2023 test year filing and 2022 look-back filing showing Entergy Mississippi’s earned return on rate base for the historical 2022 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2023 calendar year to be below the formula rate plan bandwidth. The 2023 test year filing showed a $39.8 million rate increase was necessary to reset Entergy Mississippi’s earned return on rate base to the specified point of adjustment of 6.67%, within the formula rate plan bandwidth. The 2022 look-back filing compared actual 2022 results to the approved benchmark return on rate base and reflected the need for a $19.8 million temporary increase in formula rate plan revenues, including the refund of a $1.3 million over-recovery resulting from the demand-side management costs true-up for 2022. In fourth quarter 2022, Entergy Mississippi recorded a regulatory asset of $18.2 million in connection with the look-back feature of the formula rate plan to reflect that the 2022 estimated earned return was below the formula rate plan bandwidth. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $27.9 million interim rate increase, reflecting a cap equal to 2% of 2022 retail revenues, effective in April 2023.

In May 2023, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed a 2023 test year filing resulting in a total revenue increase of $26.5 million for 2023. Pursuant to the joint stipulation, Entergy Mississippi’s 2022 look-back filing reflected an earned return on rate base of 6.10% in calendar year 2022, which was below the look-back bandwidth, resulting in a $19.0 million increase in the formula rate plan revenues on an interim basis through June 2024. Entergy Mississippi recorded a regulatory credit of $0.8 million in June 2023 to reflect the increase in the look-back regulatory asset. In addition, certain long-term service agreement and conductor handling costs were authorized for realignment from the formula rate plan to the annual power management and grid modernization riders effective January 2023, resulting in regulatory credits recorded in June 2023 of $4.1 million and $4.3 million, respectively. Also, the amortization of Entergy Mississippi’s COVID-19 bad debt expense deferral was suspended for calendar year 2023, but resumed in July 2024. In June 2023 the MPSC approved the joint stipulation with rates effective in July 2023.

2024 Formula Rate Plan Filing

In March 2024, Entergy Mississippi submitted its formula rate plan 2024 test year filing and 2023 look-back filing showing Entergy Mississippi’s earned return on rate base for the historical 2023 calendar year to be within the formula rate plan bandwidth and projected earned return for the 2024 calendar year to be below the formula rate plan bandwidth. The 2024 test year filing showed a $63.4 million rate increase was necessary to reset Entergy Mississippi’s earned return on rate base to the specified point of adjustment of 7.10%, within the formula rate plan bandwidth. The 2023 look-back filing compared actual 2023 results to the approved benchmark return on rate base and reflected no change in formula rate plan revenues. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $32.6 million interim rate increase, reflecting a cap equal to 2% of 2023 retail revenues, effective April 2024.

In December 2014 the MPSC ordered Entergy Mississippi to file an updated depreciation study at least once every four years. Pursuant to this order and Entergy Mississippi’s filing cycle, Entergy Mississippi would have filed an updated depreciation report with its formula rate plan filing in 2023. However, in July 2022 the MPSC directed Entergy Mississippi to file its next depreciation study in connection with its 2024 formula rate plan filing notwithstanding the MPSC’s prior order. Accordingly, Entergy Mississippi filed a depreciation study in February 2024. The study showed a need for an increase in annual depreciation expense of $55.2 million. The calculated increase in annual depreciation expense was excluded from Entergy Mississippi’s 2024 formula rate plan revenue increase request because the MPSC had not yet approved the proposed depreciation rates.
In June 2024, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed the 2024 test year filing, with the exception of immaterial adjustments to certain operation and maintenance expenses. After performance adjustments, the formula rate plan reflected an earned return on rate base of 6.08% for calendar year 2024, which resulted in a total revenue increase of $64.6 million for 2024. The joint stipulation also recommended approval of a revised customer charge of $31.82 per month for residential customers and $53.10 per month for general service customers. Pursuant to the stipulation, Entergy Mississippi’s 2023 look-back filing reflected an earned return on rate base of 6.81%, resulting in an increase of $0.3 million in the formula rate plan revenues for 2023. Finally, the stipulation recommended approval of Entergy Mississippi’s proposed depreciation rates with those rates to be implemented upon request and approval at a later date. In June 2024 the MPSC approved the joint stipulation with rates effective in July 2024. The approval also included a reduction to the energy cost factor, resulting in a net bill decrease for a typical residential customer using 1,000 kWh per month. Also in June 2024, Entergy Mississippi recorded regulatory credits of $7.3 million to reflect the difference between interim rates placed in effect in April 2024 and the rates reflected in the joint stipulation.

In May 2024, Entergy Mississippi received approval from the MPSC for formula rate plan revisions that were necessary for Entergy Mississippi to comply with state legislation passed in January 2024. The legislation allows Entergy Mississippi to make interim rate adjustments 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 filed the first of its annual interim facilities rate adjustment reports in May 2024 to recover approximately $8.7 million of these costs over a six-month period with rates effective beginning in July 2024. Entergy Mississippi filed its second annual interim facilities rate adjustment report in December 2024 to recover approximately $46.7 million of these costs over a 12-month period with rates effective beginning in January 2025.

Grand Gulf Capacity Filing

In September 2024, Entergy Mississippi filed a notice of intent with the MPSC to implement revisions to its unit power cost recovery rider that would allow Entergy Mississippi to recover the first year of costs associated with the transfer of Entergy Louisiana’s entitlements to Grand Gulf capacity and energy, which consists of Energy Louisiana’s interest in and purchases of Grand Gulf capacity and energy under the revised rider schedule, effective by January 1, 2025. This notice filing related to the divestiture of Entergy Louisiana’s 14% share of Grand Gulf capacity and energy under the Unit Power Sales Agreement and 2.43% share of capacity and energy from Entergy Arkansas under the MSS-4 replacement tariff. This divestiture is being effectuated initially through Entergy Mississippi’s purchases from Entergy Louisiana pursuant to a PPA governed by the MSS-4 replacement tariff, a tariff governing the sales of energy and capacity among the Utility operating companies as described in the System Energy global settlement with the LPSC and Entergy Louisiana. The MSS-4 replacement PPA to effectuate this divestiture was approved by the FERC in November 2024. In February 2025 the MPSC approved Entergy Mississippi’s notice of intent, finding that it was just and reasonable for Entergy Mississippi to obtain Entergy Louisiana’s entitlements to Grand Gulf capacity and energy and that Entergy Mississippi should be allowed to recover the costs associated with the transfer of such entitlements to Grand Gulf capacity and energy, as described above. The MPSC approved the MSS-4 replacement PPA, effective as of January 1, 2025. See “Complaints Against System Energy – System Energy Settlement with the LPSC” below for further details of the System Energy global settlement with the LPSC and Note 8 to the financial statements for discussion of the Unit Power Sales Agreement.

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.

Filings with the City Council (Entergy New Orleans)

Retail Rates

2022 Formula Rate Plan Filing

In April 2022, Entergy New Orleans submitted to the City Council its formula rate plan 2021 test year filing. The 2021 test year evaluation report, subsequently updated in a July 2022 filing, produced an earned return on equity of 6.88% compared to the authorized return on equity of 9.35%. Entergy New Orleans sought approval of a $42.1 million rate increase based on the formula set by the City Council in the 2018 rate case. The formula resulted in an increase in authorized electric revenues of $34.1 million and an increase in authorized gas revenues of $3.3 million. Entergy New Orleans also sought to commence collecting $4.7 million in electric revenues that were previously approved by the City Council for collection through the formula rate plan. In July 2022 the City Council’s advisors issued a report seeking a reduction to Entergy New Orleans’s proposed increase of approximately $17.1 million in total for electric and gas revenues. Effective with the first billing cycle of September 2022, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council including adjustments filed in the City Council’s advisors’ report, per the approved process for formula rate plan implementation. The total formula rate plan increase implemented was $24.7 million, which includes an increase of $18.2 million in electric revenues, $4.7 million in previously approved electric revenues, and an increase of $1.8 million in gas revenues. Additionally, credits of $13.9 million funded by certain regulatory liabilities currently held by Entergy New Orleans for customers were issued over an eight-month period beginning September 2022.

2023 Formula Rate Plan Filing

In April 2023, Entergy New Orleans submitted to the City Council its formula rate plan 2022 test year filing. The 2022 test year evaluation report produced an electric earned return on equity of 7.34% and a gas earned return on equity of 3.52% compared to the authorized return on equity for each of 9.35%. Entergy New Orleans sought approval of a $25.6 million rate increase based on the formula set by the City Council in the 2018 rate case. The formula would result in an increase in authorized electric revenues of $17.4 million and an increase in authorized gas revenues of $8.2 million. Entergy New Orleans also sought to commence collecting $3.4 million in electric revenues that were previously approved by the City Council for collection through the formula rate plan. In July 2023, Entergy New Orleans filed a report to decrease its requested formula rate plan revenues by approximately $0.5 million to account for minor errors discovered after the filing. The City Council advisors issued a report seeking a reduction in the requested formula rate plan revenues of approximately $8.3 million, combined for electric and gas, due to alleged errors. The City Council advisors proposed additional rate mitigation in the amount of $12 million through offsets to the formula rate plan rate increase by certain regulatory liabilities. In September 2023 the City Council approved an agreement to settle the 2023 formula rate plan filing. Effective with the first billing cycle of September 2023, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council, per the approved process for formula rate plan implementation. The agreement provides for a total increase in electric revenues of $10.5 million and a total increase in gas revenues of
$6.9 million. The agreement also provides for a minor storm accrual of $0.5 million per year and the distribution of $8.9 million of currently held customer credits to implement the City Council advisors’ mitigation recommendations.

Request for Extension and Modification of Formula Rate Plan

In September 2023, Entergy New Orleans filed a motion seeking City Council approval of a three-year extension of Entergy New Orleans’s electric and gas formula rate plans. In October 2023 the City Council granted Entergy New Orleans’s request for an extension, subject to minor modifications which included a 55% equity ratio for rate setting purposes.

2024 Formula Rate Plan Filing

In April 2024, Entergy New Orleans submitted to the City Council its formula rate plan 2023 test year filing. Without the requested rate change in 2024, the 2023 test year evaluation report produced an electric earned return on equity of 8.66% and a gas earned return on equity of 5.87% compared to the authorized return on equity for each of 9.35%. Entergy New Orleans sought approval of a $12.6 million rate increase based on the formula set by the City Council in the 2018 rate case and approved again by the City Council in 2023. The formula would result in an increase in authorized electric revenues of $7.0 million and an increase in authorized gas revenues of $5.6 million. Following City Council review, the City Council’s advisors issued a report in July 2024 seeking a reduction in Entergy New Orleans’s requested formula rate plan revenues in an aggregate amount of approximately $1.6 million for electric and gas together due to alleged errors. Effective with the first billing cycle of September 2024, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council, per the approved process for formula rate plan implementation. The total formula rate plan increase implemented was $11.2 million, which includes an increase of $5.8 million in electric revenues and an increase of $5.4 million in gas revenues.

Filings with the PUCT and Texas Cities (Entergy Texas)

Retail Rates

2022 Base Rate Case

In July 2022, Entergy Texas filed a base rate case with the PUCT seeking a net increase in base rates of approximately $131.4 million. The base rate case was based on a 12-month test year ending December 31, 2021. Key drivers of the requested increase were changes in depreciation rates as the result of a depreciation study and an increase in the return on equity. In addition, Entergy Texas included capital additions placed into service for the period of January 1, 2018 through December 31, 2021, including those additions reflected in the then-effective distribution and transmission cost recovery factor riders and the generation cost recovery rider, all of which were reset to zero in June 2023 as a result of this proceeding. In July 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In October 2022 intervenors filed direct testimony challenging and supporting various aspects of Entergy Texas’s rate case application. The key issues addressed included the appropriate return on equity, generation plant deactivations, depreciation rates, and proposed tariffs related to electric vehicles. In November 2022 the PUCT staff filed direct testimony addressing a similar set of issues and recommending a reduction of $50.7 million to Entergy Texas’s overall cost of service associated with the requested net increase in base rates of approximately $131.4 million. Entergy Texas filed rebuttal testimony in November 2022.

In May 2023, Entergy Texas filed on behalf of the parties an unopposed settlement resolving all issues in the proceeding, except for issues related to electric vehicle charging infrastructure which were eventually severed to a separate proceeding and resolved in October 2024, and Entergy Texas filed an agreed motion for interim rates, subject to refund or surcharge to the extent that the interim rates differ from the final approved rates. The unopposed settlement reflected a net base rate increase to be effective and relate back to December 2022 of
$54 million, exclusive of, and incremental to, the costs being realigned from the distribution and transmission cost recovery factor riders and the generation cost recovery rider and $4.8 million of rate case expenses to be recovered through a rider over a period of 36 months. The net base rate increase of $54 million includes updated depreciation rates and a total annual revenue requirement of $14.5 million for the accrual of a self-insured storm reserve and the recovery of the regulatory assets for the pension and postretirement benefits expense deferral, costs associated with the COVID-19 pandemic, and retired non-advanced metering system electric meters. In May 2023 the ALJ with the State Office of Administrative Hearings granted the motion for interim rates, which became effective in June 2023. Additionally, the ALJ remanded the proceeding to the PUCT to consider the settlement. In August 2023 the PUCT issued an order approving the unopposed settlement. Concurrently, Entergy Texas recorded the reversal of $21.9 million of regulatory liabilities to reflect the recognition of certain receipts by Entergy Texas under affiliated PPAs that have been resolved.

Following the PUCT’s approval of the unopposed settlement in August 2023, Entergy Texas recorded a regulatory liability of $10.3 million, which reflected the net effects of higher depreciation and amortizations for the relate back period, partially offset by the relate back of base rate revenues that would have been collected had the approved rates been in effect for the period from December 2022 through June 2023, the date the new base rates were implemented on an interim basis. In October 2023, Entergy Texas filed a relate back surcharge rider to collect over six months beginning in January 2024 an additional approximately $24.6 million, which was the revenue requirement associated with the relate back of rates from December 2022 through June 2023, including carrying costs, as authorized by the PUCT’s August 2023 order. In November 2023, Entergy Texas filed an amended relate back surcharge rider to collect approximately $24.1 million based on a revised carrying cost rate. The amended relate back surcharge rider was approved by the PUCT in December 2023. The higher depreciation and amortizations for the relate back period were also recognized over the six months beginning in January 2024, resulting in no effect on net income from the collection of the relate back surcharge rider.

Distribution Cost Recovery Factor (DCRF) Rider

In June 2024, Entergy Texas filed with the PUCT a request to set a new DCRF rider. The new rider was designed to collect from Entergy Texas’s retail customers approximately $40.3 million annually based on its capital invested in distribution between January 1, 2022 and March 31, 2024. In September 2024 the PUCT approved the DCRF rider, consistent with Entergy Texas’s as-filed request, and rates became effective with the first billing cycle in October 2024.

In September 2024, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $48.9 million annually, or $8.6 million in incremental annual revenues beyond Entergy Texas’s then-effective DCRF rider based on its capital invested in distribution between April 1, 2024 and June 30, 2024. In December 2024, Entergy Texas filed an errata to revise its DCRF application for minor corrections, which decreased the requested annual revenue requirement to $48.5 million. The amended request represented an incremental increase of $8.2 million in annual revenues beyond Entergy Texas’s then-effective DCRF rider. Also in December 2024 the PUCT approved the DCRF rider, consistent with Entergy Texas’s filed errata, and rates became effective on December 20, 2024.

Transmission Cost Recovery Factor (TCRF) Rider

In December 2018, Entergy Texas filed with the PUCT a request to set a new TCRF rider. The new TCRF rider was designed to collect approximately $2.7 million annually from Entergy Texas’s retail customers based on its capital invested in transmission between January 1, 2018 and September 30, 2018. In April 2019 parties filed testimony proposing a load growth adjustment, which would fully offset Entergy Texas’s proposed TCRF revenue requirement. In July 2019 the PUCT granted Entergy Texas’s application as filed to begin recovery of the requested $2.7 million annual revenue requirement, rejecting opposing parties’ proposed adjustment; however, the PUCT found that the question of prudence of the actual investment costs should be determined in Entergy Texas’s next rate case similar to the procedure used for the costs recovered through the DCRF rider. In October 2019 the PUCT
issued an order on a motion for rehearing, clarifying and affirming its prior order granting Entergy Texas’s application as filed. Also in October 2019 a second motion for rehearing was filed, and Entergy Texas filed a response in opposition to the motion. The second motion for rehearing was overruled by operation of law. In December 2019, Texas Industrial Energy Consumers filed an appeal to the PUCT order in district court alleging that the PUCT erred in declining to apply a load growth adjustment.

In October 2021, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $66.1 million annually, or $15.1 million in incremental annual revenues beyond Entergy Texas’s then-effective TCRF rider based on its capital invested in transmission between September 1, 2020 and July 31, 2021 and changes in approved transmission charges. In January 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In February 2022 the parties filed an unopposed settlement recommending that Entergy Texas be allowed to collect its full requested TCRF revenue requirement with interim rates effective March 2022. In February 2022 the ALJ granted the motion for interim rates, admitted evidence, and remanded the case to the PUCT for consideration of a final order at a future open meeting. In June 2022 the PUCT issued an order approving the settlement.

In October 2024, Entergy Texas filed with the PUCT a request to amend its TCRF rider, which was previously reset to zero in June 2023 as a result of the 2022 base rate case. The proposed rider is designed to collect from Entergy Texas’s retail customers approximately $9.7 million annually based on its capital invested in transmission between January 1, 2022 and June 30, 2024 and changes in other transmission charges. In December 2024 the PUCT staff filed a recommendation that the PUCT approve Entergy Texas’s as-filed application. In February 2025 the PUCT staff issued a proposed order that, if approved by the PUCT, would approve Entergy Texas’s TCRF rider as filed.

Generation Cost Recovery Rider

In October 2020, Entergy Texas filed an application to establish a generation cost recovery rider to begin recovering a return of and on its generation capital investment in the Montgomery County Power Station. Entergy Texas filed an unopposed settlement agreement in December 2020, and the PUCT approved the generation cost recovery rider settlement rates on an interim basis in January 2021. In March 2021, Entergy Texas filed to update its generation cost recovery rider, and an unopposed settlement agreement filed by Entergy Texas on behalf of the parties in October 2021 was approved by the PUCT in January 2022. In February 2022, Entergy Texas filed a relate-back rider to collect over five months an additional approximately $5 million, which was the difference between the interim revenue requirement approved in January 2021 and the revenue requirement approved in January 2022 reflecting Entergy Texas’s full generation capital investment and ownership in Montgomery County Power Station on January 1, 2021, plus carrying costs from January 2021 through January 2022 when the updated revenue requirement took effect. The PUCT approved the relate-back rider consistent with Entergy Texas’s as-filed request, and rates became effective over a five-month period, in August 2022.

In December 2020, Entergy Texas also filed an application to amend its generation cost recovery rider to reflect its acquisition of the Hardin County Peaking Facility, which closed in June 2021. Because Hardin was to be acquired in the future, the initial generation cost recovery rider rates proposed in the application represented no change from the generation cost recovery rider rates established in Entergy Texas’s previous generation cost recovery rider proceeding. In July 2021 the PUCT issued an order approving the application. In August 2021, Entergy Texas filed an update application to recover its actual investment in the acquisition of the Hardin County Peaking Facility, and in January 2022, Entergy Texas filed an update to its application to align the requested revenue requirement with the terms of the generation cost recovery rider settlement approved by the PUCT in January 2022. In April 2022, Entergy Texas filed on behalf of the parties a unanimous settlement agreement that would adjust its generation cost recovery rider to recover an annual revenue requirement of approximately $92.8 million, which was $4.5 million in incremental annual revenue above the revenue requirement approved in January 2022 described above and related to Entergy Texas’s investment in the Montgomery County Power Station. The PUCT approved the settlement agreement and rates became effective in August 2022. In September 2022,
Entergy Texas filed a relate-back rider designed to collect over three months an additional approximately $5.7 million, which is the revenue requirement, plus carrying costs, associated with Entergy Texas’s acquisition of Hardin County Peaking Facility from June 2021 through August 2022 when the updated revenue requirement took effect. In April 2023 the PUCT approved Entergy Texas’s as-filed request with rates effective over three months beginning in May 2023.
Entergy Arkansas Opportunity Sales Proceeding

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

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

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

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

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

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

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

In October 2018 the FERC issued an order addressing the ALJ’s July 2017 initial decision. The FERC reversed the ALJ’s decision to cap the reduction in Entergy Arkansas’s payment to account for the increased bandwidth payments that Entergy Arkansas made to the other operating companies. The FERC also reversed the ALJ’s decision that Grand Gulf sales from January through September 2000 should be included in the calculation of Entergy Arkansas’s payment. The FERC affirmed on other grounds the ALJ’s rejection of the LPSC’s claim that certain joint account sales should be accounted for as part of the calculation of Entergy Arkansas’s payment. In November 2018 the LPSC requested rehearing of the FERC’s October 2018 decision. In December 2019 the FERC denied the LPSC’s request for rehearing. In January 2020 the LPSC appealed the December 2019 decision to the D.C. Circuit.
In December 2018, Entergy made a compliance filing in response to the FERC’s October 2018 order. The compliance filing provided a final calculation of Entergy Arkansas’s payments to the other Utility operating companies, including interest. No protests were filed in response to the December 2018 compliance filing. Refunds and interest in the following amounts were paid by Entergy Arkansas to the other operating companies in December 2018:
 Total refunds including interest
Payment/(Receipt)
 (In Millions)
PrincipalInterestTotal
Entergy Arkansas$68$67$135
Entergy Louisiana($30)($29)($59)
Entergy Mississippi($18)($18)($36)
Entergy New Orleans($3)($4)($7)
Entergy Texas($17)($16)($33)

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

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

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

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

In July 2020 the APSC issued a decision finding that Entergy Arkansas’s application is not in the public interest. The order also directed Entergy Arkansas to refund to its retail customers within 30 days of the order the FERC-determined over-collection of $13.7 million, plus interest, associated with a recalculated bandwidth remedy. In addition to these primary findings, the order also denied the Attorney General’s request for Entergy Arkansas to prepare a compliance filing detailing all of the retail impacts from the opportunity sales and denied a request by the Arkansas Electric Energy Consumers to recalculate all costs using the revised responsibility ratio. Entergy Arkansas filed a motion for temporary stay of the 30-day requirement to allow Entergy Arkansas a reasonable opportunity to seek rehearing of the APSC order, but in July 2020 the APSC denied Entergy Arkansas’s request for a stay and directed Entergy Arkansas to refund to its retail customers the component of the total FERC-determined opportunity sales payment that was associated with increased bandwidth remedy payments of $13.7 million, plus interest. The refunds were issued in the August 2020 billing cycle. While the APSC denied Entergy Arkansas’s stay request, Entergy Arkansas believes its actions were prudent and, therefore, the costs, including the $13.7 million, plus interest, are recoverable. In July 2020, Entergy Arkansas requested rehearing of the APSC order, which rehearing was denied by the APSC in August 2020. In September 2020, Entergy Arkansas filed a complaint in the U.S. District Court for the Eastern District of Arkansas challenging the APSC’s order denying Entergy Arkansas’s request to recover the costs of these payments. In October 2020 the APSC filed a motion to dismiss Entergy Arkansas’s complaint, to which Entergy Arkansas responded. Also in December 2020, Entergy Arkansas and the APSC held a pre-trial conference, and filed a report with the court in January 2021. The court held a hearing in February 2021 regarding issues addressed in the pre-trial conference report, and in June 2021 the court stayed all discovery until it rules on pending motions, after which the court will issue an amended schedule if necessary. In March 2022 the court denied the APSC’s motion to dismiss, and, in April 2022, issued a scheduling order including a trial date in February 2023. In June 2022, Entergy Arkansas filed a motion asserting that it is entitled to summary judgment because Entergy Arkansas’s position that the APSC’s order is pre-empted by the filed rate doctrine and violates the Dormant Commerce Clause is premised on facts that are not subject to genuine dispute. In July 2022, Arkansas Electric Energy Consumers, Inc., an industrial customer association, filed a motion to intervene and to hold Entergy Arkansas’s motion for summary judgment in abeyance pending a ruling on the motion to intervene. Entergy Arkansas filed a consolidated opposition to both motions. In August 2022 the APSC filed a motion for summary judgment arguing that there is no genuine issue as to any material fact and the APSC is entitled to judgment as a matter of law. In September 2022, Entergy Arkansas filed an opposition to the motion. In October 2022 the APSC filed a motion asking the court to hold further proceedings in abeyance pending a decision on the motions for summary judgment filed by Entergy Arkansas and the APSC. Also in October 2022, Entergy Arkansas filed an opposition to the motion, and the APSC filed a reply in support of its motion for summary judgment. In January 2023 the judge assigned to the case, on her own motion, identified facts that may present a conflict and recused herself; a new judge was assigned to the case, but he also recused due to a conflict. The case again was reassigned to a new judge. In January 2023 the court denied all pending motions (including those described above) except for a motion by the APSC to exclude certain testimony and further ruled that the matter would proceed to trial. In January 2023, Arkansas Electric Energy Consumers, Inc. filed a notice of appeal of the court’s order denying its motion to intervene to the United States Court of Appeals for the Eighth Circuit and a motion with the district court to stay the proceedings pending the appeal, which was denied. In February 2023, Arkansas Electric Energy Consumers, Inc. filed a motion with the United States Court of Appeals for the Eighth Circuit to stay the proceedings pending the appeal, which also was denied. The trial was held in February 2023. Following the trial, Entergy Arkansas filed a motion with the United States Court of Appeals for the Eighth Circuit to expedite the appeal filed by Arkansas Electric Energy Consumers, Inc. The United States Court of Appeals for
the Eighth Circuit granted Entergy Arkansas’s request, and oral arguments were held in June 2023. In August 2023 the United States Court of Appeals for the Eighth Circuit affirmed the order of the court denying Arkansas Electric Energy Consumers, Inc.’s motion to intervene.

In March 2024 the U.S. District Court for the Eastern District of Arkansas issued a judgment in favor of the APSC and against Entergy Arkansas. In March 2024 Entergy Arkansas filed a notice of appeal and a motion to expedite oral arguments with the United States Court of Appeals for the Eighth Circuit and the court granted the motion to expedite. Briefing to the United States Court of Appeals for the Eighth Circuit concluded in July 2024 and oral arguments concluded in September 2024. As a result of the adverse decision by the U.S. District Court for the Eastern District of Arkansas, Entergy Arkansas concluded that it could no longer support the recognition of its $131.8 million regulatory asset reflecting the previously-expected recovery of a portion of the costs at issue in the opportunity sales proceeding and recorded a $131.8 million ($99.1 million net-of-tax) charge to earnings in first quarter 2024. In December 2024 the United States Court of Appeals for the Eighth Circuit affirmed the decision of the U.S. District Court for the Eastern District of Arkansas, and Entergy Arkansas filed a petition for rehearing en banc. In January 2025 the United States Court of Appeals for the Eighth Circuit denied Entergy Arkansas’s petition. Entergy Arkansas is evaluating a petition for certiorari with the United States Supreme Court.
MSS-4 Replacement Tariff – Net Operating Loss Carryforward Proceeding

In January 2021, pursuant to section 205 of the Federal Power Act, Entergy Services filed an amendment to the MSS-4 replacement tariff, a tariff governing the sales of energy and capacity among the Utility operating companies, in order to provide for the inclusion of specified accumulated deferred income taxes, including net operating loss carryforward accumulated deferred income taxes (NOLC ADIT), in the rate for sales of energy among the Utility operating companies on a prospective basis. In March 2021, the FERC accepted the filing, subject to refund and hearing procedures.

In October 2021 the LPSC filed a complaint with the FERC alleging that Entergy Services improperly excluded NOLC ADIT from MSS-4 replacement tariff rates in the period before March 20, 2021. The LPSC argued that sales from Entergy Louisiana to Entergy Texas and Entergy New Orleans were charged at rates lower than they otherwise should have been, and it accordingly seeks surcharges for the period prior to March 20, 2021. The FERC set the complaint for hearing procedures and subsequently the hearing for this complaint proceeding was consolidated with the hearing procedures for Entergy Services’ January 2021 NOLC ADIT filing.

Testimony was filed by parties in 2023, and the hearing before a FERC ALJ was concluded in February 2024. In June 2024, the FERC ALJ issued an initial decision addressing three major issues: (1) whether Entergy Services’ proposed prospective inclusion and allocation of NOLC ADIT in MSS-4 replacement tariff rates using a modified with-and-without methodology is just and reasonable; (2) whether Entergy Services correctly calculated excess and deficient accumulated deferred income taxes in accordance with the terms of a prior settlement; and (3) whether NOLC ADIT should have been included in MSS-4 replacement tariff rates prior to the effective date of the January 2021 MSS-4 replacement tariff filing.

With respect to issues (1) and (2), the presiding ALJ concluded that Entergy Services’ proposed methodology for allocating and including NOLC ADIT in MSS-4 replacement tariff rates was just and reasonable and that Entergy Services correctly performed the excess and deficient accumulated deferred income taxes calculations. With respect to issue (3), however, the presiding ALJ agreed with the LPSC that NOLC ADIT should have been included in MSS-4 replacement tariff rates since September 1, 2016, and as a result, the presiding ALJ ordered that Entergy Louisiana and Entergy Arkansas recalculate bills for the period of September 1, 2016 through November 11, 2023 with surcharges expected to be due to those operating companies from the purchasing operating companies, Entergy New Orleans, Entergy Texas, and Entergy Louisiana (for some Entergy Arkansas sales). The presiding ALJ also ordered Entergy Services to pay the interest owed to Entergy Louisiana on these surcharges.
The surcharge methodology that the presiding ALJ recommended in connection with issue (3) was not supported by any participant in the hearing. As part of their exceptions to the initial decision, all parties to the proceeding opposed the use of the ALJ’s methodology, except for the FERC trial staff, which took no position. During the hearing, the LPSC and the FERC trial staff advocated that the alleged tariff violation should be remedied by the application of Entergy Services’ January 2021 proposed methodology. All other parties, including the PUCT, the City Council, and Entergy Services, opposed any surcharges for the period prior to the March 20, 2021 effective date of the January 2021 filing.

Entergy Services disputes the presiding ALJ's rulings on issue (3) and filed exceptions to these rulings in July 2024. The ALJ's initial decision is not binding on the FERC and is an interim step in the hearing process. No refunds will be owed in connection with this proceeding unless and until the FERC requires them in a final order.
Complaints Against System Energy

System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf.  System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. System Energy and the Unit Power Sales Agreement have been the subject of several litigation proceedings at the FERC, including challenges with respect to System Energy’s authorized return on equity and capital structure, renewal of its sale-leaseback arrangement, treatment of uncertain tax positions, a broader investigation of rates under the Unit Power Sales Agreement, and two prudence complaints, one challenging the extended power uprate completed at Grand Gulf in 2012 and the operation and management of Grand Gulf, particularly in the 2016-2020 time period, and the second challenging the operation and management of Grand Gulf in the 2021-2022 time period. Settlements that resolve all significant aspects of these complaints have been reached with the MPSC, the APSC, the City Council, and the LPSC, and these settlements have been approved by the FERC. Following are discussions of the proceedings.

Return on Equity and Capital Structure Complaints

In January 2017 the APSC and the MPSC filed a complaint with the FERC against System Energy. The complaint sought a reduction in the return on equity component of the Unit Power Sales Agreement pursuant to which System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. Entergy Arkansas also sells some of its Grand Gulf capacity and energy to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under separate agreements. The return on equity under the Unit Power Sales Agreement at the time of the complaint was 10.94%, which was established in a rate proceeding that became final in July 2001.

The APSC and the MPSC complaint alleged that the return on equity was unjust and unreasonable because capital market and other considerations indicated that it was excessive. The complaint requested proceedings to investigate the return on equity and establish a lower return on equity, and also requested that the FERC establish January 23, 2017 as a refund effective date. The complaint included a return on equity analysis that purported to establish that the range of reasonable return on equity for System Energy was between 8.37% and 8.67%. System Energy answered the complaint in February 2017 and disputed that a return on equity of 8.37% to 8.67% was just and reasonable. The LPSC and the City Council intervened in the proceeding expressing support for the complaint. In September 2017 the FERC established a refund effective date of January 23, 2017 and directed the parties to engage in settlement proceedings before an ALJ. The parties were unable to settle the return on equity issue and a FERC hearing judge was assigned in July 2018. The 15-month refund period in connection with the APSC/MPSC complaint expired on April 23, 2018.

In April 2018 the LPSC filed a complaint with the FERC against System Energy seeking an additional 15-month refund period.  The LPSC complaint requested similar relief from the FERC with respect to System Energy’s
return on equity and also requested the FERC to investigate System Energy’s capital structure.  The APSC, the MPSC, and the City Council intervened in the proceeding, filed an answer expressing support for the complaint, and asked the FERC to consolidate this proceeding with the proceeding initiated by the complaint of the APSC and the MPSC in January 2017. System Energy answered the LPSC complaint in May 2018 and also filed a motion to dismiss the complaint. In August 2018 the FERC issued an order dismissing the LPSC’s request to investigate System Energy’s capital structure and setting for hearing the return on equity complaint, with a refund effective date of April 27, 2018. The 15-month refund period in connection with the LPSC return on equity complaint expired on July 26, 2019.

The portion of the LPSC’s complaint dealing with return on equity was subsequently consolidated with the APSC and the MPSC complaint for hearing. The parties also addressed an order (issued in a separate FERC proceeding involving New England transmission owners) that proposed modifying the FERC’s standard methodology for determining return on equity. In September 2018 the LPSC filed an amended complaint raising the same capital structure claim the FERC had earlier dismissed. The FERC initiated a new proceeding for the amended capital structure complaint, and System Energy answered the complaint in October 2018. In January 2019 the FERC set the amended complaint for settlement and hearing proceedings. Settlement proceedings in the capital structure proceeding commenced in February 2019, but were terminated in June 2019, and the amended capital structure complaint was consolidated with the ongoing return on equity proceeding. The 15-month refund period in connection with the capital structure complaint was from September 24, 2018 to December 23, 2019.

Several rounds of testimony were filed by the parties in these proceedings between January 2019 and August 2020. Some of these rounds of testimony were precipitated by developments in an unrelated proceeding in which the FERC issued orders addressing the methodology for determining the return on equity applicable to transmission owners in MISO (Opinion Nos. 569 and 569-A). The final positions of the parties, after the submission of all pre-filed testimony, were as follows. With regard to the return on equity complaints for the first refund period, based on their respective interpretations and applications of the Opinion No. 569-A methodology, the LPSC argued for an authorized return on equity for System Energy of 7.97%; the MPSC and the APSC argued for an authorized return on equity of 9.24%; and the FERC trial staff argued for an authorized return on equity of 9.49%. For the second refund period and on a prospective basis, based on their respective interpretations and applications of the Opinion No. 569-A methodology, the LPSC argued for an authorized return on equity for System Energy of 7.78%; the MPSC and the APSC argued that an authorized return on equity of 9.15% may be appropriate if the second complaint was not dismissed; and the FERC trial staff argued for an authorized return on equity of 9.09% if the second complaint was not dismissed. The LPSC also continued to support as its primary recommendation, based on an alternative analysis to the Opinion No. 569-A methodology, an authorized return on equity for System Energy as low as 7.56% for the first complaint refund period and as low as 7.18% for the second complaint refund period and prospectively. The MPSC and the APSC also continued to support as their primary recommendation, based on an alternative analysis to the Opinion No. 569-A methodology, an authorized return on equity for System Energy as low as 8.26% for the first complaint refund period and as low as 8.32% for the second complaint refund period and prospectively. System Energy argued that strict application of the Opinion No. 569-A methodology produces results inconsistent with investor requirements and does not provide a sound basis on which to evaluate System Energy’s authorized return on equity. Therefore, as its primary recommendation, System Energy argued for the use of a methodology that incorporates four separate financial models and, based on application of this recommended methodology, an authorized return on equity of 10.12% for the first refund period, which also fell within the presumptively just and reasonable range calculated for the second refund period and prospectively. Under the Opinion No. 569-A methodology, System Energy calculated an authorized return on equity of 9.44% for the first refund period, which also fell within the presumptively just and reasonable range calculated for the second refund period and prospectively.

With regard to the capital structure, the LPSC’s primary recommendation was that the FERC establish a hypothetical capital structure for System Energy for ratemaking purposes, according to which System Energy’s common equity ratio would be set to Entergy Corporation’s equity ratio of 37% equity and 63% debt. The APSC and the MPSC recommended that 35.98% be set as the common equity ratio for System Energy. The FERC trial
staff argued that the average capital structure of the proxy group used to develop System Energy’s return on equity should be used to establish the capital structure. Using this approach, the FERC trial staff calculated the average capital structure for its proposed proxy group of 46.74% common equity and 53.26% debt. System Energy disputed all of these recommendations and argued that the use of its actual capital structure was just and reasonable.

After conducting a hearing, in March 2021 the FERC ALJ issued an initial decision. With regard to System Energy’s authorized return on equity, the ALJ determined that the existing return on equity of 10.94% was no longer just and reasonable, and that the replacement authorized return on equity, based on application of the Opinion No. 569-A methodology, should be 9.32%. The ALJ further determined that System Energy should pay refunds for a fifteen-month refund period (January 2017-April 2018) based on the difference between the current return on equity and the replacement authorized return on equity. The ALJ determined that the April 2018 complaint concerning the authorized return on equity should be dismissed, and that no refunds for a second fifteen-month refund period should be due. With regard to System Energy’s capital structure, the ALJ determined that System Energy’s actual equity ratio was excessive and that the just and reasonable equity ratio was 48.15% equity, based on the average equity ratio of the proxy group used to evaluate the return on equity for the second complaint. The ALJ further determined that System Energy should pay refunds for a fifteen-month refund period (September 2018-December 2019) based on the difference between the actual equity ratio and the 48.15% equity ratio.

In April 2021, System Energy filed its brief on exceptions, in which it challenged the initial decision’s findings on both the return on equity and capital structure issues. Also in April 2021 the LPSC, the APSC, the MPSC, the City Council, and the FERC trial staff filed briefs on exceptions. Reply briefs opposing exceptions were filed in May 2021 by System Energy, the FERC trial staff, the LPSC, the APSC, the MPSC, and the City Council.

As discussed below in “System Energy Settlement with the MPSC,” “System Energy Settlement with the APSC,” “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the MPSC, the APSC, the City Council, and the LPSC have settled their claims related to these proceedings. As part of the settlements with their respective retail regulators, effective July 2022 for Entergy Mississippi, November 2023 for Entergy Arkansas, June 2024 for Entergy New Orleans, and September 2024 for Entergy Louisiana, bills issued under the Unit Power Sales Agreement reflect a return on equity of 9.65% and a capital structure not to exceed 52% equity.

In August 2022 the D.C. Circuit issued an order addressing appeals of FERC’s Opinion No. 569 and 569-A, which established the methodology applied in the ALJ’s initial decision in the proceeding against System Energy discussed above. The appellate order addressed the methodology for determining the return on equity applicable to transmission owners in MISO. The D.C. Circuit found the FERC’s use of the Risk Premium model as part of the methodology to be arbitrary and capricious, and remanded the case back to the FERC. In October 2024, after System Energy had reached settlements with each of the retail regulators involved in the return on equity and capital structure proceeding discussed above, the FERC issued a remand order in the MISO transmission owners’ return on equity case, concluding that the record supported the methodology that it originally directed in Opinion No. 569 utilizing an equal weighting of the two-step discounted cash flow model and capital asset pricing model. As a result, it determined that the just and reasonable return on equity for the MISO transmission owners is 9.98%. In light of the System Energy settlements detailed below, the FERC’s changes to its return on equity methodology in the decision on the MISO transmission owners’ return on equity will not have any immediate effect on System Energy’s return on equity because System Energy’s return on equity has been set at 9.65% through the global settlement through the end of June 2026.

Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue

In May 2018 the LPSC filed a complaint against System Energy and Entergy Services related to System Energy’s renewal of a sale-leaseback transaction originally entered into in December 1988 for an 11.5% undivided interest in Grand Gulf Unit 1. The complaint alleged that System Energy violated the filed rate and the FERC’s ratemaking and accounting requirements when it included in Unit Power Sales Agreement billings the cost of
capital additions associated with the sale-leaseback interest, and that System Energy was double-recovering costs by including both the lease payments and the capital additions in Unit Power Sales Agreement billings. The complaint also claimed that System Energy was imprudent in entering into the sale-leaseback renewal because the Utility operating companies that purchase Grand Gulf’s output from System Energy could have obtained cheaper capacity and energy in the MISO markets. The complaint further alleged that System Energy violated various other reporting and accounting requirements and should have sought prior FERC approval of the lease renewal. The complaint sought various forms of relief from the FERC, including refunds for capital addition costs for all years in which they were recorded in allegedly non-formula accounts or, alternatively, the disallowance of the return on equity for the capital additions in those years plus interest; a disallowance and refund of the lease costs of the sale-leaseback renewal on grounds of imprudence; an investigation into System Energy’s treatment of a DOE litigation payment; and the imposition of certain forward-looking procedural protections, including audit rights for retail regulators of the Unit Power Sales Agreement formula rates. The APSC, the MPSC, and the City Council intervened in the proceeding.

In June 2018, System Energy and Entergy Services filed a motion to dismiss and an answer to the LPSC complaint denying that System Energy’s treatment of the sale-leaseback renewal and capital additions violated the terms of the filed rate or any other FERC ratemaking, accounting, or legal requirements or otherwise constituted double recovery. The response also argued that the complaint was inconsistent with a FERC-approved settlement to which the LPSC is a party and that explicitly authorized System Energy to recover its lease payments. Finally, the response argued that both the capital additions and the sale-leaseback renewal were prudent investments and the LPSC complaint failed to justify any disallowance or refunds. The response also offered to submit formula rate protocols for the Unit Power Sales Agreement similar to the procedures used for reviewing transmission rates under the MISO tariff. In September 2018 the FERC issued an order setting the complaint for hearing and settlement proceedings and establishing a refund effective date of May 18, 2018.

In February 2019 the presiding ALJ ruled that the hearing ordered by the FERC includes the issue of whether specific subcategories of accumulated deferred income tax should be included in, or excluded from, System Energy’s formula rate. Testimony was filed by the LPSC, the MPSC, the APSC, the City Council, the FERC trial staff, and System Energy between March 2019 and October 2019. The final positions of the parties, after all pre-filed testimony was submitted, were as follows. The LPSC sought refunds that included the renewal lease payments (approximately $17.2 million per year since July 2015), rate base reductions for accumulated deferred income tax associated with uncertain tax positions (with a corresponding refund of approximately $512 million), and the cost of capital additions associated with the sale-leaseback interest, as well as interest on those amounts. The LPSC also argued that adjustments to depreciation rates should require retroactive depreciation expense refunds but only prospective rate base adjustments. The APSC, the MPSC, and the City Council generally agreed with the LPSC’s positions. The FERC trial staff argued for refunds for rate base reductions for liabilities associated with uncertain tax positions, and also argued that System Energy recovered $32 million more than it should have in depreciation expense for capital additions. System Energy filed testimony asking the FERC to reject all of the LPSC’s claims for refunds and opposing the FERC trial staff’s position regarding the uncertain tax position issue. System Energy also argued that the FERC trial staff’s position regarding depreciation rates for capital additions was not unreasonable, but any change in depreciation expense is only one element of a Unit Power Sales Agreement re-billing calculation. Adjustments to depreciation expense in any re-billing under the Unit Power Sales Agreement formula rate would also involve changes to accumulated depreciation, accumulated deferred income taxes, and other formula elements as needed.

After holding a hearing in November 2019, in April 2020 the FERC ALJ issued the initial decision. Among other things, the ALJ determined that refunds were due on three main issues. First, with regard to the lease renewal payments, the ALJ determined that System Energy was recovering an unjust acquisition premium through the lease renewal payments, and that System Energy’s recovery from customers through rates should be limited to the cost of service based on the remaining net book value of the leased assets, which was approximately $70 million. The ALJ found that the remedy for this issue should be the refund of lease payments (approximately $17.2 million per year since July 2015) with interest determined at the FERC quarterly interest rate, which would be offset by the addition
of the net book value of the leased assets in the cost of service. The ALJ did not calculate a value for the refund expected as a result of this remedy. In addition, System Energy would no longer recover the lease payments in rates prospectively. Second, with regard to the liabilities associated with uncertain tax positions, the ALJ determined that the liabilities are accumulated deferred income taxes and that System Energy’s rate base should have been reduced for those liabilities. The ALJ also found that System Energy should include liabilities associated with uncertain tax positions as a rate base reduction going forward. Third, with regard to the depreciation expense adjustments, the ALJ found that System Energy should correct for the error in re-billings retroactively and prospectively, but that System Energy should not be permitted to recover interest on any retroactive return on enhanced rate base resulting from such corrections.

In June 2020, System Energy, the LPSC, and the FERC trial staff filed briefs on exceptions, challenging several of the initial decision’s findings. System Energy’s brief on exceptions challenged the initial decision’s limitations on recovery of the lease renewal payments, its proposed rate base refund for the liabilities associated with uncertain tax positions, and its proposal to asymmetrically treat interest on bill corrections for depreciation expense adjustments. The LPSC’s and the FERC trial staff’s briefs on exceptions each challenged the initial decision’s allowance for recovery of the cost of service associated with the lease renewal based on the remaining net book value of the leased assets, its calculation of the remaining net book value of the leased assets, and the amount of the initial decision’s proposed rate base refund for the liabilities associated with uncertain tax positions. The LPSC’s brief on exceptions also challenged the initial decision’s proposal that depreciation expense adjustments include retroactive adjustments to rate base and its finding that section 203 of the Federal Power Act did not apply to the lease renewal. The FERC trial staff’s brief on exceptions also challenged the initial decision’s finding that the FERC need not institute a formal investigation into System Energy’s tariff. In October 2020, System Energy, the LPSC, the MPSC, the APSC, and the City Council filed briefs opposing exceptions. System Energy opposed the exceptions filed by the LPSC and the FERC trial staff. The LPSC, the MPSC, the APSC, the City Council, and the FERC trial staff opposed the exceptions filed by System Energy. Also in October 2020 the MPSC, the APSC, and the City Council filed briefs adopting the exceptions of the LPSC and the FERC trial staff.

In addition, in September 2020, the IRS issued a Notice of Proposed Adjustment (NOPA) and Entergy executed it. The NOPA memorialized the IRS’s decision to adjust the 2015 consolidated federal income tax return of Entergy Corporation and certain of its subsidiaries, including System Energy, with regard to the uncertain decommissioning tax position. Pursuant to the audit resolution documented in the NOPA, the IRS allowed System Energy’s inclusion of $102 million of future nuclear decommissioning costs in System Energy’s cost of goods sold for the 2015 tax year, roughly 10% of the requested deduction, but disallowed the balance of the position. In September 2020, System Energy filed a motion to lodge the NOPA into the record in the FERC proceeding. In October 2020 the LPSC, the APSC, the MPSC, the City Council, and the FERC trial staff filed oppositions to System Energy’s motion. As a result of the NOPA issued by the IRS in September 2020, System Energy filed, in October 2020, a new Federal Power Act section 205 filing at FERC to establish an ongoing rate base credit for the accumulated deferred income taxes resulting from the decommissioning uncertain tax position. On a prospective basis beginning with the October 2020 bill, System Energy proposed to include the accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position as a credit to rate base under the Unit Power Sales Agreement. In November 2020 the LPSC, the APSC, the MPSC, and the City Council filed a protest to the filing, and System Energy responded.

In November 2020 the IRS issued a Revenue Agent’s Report (RAR) for the 2014/2015 tax year and in December 2020 Entergy executed it. The RAR contained the same adjustment to the uncertain nuclear decommissioning tax position as that which the IRS had announced in the NOPA. In December 2020, System Energy filed a motion to lodge the RAR into the record in the FERC proceeding addressing the uncertain tax position rate base issue. In January 2021 the LPSC, the APSC, the MPSC, and the City Council filed a protest to the motion.

As a result of the RAR, in December 2020, System Energy filed amendments to its new Federal Power Act section 205 filings to establish an ongoing rate base credit for the accumulated deferred income taxes resulting from
the decommissioning uncertain tax position and to credit excess accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position. The amendments both proposed the inclusion of the RAR as support for the filings. In December 2020 the LPSC, the APSC, and the City Council filed protests to the amendments. In February 2021 the FERC issued an order accepting System Energy’s Federal Power Act section 205 filings subject to refund, setting them for hearing, and holding the hearing in abeyance.

In December 2020, System Energy filed a new Federal Power Act section 205 filing to provide a one-time, historical credit of $25.2 million for the accumulated deferred income taxes that would have been created by the decommissioning uncertain tax position if the IRS’s decision had been known in 2016. In January 2021 the LPSC, APSC, MPSC, and City Council filed a protest to the filing. In February 2021 the FERC issued an order accepting System Energy’s Federal Power Act section 205 filing subject to refund, setting it for hearing, and holding the hearing in abeyance. System Energy provided the one-time credit during the first quarter 2021.

In December 2022 the FERC issued an order on the ALJ’s initial decision, which affirmed it in part and modified it in part. The FERC’s order directed System Energy to calculate refunds on three issues, and to provide a compliance report detailing the calculations. The FERC’s order also disallowed the future recovery of sale-leaseback renewal costs, which is estimated at approximately $11.5 million annually for purchases from Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans through July 2036. The three refund issues were rental expenses related to the renewal of the sale-leaseback arrangements; refunds, if any, for the revenue requirement impact of including accumulated deferred income taxes resulting from the decommissioning uncertain tax positions from 2004 through the present; and refunds for the net effect of correcting the depreciation inputs for capital additions attributable to the portion of plant subject to the sale-leaseback.

As a result of the FERC order’s directives regarding the recovery of the sale-leaseback transaction, in December 2022 System Energy reduced the Grand Gulf sale-leaseback regulatory liability by $56 million, reduced the related accumulated deferred income tax asset by $94 million, and reduced the Grand Gulf sale-leaseback accumulated deferred income tax regulatory liability by $25 million, resulting in an increase in income tax expense of $13 million. In addition, the FERC determined that System Energy recognized excess depreciation expense related to property subject to the sale-leaseback. As a result, in December 2022, System Energy recorded a reduction in depreciation expense and the related accumulated depreciation of $33 million.

In January 2023, System Energy filed its compliance report with the FERC. With respect to the sale-leaseback renewal costs, System Energy calculated a refund of $89.8 million, which represented all of the sale-leaseback renewal rental costs that System Energy recovered in rates, with interest. With respect to the decommissioning uncertain tax position issue, System Energy calculated that no additional refunds were owed because it had already provided a one-time historical credit (for the period January 2016 through September 2020) of $25.2 million based on the accumulated deferred income taxes that resulted from the IRS’s partial acceptance of the decommissioning tax position, and because it has been providing an ongoing rate base credit for the accumulated deferred income taxes that resulted from the IRS’s partial acceptance of the decommissioning tax position since October 2020. With respect to the depreciation refund, System Energy calculated a refund of $13.7 million, which is the net total of a refund to customers for excess depreciation expense previously collected, plus interest, offset by the additional return on rate base that System Energy previously did not collect, without interest. See “System Energy Settlement with the MPSC” below for discussion of the regulatory charge and corresponding regulatory liability recorded in June 2022 related to these proceedings. In January 2023, System Energy paid the refunds of $103.5 million, which included refunds of $41.7 million to Entergy Arkansas, $27.8 million to Entergy Louisiana, and $34 million to Entergy New Orleans.

In February 2023 the LPSC, the APSC, and the City Council filed protests to System Energy’s January 2023 compliance report, in which they challenged System Energy’s calculation of the refunds associated with the decommissioning tax position but did not protest the other components of the compliance report. Each of them argued that System Energy should have paid additional refunds for the decommissioning tax position issue, and the City Council estimated the total additional refunds owed to customers of Entergy Louisiana, Entergy New Orleans,
and Entergy Arkansas for that issue as $493 million, including interest (and without factoring in the $25.2 million refund that System Energy already paid in 2021).

In January 2023, System Energy filed a request for rehearing of the FERC’s determinations in the December 2022 order on sale-leaseback refund issues and future lease cost disallowances, the FERC’s prospective policy on uncertain tax positions, and the proper accounting of System Energy’s accumulated deferred income taxes adjustment for the Tax Cuts and Jobs Act of 2017; and a motion for confirmation of its interpretation of the December 2022 order’s remedy concerning the decommissioning tax position. In January 2023 the retail regulators filed a motion for confirmation of their interpretation of the refund requirement in the December 2022 FERC order and a provisional request for rehearing. In February 2023 the FERC issued a notice that the rehearing requests were denied by operation of law. In March 2023, System Energy filed in the United States Court of Appeals for the Fifth Circuit a petition for review of the December 2022 order. In March 2023, System Energy also filed an unopposed motion to stay the proceeding in the Fifth Circuit pending the FERC’s disposition of the pending motions, and the court granted the motion to stay.

In February 2023, System Energy submitted a tariff compliance filing with the FERC to clarify that, consistent with the releases provided in the MPSC settlement, Entergy Mississippi will continue to be charged for its allocation of the sale-leaseback renewal costs under the Unit Power Sales Agreement. See “System Energy Settlement with the MPSC” below for discussion of the settlement. In March 2023 the MPSC filed a protest to System Energy’s tariff compliance filing. The MPSC argues that the settlement did not specifically address post-settlement sale-leaseback renewal costs and that the sale-leaseback renewal costs may not be recovered under the Unit Power Sales Agreement. Entergy Mississippi’s allocated sale-leaseback renewal costs are estimated at $5.7 million annually for the remaining term of the sale-leaseback renewal.

In August 2023 the FERC issued an order addressing arguments raised on rehearing and partially setting aside the prior order (rehearing order). The rehearing order addressed rehearing requests that were filed in January 2023 separately by System Energy and the LPSC, the APSC, and the City Council.

In the rehearing order, the FERC directed System Energy to recalculate refunds for two issues: (1) refunds of rental expenses related to the renewal of the sale-leaseback arrangements and (2) refunds for the net effect of correcting the depreciation inputs for capital additions associated with the sale-leaseback. With regard to the sale-leaseback renewal rental expenses, the rehearing order allowed System Energy to recover an implied return of and on the depreciated cost of the portion of the plant subject to the sale-leaseback as of the expiration of the initial lease term. With regard to the depreciation input issue, the rehearing order allowed System Energy to offset refunds so that System Energy may collect interest on the rate base recalculations that were part of the overall depreciation rate recalculations. The rehearing order further directed System Energy to submit within 60 days of the date of the rehearing order an additional compliance filing to revise the total refunds for these two issues. As discussed above, System Energy’s January 2023 compliance filing calculated $103.5 million in total refunds, and the refunds were paid in January 2023. In October 2023, System Energy filed its compliance report with the FERC as directed in the August 2023 rehearing order. The October 2023 compliance report reflected recalculated refunds totaling $35.7 million for the two issues resulting in $67.8 million in refunds that could be recouped by System Energy. As discussed below in “System Energy Settlement with the APSC,” System Energy reached a settlement in principle with the APSC to resolve several pending cases under the FERC’s jurisdiction, including this one, pursuant to which it agreed not to recoup the $27.3 million calculated for Entergy Arkansas in the compliance filing. As a result of the FERC’s rulings on the sale-leaseback and depreciation input issues in the August 2023 rehearing order, in third quarter 2023, System Energy recorded a regulatory asset and corresponding regulatory credit of $40 million to reflect the portion of the January 2023 refunds to be recouped from Entergy Louisiana and Entergy New Orleans. Consistent with the compliance filing, in October 2023, Entergy Louisiana and Entergy New Orleans paid recoupment amounts of $18.2 million and $22.3 million, respectively, to System Energy.
On the third refund issue identified in the rehearing requests, concerning the decommissioning uncertain tax positions, the rehearing order denied all rehearing requests, re-affirmed the remedy contained in the December 2022 order, and did not direct System Energy to recalculate refunds or to submit an additional compliance filing.

In September 2023, System Energy filed a protective appeal of the rehearing order with the United States Court of Appeals for the Fifth Circuit. The appeal was consolidated with System Energy’s prior appeal of the December 2022 order.

In September 2023 the LPSC filed with the FERC a request for rehearing and clarification of the rehearing order. The LPSC requested that the FERC reverse its determination in the rehearing order that System Energy may collect an implied return of and on the depreciated cost of the portion of the plant subject to the sale-leaseback, as of the expiration of the initial lease term, as well as its determination in the rehearing order that System Energy may offset the refunds for the depreciation rate input issue and collect interest on the rate base recalculations that were part of the overall depreciation rate recalculations. In addition, the LPSC requested that the FERC either confirm the LPSC’s interpretation of the refund associated with the decommissioning uncertain tax positions or explain why it is not doing so. In October 2023 the FERC issued a notice that the rehearing request was deemed denied by operation of law. In November 2023 the FERC issued a further notice stating that it would not issue any further order addressing the rehearing request. Also in November 2023 the LPSC filed with the United States Court of Appeals for the Fifth Circuit a petition for review of the FERC’s August 2023 rehearing order and denials of the September 2023 rehearing request.

In December 2023 the United States Court of Appeals for the Fifth Circuit lifted the abeyance on the consolidated System Energy appeals and it also consolidated the LPSC’s appeal with the System Energy appeals. Briefing of the appeals occurred between March 2024 and July 2024. In September 2024 the parties filed a joint motion to continue and stay oral argument, previously scheduled for October 2024, pending the FERC’s decision whether to approve the settlement between System Energy and the LPSC, and the United States Court of Appeals for the Fifth Circuit granted the motion. In November 2024, after the FERC issued the order approving the settlement between System Energy and the LPSC, System Energy, the LPSC, the APSC, and the FERC filed a joint stipulation to dismiss the pending appeals, which the United States Court of Appeals for the Fifth Circuit granted.

As discussed below in “System Energy Settlement with the MPSC,” “System Energy Settlement with the APSC,” “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the MPSC, the APSC, the City Council, and the LPSC have settled their claims related to this proceeding.

LPSC Additional Complaints

In May 2020 the LPSC authorized its staff to file additional complaints at the FERC related to the rates charged by System Energy for Grand Gulf energy and capacity supplied to Entergy Louisiana under the Unit Power Sales Agreement. The LPSC directive noted that the initial decision issued by the presiding ALJ in the Grand Gulf sale-leaseback complaint proceeding did not address, for procedural reasons, certain rate issues raised by the LPSC and declined to order further investigation of rates charged by System Energy.

Unit Power Sales Agreement Complaint

The first of the additional complaints was filed by the LPSC, the APSC, the MPSC, and the City Council in September 2020. The first complaint raised two sets of rate allegations: violations of the filed rate and a corresponding request for refunds for prior periods; and elements of the Unit Power Sales Agreement are unjust and unreasonable and a corresponding request for refunds for the 15-month refund period and changes to the Unit Power Sales Agreement prospectively. Several of the filed rate allegations overlapped with the previous complaints. The filed rate allegations not previously raised were that System Energy: failed to provide a rate base credit to customers for the “time value” of sale-leaseback lease payments collected from customers in advance of the time those payments were due to the owner-lessors; improperly included certain sale-leaseback transaction costs in rate base as
prepayments; improperly included nuclear refueling outage costs in rate base; wrongly included categories of accumulated deferred income taxes as increases to rate base; charged customers based on a higher equity ratio than would be appropriate due to excessive retained earnings; and did not correctly reflect money pool investments and imprudently invested cash into the money pool. The elements of the Unit Power Sales Agreement that the complaint alleged were unjust and unreasonable include: the current cash working capital allowance of zero, uncapped recovery of incentive and executive compensation, lack of an equity re-opener, and recovery of lobbying and private airplane travel expenses. The complaint also requested a rate investigation into the Unit Power Sales Agreement and System Energy’s billing practices pursuant to section 206 of the Federal Power Act, including any issue relevant to the Unit Power Sales Agreement and its inputs. System Energy filed its answer opposing the complaint in November 2020. In its answer, System Energy argued that all of the claims raised in the complaint should be dismissed and agreed that bill adjustment with respect to two discrete issues were justified. System Energy argued that dismissal was warranted because all claims fell into one or more of the following categories: the claims had been raised and were being litigated in another proceeding; the claims did not present a prima facie case and did not satisfy the threshold burden to establish a complaint proceeding; the claims were premised on a theory or request relief that is incompatible with federal law or FERC policy; the claims request relief that is inconsistent with the filed rate; the claims were barred or waived by the legal doctrine of laches; and/or the claims had been fully addressed and do not warrant further litigation. In December 2020, System Energy filed a bill adjustment report indicating that $3.4 million had been credited to customers in connection with the two discrete issues concerning the inclusion of certain accumulated deferred income taxes balances in rates.

In May 2021 the FERC issued an order addressing the complaint, establishing a refund effective date of September 21, 2020, establishing hearing procedures, and holding those procedures in abeyance pending the FERC’s review of the initial decision in the Grand Gulf sale-leaseback renewal complaint discussed above. System Energy agreed that the hearing should be held in abeyance but sought rehearing of FERC’s decision as related to matters set for hearing that were beyond the scope of FERC’s jurisdiction or authority. The complainants sought rehearing of FERC’s decision to hold the hearing in abeyance and filed a motion to proceed, which motion System Energy opposed. In June 2021, System Energy’s request for rehearing was denied by operation of law, and System Energy filed an appeal of FERC’s orders in the Court of Appeals for the Fifth Circuit. In November 2021 the Fifth Circuit dismissed the appeal as premature.

In August 2021 the FERC issued an order addressing System Energy’s and the complainants’ rehearing requests. The FERC dismissed part of the complaint seeking an equity re-opener, maintained the abeyance for issues related to the proceeding addressing the sale-leaseback renewal and uncertain tax positions, lifted the abeyance for issues unrelated to that proceeding, and clarified the scope of the hearing.

In November 2021 the LPSC, the APSC, and the City Council filed direct testimony and requested the FERC to order refunds for prior periods and prospective amendments to the Unit Power Sales Agreement. The LPSC’s refund claims included, among other things, allegations that: (1) System Energy should not have included certain sale-leaseback transaction costs in prepayments; (2) System Energy should have credited rate base to reflect the time value of money associated with the advance collection of lease payments; (3) System Energy incorrectly included refueling outage costs that were recorded in account 174 in rate base; and (4) System Energy should have excluded several accumulated deferred income tax balances in account 190 from rate base. The LPSC also sought a retroactive adjustment to retained earnings and capital structure in conjunction with the implementation of its proposed refunds. In addition, the LPSC sought amendments to the Unit Power Sales Agreement going forward to address below-the-line costs, incentive compensation, the working capital allowance, litigation expenses, and the 2019 termination of the capital funds agreement. The APSC argued that: (1) System Energy should have included borrowings from the Entergy system money pool in its determination of short-term debt in its cost of capital; and (2) System Energy should credit customers with System Energy’s allocation of earnings on money pool investments. The City Council alleged that System Energy has maintained excess cash on hand in the money pool and that retention of excess cash was imprudent. Based on this allegation, the City Council’s witness recommended a refund of approximately $98.8 million for the period 2004-September 2021 or other alternative relief. The City Council
further recommended that the FERC impose a hypothetical equity ratio such as 48.15% equity to capital on a prospective basis.

In January 2022, System Energy filed answering testimony arguing that the FERC should not order refunds for prior periods or any prospective amendments to the Unit Power Sales Agreement. In response to the LPSC’s refund claims, System Energy argued, among other things, that: (1) the inclusion of sale-leaseback transaction costs in prepayments was correct; (2) that the filed rate doctrine bars the request for a retroactive credit to rate base for the time value of money associated with the advance collection of lease payments; (3) that an accounting misclassification for deferred refueling outage costs had been corrected, caused no harm to customers, and requires no refunds; and (4) that its accounting and ratemaking treatment of specified accumulated deferred income tax balances in account 190 had been correct. System Energy further responded that no retroactive adjustment to retained earnings or capital structure should be ordered because there was no general policy requiring such a remedy, and there was no showing that the retained earnings element of the capital structure was incorrectly implemented. Further, System Energy presented evidence that all of the costs that were being challenged were long known to the retail regulators and were approved by them for inclusion in retail rates, and the attempt to retroactively challenge these costs, some of which had been included in rates for decades, was unjust and unreasonable. In response to the LPSC’s proposed going-forward adjustments, System Energy presented evidence to show that none of the proposed adjustments were needed. On the issue of below-the-line expenses, during discovery procedures System Energy identified a historical allocation error in certain months and agreed to provide a bill credit to customers to correct the error. In response to the APSC’s claims, System Energy argued that the Unit Power Sales Agreement did not include System Energy’s borrowings from the Entergy system money pool or earnings on deposits to the Entergy system money pool in the determination of the cost of capital; and accordingly, no refunds were appropriate on those issues. In response to the City Council’s claims, System Energy argued that it has reasonably managed its cash and that the City Council’s theory of cash management was defective because it failed to adequately consider the relevant cash needs of System Energy and it made faulty presumptions about the operation of the Entergy system money pool. System Energy further pointed out that the issue of its capital structure was already subject to pending FERC litigation.

In March 2022 the FERC trial staff filed direct and answering testimony in response to the LPSC, the APSC, and the City Council’s direct testimony. In its testimony, the FERC trial staff recommended refunds for two primary reasons: (1) it concluded that System Energy should have excluded specified accumulated deferred income tax balances in account 190 associated with rate refunds; and (2) it concluded that System Energy should have excluded specified accumulated deferred income tax balances in account 190 associated with a deemed contract satisfaction and reissuance that occurred in 2005. The FERC trial staff recommended refunds of $84.1 million, exclusive of any tax gross-up or FERC interest. In addition, the FERC trial staff recommended the following prospective modifications to the Unit Power Sales Agreement: (1) inclusion of a rate base credit to recognize the time value of money associated with the advance collection of lease payments; (2) exclusion of executive incentive compensation costs for members of the Office of the Chief Executive and long-term performance unit costs where awards are based solely or primarily on financial metrics; and (3) exclusion of unvested, accrued amounts for stock options, performance units, and restricted stock awards. With respect to issues that ultimately concerned the reasonableness of System Energy’s rate of return, the FERC trial staff stated that it was unnecessary to consider such issues in the proceeding, in light of the pending case concerning System Energy’s return on equity and capital structure. On all other material issues raised by the LPSC, the APSC, and the City Council, the FERC trial staff recommended either no refunds or no modification to the Unit Power Sales Agreement.

In April 2022, System Energy filed cross-answering testimony in response to the FERC trial staff’s recommendations of refunds for the accumulated deferred income taxes issues and proposed modifications to the Unit Power Sales Agreement for the executive incentive compensation issues. In June 2022 the FERC trial staff submitted revised answering testimony, in which it recommended additional refunds associated with the accumulated deferred income tax balances in account 190 associated with a deemed contract satisfaction and reissuance that occurred in 2005. Based on the testimony revisions, the FERC trial staff’s recommended refunds total $106.6 million, exclusive of any tax gross-up or FERC awarded interest. Also in June 2022, System Energy
filed revised and supplemental cross-answering testimony to respond to the FERC trial staff’s testimony and oppose its revised recommendation.

In May 2022 the LPSC, the APSC, and the City Council filed rebuttal testimony. The LPSC’s testimony asserted new claims, including that: (1) certain of the sale-leaseback transaction costs may have been imprudently incurred; (2) accumulated deferred income taxes associated with sale-leaseback transaction costs should have been included in rate base; (3) accumulated deferred income taxes associated with federal investment tax credits should have been excluded from rate base; (4) monthly net operating loss accumulated deferred income taxes should have been excluded from rate base; and (5) several categories of proposed rate changes, including executive incentive compensation, air travel, industry dues, and legal costs, also warranted historical refunds. The LPSC’s rebuttal testimony argued that refunds for the alleged tariff violations and other claims must be calculated by rerunning the Unit Power Sales Agreement formula rate; however, it included estimates of refunds associated with some, but not all, of its claims, totaling $286 million without interest. The City Council’s rebuttal testimony also proposed a new, alternate theory and claim for relief regarding System Energy’s participation in the Entergy system money pool, under which it calculates estimated refunds of approximately $51.7 million. The APSC’s rebuttal testimony agreed with the LPSC’s direct testimony that retained earnings should be adjusted in a comprehensive refund calculation. The testimony quantified the estimated impacts of three issues: (1) a $1.5 million reduction in the revenue requirement under the Unit Power Sales Agreement if System Energy’s borrowings from the money pool were included in short-term debt; (2) a $1.9 million reduction in the revenue requirement if System Energy’s allocated share of money pool earnings were credited through the Unit Power Sales Agreement; and (3) a $1.9 million reduction in the revenue requirement for every $50 million of refunds ordered in a given year, without interest. In total, excluding the settled issues noted below, the claims sought more than $700 million in refunds and interest, based on charges to all Unit Power Sales Agreement purchasers including Entergy Mississippi. The hearing before a FERC ALJ occurred between September and December 2022.

In November 2022, System Energy filed a partial settlement agreement with the APSC, the City Council, and the LPSC that resolved the following issues raised in the Unit Power Sales Agreement complaint: advance collection of lease payments, aircraft costs, executive incentive compensation, money pool borrowings, advertising expenses, deferred nuclear refueling outage costs, industry association dues, and termination of the capital funds agreement. The settlement provided that System Energy would provide a black box refund of $18 million (inclusive of interest), plus additional refund amounts with interest to be calculated for certain issues to be distributed to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans as the Utility operating companies other than Entergy Mississippi purchasing under the Unit Power Sales Agreement. The settlement further provided that if the APSC, the City Council, or the LPSC agreed to the global settlement System Energy entered into with the MPSC (discussed below), and such global settlement included a black box refund amount, then the black box refund for this settlement agreement would not be incremental or in addition to the global black box refund amount. The settlement agreement addressed other matters as well, including adjustments to rate base beginning in October 2022, exclusion of certain other costs, and inclusion of money pool borrowings, if any, in short-term debt within the cost of capital calculation used in the Unit Power Sales Agreement. In April 2023 the FERC approved the settlement agreement. The refund provided for in the settlement agreement was included in the May 2023 service month bills under the Unit Power Sales Agreement.

In May 2023 the presiding ALJ issued an initial decision finding that System Energy should have excluded multiple identified categories of accumulated deferred income taxes from rate base when calculating Unit Power Sales Agreement bills. The initial decision also found that the Unit Power Sales Agreement should be modified such that a cash working capital allowance of negative $36.4 million is applied prospectively. On the other non-settled issues for which the complainants sought refunds or changes to the Unit Power Sales Agreement, the initial decision ruled against the complainants.

System Energy disagreed with the ALJ’s findings concerning the accumulated deferred income taxes issues and cash working capital. In July 2023, System Energy filed a brief on exceptions to the initial decision’s accumulated deferred income taxes findings. Also in July 2023, the APSC, the LPSC, the City Council, and the
FERC trial staff filed separate briefs on exceptions. In August 2023 all parties filed separate briefs opposing exceptions.

As discussed below in “System Energy Settlement with the MPSC,” “System Energy Settlement with the APSC,” and “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the MPSC, the APSC, and the City Council, and the LPSC have settled their claims related to this proceeding.

Grand Gulf Prudence Complaints

The second of the additional complaints was filed at the FERC in March 2021 by the LPSC, the APSC, and the City Council against System Energy, Entergy Services, Entergy Operations, and Entergy Corporation. The second complaint contained two primary allegations. First, it alleged that, based on the plant’s capacity factor and alleged safety performance, System Energy and the other respondents imprudently operated Grand Gulf during the period 2016-2020, and it sought refunds of at least $360 million in alleged replacement energy costs, in addition to other costs, including those that could only be identified upon further investigation. Second, it alleged that the performance and/or management of the 2012 extended power uprate of Grand Gulf was imprudent, and it sought refunds of all costs of the 2012 uprate that were determined to result from imprudent planning or management of the project. In addition to the requested refunds, the complaint asked that the FERC modify the Unit Power Sales Agreement to provide for full cost recovery only if certain performance indicators were met and to require pre-authorization of capital improvement projects in excess of $125 million before related costs could be passed through to customers in rates. In April 2021, System Energy and the other respondents filed their motion to dismiss and answer to the complaint. System Energy requested that the FERC dismiss the claims within the complaint. With respect to the claim concerning operations, System Energy argued that the complaint did not meet its legal burden because, among other reasons, it failed to allege any specific imprudent conduct. With respect to the claim concerning the uprate, System Energy argued that the complaint failed because, among other reasons, the complainants’ own conduct prevented them from raising a serious doubt as to the prudence of the uprate. System Energy also requested that the FERC dismiss other elements of the complaint, including the proposed modifications to the Unit Power Sales Agreement, because they were not warranted. In February 2023 the FERC issued an order denying rehearing and thereby affirming its order setting the complaint for settlement and hearing procedures. In July 2023 the FERC chief ALJ terminated settlement procedures and appointed a presiding ALJ to oversee hearing procedures. In September 2023 a procedural schedule for hearing procedures was established. Also in September 2023 the LPSC authorized its staff to file an additional complaint concerning the prudence of System Energy’s operation and management of Grand Gulf in the year 2022. In October 2023 the LPSC, the APSC, and the City Council filed what they styled as an amended and supplemental complaint with the FERC against System Energy, Entergy Services, and Entergy Operations. In November 2023, System Energy answered the amended and supplemental complaint. Pursuant to the procedural schedule, the complainants’ testimony in the original complaint proceeding was filed in December 2023. System Energy’s answering testimony was filed in May 2024, and the FERC trial staff’s direct and answering testimony was filed in June 2024.

As discussed below in “System Energy Settlement with the APSC,” “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the APSC, the City Council, and the LPSC have settled all of their claims related to this proceeding.

System Energy Settlement with the MPSC

In June 2022, System Energy, Entergy Mississippi, and additional named Entergy parties involved in thirteen docketed proceedings before the FERC filed with the FERC a partial settlement agreement and offer of settlement. The settlement memorialized the Entergy parties’ agreement with the MPSC to globally resolve all actual and potential claims between the Entergy parties and the MPSC associated with those FERC proceedings and with System Energy’s past implementation of the Unit Power Sales Agreement. The Unit Power Sales Agreement is a FERC-jurisdictional formula rate tariff for sales of energy and capacity from System Energy’s owned and
leased share of Grand Gulf to Entergy Mississippi, Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans. Entergy Mississippi purchases the greatest single amount, nearly 40% of System Energy’s share of Grand Gulf, after its additional purchases from affiliates are considered.

The settlement provided for a black box refund of $235 million from System Energy to Entergy Mississippi. In addition, beginning with the July 2022 service month, the settlement provided for Entergy Mississippi’s bills from System Energy to be adjusted to reflect: an authorized rate of return on equity of 9.65%, a capital structure not to exceed 52% equity, a rate base reduction for the advance collection of sale-leaseback rental costs, and the exclusion of certain long-term incentive plan performance unit costs from rates. The settlement was approved by the MPSC in June 2022 and the FERC in November 2022.

System Energy had previously recorded a provision and associated liability of $37 million for elements of the applicable litigation. In June 2022, System Energy recorded a regulatory charge of $551 million ($413 million net-of-tax), increasing the regulatory liability to $588 million, which consisted of $235 million for the settlement with the MPSC and $353 million for potential future refunds to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans. System Energy paid the black box refund of $235 million to Entergy Mississippi in November 2022.

System Energy Settlement with the APSC

In October 2023, System Energy, Entergy Arkansas, and additional named Entergy parties involved in multiple docketed proceedings pending before the FERC reached a settlement in principle with the APSC to globally resolve all of their actual and potential claims in those dockets and with System Energy’s past implementation of the Unit Power Sales Agreement. The settlement also covered the amended and supplemental complaint, discussed above in “Grand Gulf Prudence Complaint,” filed at the FERC in October 2023. System Energy, Entergy Arkansas, additional Entergy parties, and the APSC filed the settlement agreement and supporting materials with the FERC in November 2023.

The terms of the settlement with the APSC aligned with the $588 million global black box settlement reached between System Energy and the MPSC in June 2022 and provided for Entergy Arkansas to receive a black box refund of $142 million from System Energy, inclusive of $49.5 million already received by Entergy Arkansas from System Energy. In addition, beginning with the November 2023 service month, the settlement provided for Entergy Arkansas’s bills from System Energy to be adjusted to reflect an authorized rate of return on equity of 9.65% and a capital structure not to exceed 52% equity. In March 2024 the FERC approved the settlement, and System Energy paid the remaining black box refund of $93 million to Entergy Arkansas in 2024.

System Energy Settlement with the City Council

In April 2024, System Energy, Entergy New Orleans, and additional named Entergy parties involved in multiple docketed proceedings pending before the FERC reached a settlement in principle with the City Council to globally resolve all of their actual and potential claims in those dockets and with System Energy’s past implementation of the Unit Power Sales Agreement. The settlement also covered the amended and supplemental complaint, discussed in “Grand Gulf Prudence Complaints” above, filed by the LPSC, the APSC, and the City Council at the FERC in October 2023. In May 2024, System Energy, Entergy New Orleans, additional named Entergy parties, and the City Council filed the settlement agreement and supporting materials with the FERC.

The terms of the settlement with the City Council aligned with the $588 million global black box settlement amount reflected in the prior settlements reached between System Energy and the MPSC in June 2022 and between System Energy and the APSC in November 2023. The settlement provided for Entergy New Orleans to receive a black box refund of $116 million from System Energy, inclusive of approximately $18 million already received by Entergy New Orleans from System Energy. In addition, beginning with the June 2024 service month, the settlement provided for Entergy New Orleans’s bills from System Energy to be adjusted to reflect an authorized rate of return on equity of 9.65% and a capital structure not to exceed 52% equity. In August 2024 the FERC approved the
settlement, and System Energy paid the remaining black box refund of $98 million to Entergy New Orleans in October 2024.

System Energy Settlement with the LPSC

In July 2024, System Energy and the LPSC staff reached a settlement in principle to globally resolve all of the LPSC’s actual and potential claims in multiple docketed proceedings pending before the FERC (including all docketed proceedings resolved by the MPSC, the APSC, and the City Council settlements) and with System Energy’s past implementation of the Unit Power Sales Agreement. The settlement also covered the amended and supplemental complaint, discussed above in “Grand Gulf Prudence Complaints,” filed by the LPSC, the APSC, and the City Council at the FERC in October 2023. In August 2024 the LPSC approved the settlement. In September 2024 the settling parties filed the settlement for approval by the FERC.

The terms of the settlement with the LPSC staff aligned with the $588 million global black box settlement amount reflected in the prior settlements reached between System Energy and the MPSC in June 2022, between System Energy and the APSC in November 2023, and between System Energy and the City Council in April 2024. The settlement in principle provided for Entergy Louisiana to receive a black box refund of $95 million from System Energy, inclusive of approximately $15 million already received by Entergy Louisiana from System Energy. In addition, beginning with the September 2024 service month, the settlement provided for Entergy Louisiana’s bills from System Energy to be adjusted to reflect an authorized rate of return on equity of 9.65% and a capital structure not to exceed 52% equity. In November 2024 the FERC approved the settlement, and System Energy paid the remaining black box refund of $80 million to Entergy Louisiana in December 2024.

The settlement also included an agreement that, subject to the receipt of necessary regulatory approvals, Entergy Louisiana will divest to Entergy Mississippi all of its interest in Grand Gulf capacity and energy under the Unit Power Sales Agreement and its purchases from Entergy Arkansas under the MSS-4 replacement tariff. In October 2024 Entergy Louisiana and Entergy Mississippi filed with the FERC a PPA under which Entergy Mississippi would purchase Entergy Louisiana’s purchases of Grand Gulf capacity and energy. The PPA is governed by the MSS-4 replacement tariff, a tariff governing the sales of energy and capacity among the Utility operating companies. The requisite approvals for the PPA were issued by the FERC in November 2024 and the MPSC in February 2025. The divestiture is effective as of January 1, 2025.

System Energy Regulatory Liability for Pending Complaints

Prior to June 2022, System Energy recorded a provision and associated liability of $37 million for elements of the complaints against System Energy. In June 2022, as discussed in “System Energy Settlement with the MPSC” above, System Energy recorded a regulatory charge of $551 million ($413 million net-of-tax), increasing System Energy’s regulatory liability to $588 million, which consisted of $235 million for the settlement with the MPSC and $353 million for potential future refunds to Entergy Arkansas, Entergy New Orleans, and Entergy Louisiana. System Energy paid the black box refund of $235 million to Entergy Mississippi in November 2022. As discussed above in “Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue,” in January 2023 System Energy paid refunds of $103.5 million as a result of the FERC’s order in December 2022 in that proceeding and recouped $40.5 million of the $103.5 million from Entergy Louisiana and Entergy New Orleans in October 2023. In addition, as discussed above in “Unit Power Sales Agreement Complaint,” a black box refund of $18 million was made by System Energy in 2023 in connection with a partial settlement in that proceeding. Based on analysis of the then-pending complaints against System Energy and potential future settlement negotiations with the LPSC and the City Council, in third quarter 2023, System Energy recorded a regulatory charge of $40 million to increase System Energy’s regulatory liability related to complaints against System Energy. In December 2023 the $93 million black box refund to Entergy Arkansas was reclassified from the regulatory liability to accounts payable - associated companies on System Energy’s balance sheet. System Energy paid the remaining black box refunds of $93 million to Entergy Arkansas, $98 million to Entergy New Orleans, and $80 million to Entergy Louisiana in 2024.
Unit Power Sales Agreement

System Energy Formula Rate Annual Protocols Formal Challenge Concerning 2020 Calendar Year Bills

System Energy’s Unit Power Sales Agreement includes formula rate protocols that provide for the disclosure of cost inputs, an opportunity for informal discovery procedures, and a challenge process. In February 2022, pursuant to the protocols procedures, the LPSC, the APSC, the MPSC, the City Council, and the Mississippi Public Utilities Staff filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2020. This formal challenge was ultimately settled as a result of System Energy’s global settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” above for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.

System Energy Formula Rate Annual Protocols Formal Challenge Concerning 2021 Calendar Year Bills

In March 2023, pursuant to the protocols procedures discussed above, the LPSC, the APSC, and the City Council filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2021. This formal challenge was ultimately settled as a result of System Energy’s global settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” above for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.

System Energy Formula Rate Annual Protocols Formal Challenge Concerning 2022 Calendar Year Bills

In February 2024, pursuant to the protocols procedures, the LPSC and the City Council filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2022. This formal challenge was ultimately settled as a result of System Energy’s global settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” above for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.

Depreciation Amendment Proceeding

In December 2021, System Energy submitted to the FERC proposed amendments to the Unit Power Sales Agreement to adopt updated rates for use in calculating Grand Gulf plant depreciation and amortization expenses. The proposed amendments would result in higher charges to the Utility operating companies that buy capacity and energy from System Energy under the Unit Power Sales Agreement. In February 2022 the FERC accepted System Energy’s proposed increased depreciation rates with an effective date of March 1, 2022, subject to refund pending the outcome of the settlement and/or hearing procedures. In June 2023 System Energy filed with the FERC an unopposed offer of settlement that it had negotiated with intervenors to the proceeding. In August 2023 the FERC approved the settlement, which resolves the proceeding. In third quarter 2023, System Energy recorded a reduction in depreciation expense of $41 million representing the cumulative difference in depreciation expense resulting from the depreciation rates used from March 2022 through June 2023 and the depreciation rates included in the settlement filing approved by the FERC. In October 2023, System Energy filed a refund report with the FERC. The refund provided for in the refund report was included in the September 2023 service month bills under the Unit Power Sales Agreement. No comments or protests to the refund report were filed.

Pension Costs Amendment Proceeding

In October 2021, System Energy submitted to the FERC proposed amendments to the Unit Power Sales Agreement to include in rate base the prepaid and accrued pension costs associated with System Energy’s qualified pension plans. Based on data ending in 2020, the increased annual revenue requirement associated with the filing is approximately $8.9 million. In March 2022 the FERC accepted System Energy’s proposed amendments with an
effective date of December 1, 2021, subject to refund pending the outcome of the settlement and/or hearing procedures. In August 2023 the FERC chief ALJ terminated settlement procedures and designated a presiding ALJ to oversee hearing procedures. Testimony was filed by the parties from October 2023 through April 2024, and the hearing concluded in June 2024.

In September 2024 the presiding ALJ issued an initial decision recommending that the FERC approve inclusion of a line item in rate base for prepaid and accrued pension costs; however, the presiding ALJ did not agree with System Energy’s proposed methodology to calculate the value of the prepaid and accrued pension cost input. Instead, the presiding ALJ recommended limiting System Energy’s recovery to the prepaid and accrued pension costs that were incurred beginning in 2015 and later.

System Energy disputes the presiding ALJ's determination concerning the methodology used to calculate the prepaid and accrued pension input, and System Energy filed exceptions to these rulings in October 2024. In October 2024, the LPSC, the APSC, and the FERC trial staff filed separate briefs on exceptions; these parties generally argue that the presiding ALJ should have rejected System Energy’s filing entirely, rather than limit System Energy’s recovery of the prepaid and accrued pension costs. Later in October 2024, System Energy, the LPSC, the APSC, and the FERC trial staff filed separate briefs opposing exceptions.

If the ALJ’s determination is affirmed by the FERC, System Energy estimates refunds, including interest through December 31, 2024, of approximately $16 million to $21 million would be owed. The ALJ's initial decision is not binding on the FERC and is an interim step in the hearing process. No refunds will be owed in connection with this proceeding and no changes to System Energy’s pension cost recovery methodology will be implemented unless and until the FERC requires them in a final order. This proceeding is not covered by the global settlements described above.
Storm Cost Recovery Filings with Retail Regulators

Entergy Louisiana

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.

In December 2024, and subsequently amended in an errata filed in February 2025, Entergy Louisiana submitted an application to the LPSC seeking a determination that approximately $183.6 million in storm restoration costs associated with Hurricane Francine were reasonable and necessary and, therefore, eligible for recovery from customers, as well as approval to recover approximately $3.6 million in certain carrying costs from customers. The $183.6 million includes approximately $152.8 million in distribution capital costs and approximately $29.8 million in non-capital costs; the balance consists of transmission and generation capital costs. Entergy Louisiana proposes in its application to recover its distribution-related capital costs of $152.8 million through the distribution recovery mechanism of its formula rate plan. Entergy Louisiana has further requested the LPSC to authorize recovery of these distribution-related capital expenses through an interim rate adjustment, subject to true-up and refund, that would begin with the first billing cycle of March 2025. Entergy Louisiana also requested to recover, from its storm reserve escrow account, $33.5 million, which consists of non-capital costs and certain carrying costs. Entergy Louisiana has also proposed to recover the transmission and generation capital costs through separate ratemaking proceedings. In February 2025, Entergy Louisiana withdrew the $33.5 million from its storm reserve escrow account. The period for intervention has expired, and a status conference for the purpose of establishing a procedural schedule has been set for March 2025.
Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida

In August 2020 and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of Entergy Louisiana’s service area. The storms resulted in widespread outages, significant damage to distribution and transmission infrastructure, and the loss of sales during the outages. Additionally, as a result of Hurricane Laura’s extensive damage to the grid infrastructure serving the impacted area, large portions of the underlying transmission system required nearly a complete rebuild.

In October 2020, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments in connection with the issuance of shorter-term mortgage bonds to provide interim financing for restoration costs associated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta. Subsequently, Entergy Louisiana and the LPSC staff filed a joint motion seeking approval to exclude from the derivation of Entergy Louisiana’s capital structure and cost rate of debt for ratemaking purposes, including the allowance for funds used during construction, shorter-term debt up to $1.1 billion issued by Entergy Louisiana to fund costs associated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta costs on an interim basis. In November 2020 the LPSC issued an order approving the joint motion, and Entergy Louisiana issued $1.1 billion of 0.62% Series mortgage bonds due November 2023. Also in November 2020, Entergy Louisiana withdrew $257 million from its funded storm reserves.

In February 2021 two winter storms (collectively, Winter Storm Uri) brought freezing rain and ice to Louisiana. Ice accumulation sagged or downed trees, limbs, and power lines, causing damage to Entergy Louisiana’s transmission and distribution systems. The additional weight of ice caused trees and limbs to fall into power lines and other electric equipment. When the ice melted, it affected vegetation and electrical equipment, causing additional outages. Entergy Louisiana recovered the incremental fuel costs associated with Winter Storm Uri over a five-month period from April 2021 through August 2021.

In April 2021, Entergy Louisiana filed an application with the LPSC relating to Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri restoration costs and in July 2021, Entergy Louisiana made a supplemental filing updating the total restoration costs. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by these storms were estimated to be approximately $2.06 billion, including approximately $1.68 billion in capital costs and approximately $380 million in non-capital costs. Including carrying costs through January 2022, Entergy Louisiana sought an LPSC determination that $2.11 billion was prudently incurred and, therefore, was eligible for recovery from customers. Additionally, Entergy Louisiana requested that the LPSC determine that re-establishment of a storm escrow account to the previously authorized amount of $290 million was appropriate. In July 2021, Entergy Louisiana supplemented the application with a request regarding the financing and recovery of the recoverable storm restoration costs. Specifically, Entergy Louisiana requested approval to securitize its restoration costs pursuant to Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021.

In August 2021, Hurricane Ida caused extensive damage to Entergy Louisiana’s distribution and, to a lesser extent, transmission systems resulting in widespread power outages. In September 2021, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments in connection with the issuance of approximately $1 billion of shorter-term mortgage bonds to provide interim financing for restoration costs associated with Hurricane Ida, which bonds were issued in October 2021. Also in September 2021, Entergy Louisiana sought approval for the creation and funding of a $1 billion restricted escrow account for Hurricane Ida related restoration costs, subject to a subsequent prudence review.

After filing of testimony by the LPSC staff and intervenors, which generally supported or did not oppose Entergy Louisiana’s requests in regard to Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida, the parties negotiated and executed an uncontested stipulated settlement which was filed with the LPSC in February 2022. The settlement agreement contained the following key terms: $2.1 billion of restoration costs from Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri were prudently incurred and
eligible for recovery; carrying costs of $51 million were recoverable; a $290 million cash storm reserve should be re-established; a $1 billion reserve should be established to partially pay for Hurricane Ida restoration costs; and Entergy Louisiana was authorized to finance $3.186 billion utilizing the securitization process authorized by Act 55, as supplemented by Act 293. The LPSC issued an order approving the settlement in March 2022. As a result of the financing order, Entergy Louisiana reclassified $1.942 billion from utility plant to other regulatory assets.

In May 2022 the securitization financing closed, resulting in the issuance of $3.194 billion principal amount of bonds by Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA), a political subdivision of the State of Louisiana. The securitization was authorized pursuant to the Louisiana Utilities Restoration Corporation Act, Part VIII of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana legislature approved in 2021. The LCDA loaned the proceeds to the LURC. Pursuant to Act 293, the LURC contributed the net bond proceeds to a State legislatively authorized and LURC-sponsored trust, Restoration Law Trust I (the storm trust I).

Pursuant to Act 293, the net proceeds of the bonds were used by the storm trust I to purchase 31,635,718.7221 Class A preferred, non-voting membership interest units (the preferred membership interests) issued by Entergy Finance Company. Entergy Finance Company is required to make annual distributions (dividends) commencing on December 15, 2022 on the preferred membership interests issued to the storm trust I. These annual dividends received by the storm trust I will be distributed to Entergy Louisiana and the LURC, as beneficiaries of the storm trust I. Specifically, 1% of the annual dividends received by the storm trust I will be distributed to the LURC, for the benefit of customers, and 99% will be distributed to Entergy Louisiana, net of storm trust expenses. The preferred membership interests have a stated annual cumulative cash dividend rate of 7% and a liquidation price of $100 per unit. The terms of the preferred membership interests include certain financial covenants to which Entergy Finance Company is subject. Semi-annual redemptions of the preferred membership interests, subject to certain conditions, are expected to occur over the next 15 years.

Entergy and Entergy Louisiana do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA. The bonds are secured by system restoration property, which is the right granted by law to the LURC to collect a system restoration charge from customers. The system restoration charge is adjusted at least semi-annually to ensure that it is sufficient to service the bonds. Entergy Louisiana collects the system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee. Entergy Louisiana began collecting the system restoration charge effective with the first billing cycle of June 2022 and the system restoration charge is expected to remain in place for up to 15 years. Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as a billing and collection agent for the LCDA and the LURC. In the remote possibility that the system restoration charge, as well as any funds in the excess subaccount and funds in the debt service reserve account, are insufficient to service the bonds resulting in a payment default, the storm trust I is required to liquidate Entergy Finance Company preferred membership interests in an amount equal to what would be required to cure the default. The estimated value of this indirect guarantee is immaterial.

From the proceeds from the issuance of the preferred membership interests, Entergy Finance Company distributed $1.4 billion to its parent, Entergy Holdings Company, LLC, a company wholly-owned and consolidated by Entergy. Subsequently, Entergy Holdings Company liquidated, distributing the $1.4 billion it received from Entergy Finance Company to Entergy Louisiana as holder of 6,843,780.24 units of Class A, 4,126,940.15 units of Class B, and 2,935,152.69 units of Class C preferred membership interests. Entergy Louisiana had acquired these preferred membership interests with proceeds from previous securitizations of storm restoration costs. Entergy Finance Company loaned the remaining $1.7 billion from the preferred membership interests proceeds to Entergy which used the cash to redeem $650 million of 4.00% Series senior notes due July 2022 and indirectly contributed $1 billion to Entergy Louisiana as a capital contribution.

Entergy Louisiana used the $1 billion capital contribution to fund its Hurricane Ida escrow account and subsequently withdrew the $1 billion from the escrow account. With a portion of the $1 billion withdrawn from the
escrow account and the $1.4 billion from the Entergy Holdings Company liquidation, Entergy Louisiana deposited $290 million in a restricted escrow account as a storm damage reserve for future storms, used $1.2 billion to repay its unsecured term loan due June 2023, and used $435 million to redeem a portion of its 0.62% Series mortgage bonds due November 2023.

As discussed in Note 3 to the financial statements, the securitization resulted in recognition of a reduction of income tax expense of approximately $290 million by Entergy Louisiana. Entergy’s recognition of reduced income tax expense was partially offset by other tax charges resulting in a net reduction of income tax expense of $283 million. In recognition of obligations described in an LPSC ancillary order issued as part of the securitization regulatory proceeding, Entergy Louisiana recorded a $224 million ($165 million net-of-tax) regulatory charge and a corresponding regulatory liability to reflect its obligation to provide credits to its customers.

As discussed in Note 6 and Note 17 to the financial statements, Entergy Louisiana consolidates the storm trust I as a variable interest entity and the LURC’s 1% beneficial interest is presented as noncontrolling interest in the financial statements. In second quarter 2022, Entergy Louisiana recorded a charge of $31.6 million in other income to reflect the LURC’s beneficial interest in the storm trust I.

In April 2022, Entergy Louisiana filed an application with the LPSC relating to Hurricane Ida restoration costs. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by Hurricane Ida were estimated to be approximately $2.54 billion, including approximately $1.96 billion in capital costs and approximately $586 million in non-capital costs. Including carrying costs of $57 million through December 2022, Entergy Louisiana was seeking an LPSC determination that $2.60 billion was prudently incurred and, therefore, eligible for recovery from customers. As part of this filing, Entergy Louisiana also was seeking an LPSC determination that an additional $32 million in costs associated with the restoration of Entergy Louisiana’s electric facilities damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta as well as Winter Storm Uri was prudently incurred. This amount was exclusive of the requested $3 million in carrying costs through December 2022. In total, Entergy Louisiana was requesting an LPSC determination that $2.64 billion was prudently incurred and, therefore, eligible for recovery from customers. As discussed above, in March 2022 the LPSC approved financing of a $1 billion storm escrow account from which funds were withdrawn to finance costs associated with Hurricane Ida restoration. In June 2022, Entergy Louisiana supplemented the application with a request regarding the financing and recovery of the recoverable storm restoration costs. Specifically, Entergy Louisiana requested approval to securitize its restoration costs pursuant to Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021. In October 2022 the LPSC staff recommended a finding that the requested storm restoration costs of $2.64 billion, including associated carrying costs of $59.1 million, were prudently incurred and eligible for recovery from customers. The LPSC staff further recommended approval of Entergy Louisiana’s plans to securitize these costs, net of the $1 billion in funds withdrawn from the storm escrow account described above. The parties negotiated and executed an uncontested stipulated settlement which was filed with the LPSC in December 2022. The settlement agreement contains the following key terms: $2.57 billion of restoration costs from Hurricane Ida, Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri were prudently incurred and eligible for recovery; carrying costs of $59.2 million were recoverable; and Entergy Louisiana was authorized to finance $1.657 billion utilizing the securitization process authorized by Act 55, as supplemented by Act 293. A procedural motion to consider the uncontested settlement at the December 2022 LPSC meeting did not pass and the settlement was not voted on. In January 2023 an ALJ with the LPSC conducted a settlement hearing to receive the uncontested settlement and supporting testimony into evidence and issued a report of proceedings, which allows the LPSC to consider the uncontested settlement without the procedural motion that did not pass in December. In January 2023 the LPSC approved the stipulated settlement subject to certain modifications. These modifications include the recognition of accumulated deferred income tax benefits related to damaged assets and system restoration costs as a reduction of the amount authorized to be financed utilizing the securitization process authorized by Act 55, as supplemented by Act 293, from $1.657 billion to $1.491 billion. These modifications did not affect the LPSC’s conclusion that all system restoration costs sought by Entergy Louisiana were reasonable and prudent. In February 2023 the Louisiana Bond Commission voted to authorize the LCDA to issue the bonds authorized in the LPSC’s financing order.
In March 2023 the Hurricane Ida securitization financing closed, resulting in the issuance of approximately $1.491 billion principal amount of bonds by the LCDA and a remaining regulatory asset of $180 million to be recovered through the exclusion of the accumulated deferred income taxes related to damaged assets and system restoration costs from the determination of future rates. The securitization was authorized pursuant to the Louisiana Utilities Restoration Corporation Act, Part VIII of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021. The LCDA loaned the proceeds to the LURC. Pursuant to Act 293, the LURC contributed the net bond proceeds to a State legislatively authorized and LURC-sponsored trust, Restoration Law Trust II (the storm trust II).

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

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

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

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

As discussed in Note 6 and Note 17 to the financial statements, Entergy Louisiana consolidates the storm trust II as a variable interest entity and the LURC’s 1% beneficial interest is presented as noncontrolling interest in
the financial statements. In first quarter 2023, Entergy Louisiana recorded a charge of $14.6 million in other income to reflect the LURC’s beneficial interest in the storm trust II.

Hurricane Isaac

In August 2012, Hurricane Isaac caused extensive damage to Entergy Louisiana’s service area.  In June 2014 the LPSC authorized Entergy Louisiana to utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs.  Entergy Louisiana committed to pass on to customers a minimum of $30.8 million of customer benefits through annual customer credits of approximately $6.2 million for five years. Approvals for the Act 55 financings were obtained from the LURC and the Louisiana State Bond Commission.

In August 2014 the LCDA issued $314.85 million in bonds under Louisiana Act 55.  From the $309 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $16 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $293 million directly to Entergy Louisiana.  Entergy Louisiana used the $293 million received from the LURC to acquire 2,935,152.69 Class C preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 7.5% annual distribution rate. Distributions were payable quarterly commencing on September 15, 2014, and the membership interests had a liquidation price of $100 per unit. The preferred membership interests were callable at the option of Entergy Holdings Company after ten years under the terms of the LLC agreement. The terms of the membership interests included certain financial covenants to which Entergy Holdings Company was subject, including the requirement to maintain a net worth of at least $1.75 billion. As discussed above in “Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida”, in May 2022, Entergy Holdings Company liquidated and distributed cash to Entergy Louisiana as holder of the 2,935,152.69 units of Class C preferred membership interests.

Entergy and Entergy Louisiana do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA and there is no recourse against Entergy or Entergy Louisiana in the event of a bond default.  To service the bonds, Entergy Louisiana collects a system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee.  Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as the billing and collection agent for the state.

Hurricane Gustav and Hurricane Ike

In September 2008, Hurricane Gustav and Hurricane Ike caused catastrophic damage to Entergy Louisiana’s service territory.  In December 2009, Entergy Louisiana entered into a stipulation agreement with the LPSC staff regarding its storm costs.  In March and April 2010, Entergy Louisiana and other parties to the proceeding filed with the LPSC an uncontested stipulated settlement that included Entergy Louisiana’s proposal to utilize Act 55 financing, which included a commitment to pass on to customers a minimum of $43.3 million of customer benefits through a prospective annual rate reduction of $8.7 million for five years.  In April 2010 the LPSC approved the settlement and subsequently issued financing orders and a ratemaking order intended to facilitate the implementation of the Act 55 financings.  In June 2010 the Louisiana State Bond Commission approved the Act 55 financing. The settlement agreement allowed for an adjustment to the credits if there was a change in the applicable federal or state income tax rate. As a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, and the lowering of the federal corporate income tax rate from 35% to 21%, the Louisiana Act 55 financing savings obligation regulatory liability related to Hurricane Gustav and Hurricane Ike was reduced by $2.7 million, with a corresponding increase to Other regulatory credits on the income statement. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.

In July 2010 the LCDA issued two series of bonds totaling $713.0 million under Act 55.  From the $702.7 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $290 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $412.7 million directly to Entergy Louisiana.  From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana
used $412.7 million to acquire 4,126,940.15 Class B preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 9% annual distribution rate. Distributions were payable quarterly commencing on September 15, 2010, and the membership interests had a liquidation price of $100 per unit. The preferred membership interests were callable at the option of Entergy Holdings Company after ten years under the terms of the LLC agreement.  The terms of the membership interests included certain financial covenants to which Entergy Holdings Company was subject, including the requirement to maintain a net worth of at least $1 billion. As discussed above in “Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida”, in May 2022, Entergy Holdings Company liquidated and distributed cash to Entergy Louisiana as holder of the 4,126,940.15 units of Class B preferred membership interests.

The bonds were repaid in 2022. Entergy and Entergy Louisiana did not report the bonds issued by the LCDA on their balance sheets because the bonds were the obligation of the LCDA, and there was no recourse against Entergy or Entergy Louisiana in the event of a bond default.  To service the bonds, Entergy Louisiana collected a system restoration charge on behalf of the LURC and remitted the collections to the bond indenture trustee.  Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as the billing and collection agent for the state.

Hurricane Katrina and Hurricane Rita

In August and September 2005, Hurricanes Katrina and Rita caused catastrophic damage to Entergy Louisiana’s service territory. In March 2008, Entergy Louisiana and the LURC filed at the LPSC an application requesting that the LPSC grant a financing order authorizing the financing of Entergy Louisiana storm costs, storm reserves, and issuance costs pursuant to Louisiana Act 55.  Entergy Louisiana also filed an application requesting LPSC approval for ancillary issues including the mechanism to flow charges and savings to customers via a storm cost offset rider.  In April 2008 the Louisiana Public Facilities Authority (LPFA), which is the issuer of the bonds pursuant to the Act 55 financing, approved requests for the Act 55 financing.  Also in April 2008, Entergy Louisiana and the LPSC staff filed with the LPSC an uncontested stipulated settlement that included Entergy Louisiana’s proposal under the Act 55 financing, which included a commitment to pass on to customers a minimum of $40 million of customer benefits through a prospective annual rate reduction of $8 million for five years.  The LPSC subsequently approved the settlement and issued two financing orders and one ratemaking order intended to facilitate implementation of the Act 55 financing.  In May 2008 the Louisiana State Bond Commission granted final approval of the Act 55 financing. The settlement agreement allowed for an adjustment to the credits if there was a change in the applicable federal or state income tax rate. As a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, and the lowering of the federal corporate income tax rate from 35% to 21%, the Louisiana Act 55 financing savings obligation regulatory liability related to Hurricanes Katrina and Rita was reduced by $22.3 million, with a corresponding increase to Other regulatory credits on the income statement. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.

In July 2008 the LPFA issued $687.7 million in bonds under the aforementioned Act 55.  From the $679 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $152 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $527 million directly to Entergy Louisiana.  From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $545 million, including $17.8 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 5,449,861.85 Class A preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 10% annual distribution rate.  In August 2008 the LPFA issued $278.4 million in bonds under the aforementioned Act 55.  From the $274.7 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $87 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $187.7 million directly to Entergy Louisiana.  From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $189.4 million, including $1.7 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 1,893,918.39 Class A preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 10% annual distribution rate.  Distributions were payable quarterly commencing on September 15, 2008 and had a
liquidation price of $100 per unit.  The preferred membership interests were callable at the option of Entergy Holdings Company after ten years under the terms of the LLC agreement.  The terms of the membership interests included certain financial covenants to which Entergy Holdings Company was subject, including the requirement to maintain a net worth of at least $1 billion.  In February 2012, Entergy Louisiana sold 500,000 of its Class A preferred membership units in Entergy Holdings Company to a third party. Those preferred membership units were subsequently repurchased by Entergy Holdings Company in March 2019. As discussed above in “Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida”, in May 2022, Entergy Holdings Company liquidated and distributed cash to Entergy Louisiana as holder of the remaining 6,843,780.24 units of Class A preferred membership interests.

The bonds were repaid in 2018. Entergy and Entergy Louisiana did not report the bonds issued by the LPFA on their balance sheets because the bonds were the obligation of the LPFA, and there was no recourse against Entergy or Entergy Louisiana in the event of a bond default.  To service the bonds, Entergy Louisiana collected a system restoration charge on behalf of the LURC and remitted the collections to the bond indenture trustee.  Entergy and Entergy Louisiana did not report the collections as revenue because Entergy Louisiana was merely acting as the billing and collection agent for the state.

Entergy Mississippi

Prior to June 2024, Entergy Mississippi had approval from the MPSC to collect a storm damage provision of $1.75 million per month. If Entergy Mississippi’s accumulated storm damage provision balance exceeded $15 million, the collection of the storm damage provision ceased until such time that the accumulated storm damage provision became less than $10 million. Entergy Mississippi’s storm damage provision balance had been less than $10 million since May 2019, and Entergy Mississippi had been billing the monthly storm damage provision since July 2019.

In December 2023, Entergy Mississippi filed a Notice of Storm Escrow Disbursement and Request for Interim Relief notifying the MPSC that Entergy Mississippi had requested disbursement of approximately $34.5 million of storm escrow funds from its restricted storm escrow account. The filing also requested authorization from the MPSC, on a temporary basis, that the $34.5 million of storm escrow funds be credited to Entergy Mississippi’s storm damage provision, pending the MPSC’s review of Entergy Mississippi’s storm-related costs, and that Entergy Mississippi continue to bill its monthly storm damage provision without suspension in the event the storm damage provision balance exceeded $15 million, in anticipation of a subsequent filing by Entergy Mississippi in this proceeding. The storm damage provision exceeded $15 million upon receipt of the storm escrow funds. Because the MPSC had not entered an order on Entergy Mississippi’s filing on the requested relief to continue billing this provision, Entergy Mississippi suspended billing the monthly storm damage provision effective with February 2024 bills.

In March 2024, Entergy Mississippi made a combined dual filing which included a notice of intent to make routine change in rates and schedules and a motion for determination relating to the above-described notice of storm escrow disbursement. The notice of intent proposed a new storm damage mitigation and restoration rider to supersede both the then-current storm damage rate schedule and the vegetation management rider schedule, in which the collection of both expenses would be combined. The proposal requested that the MPSC authorize Entergy Mississippi to collect approximately $5.2 million per month for vegetation management and a storm damage provision. Furthermore, if Entergy Mississippi’s accumulated vegetation management and storm damage provision balance were to exceed $70 million, collection under the storm damage mitigation and restoration rider would cease until such time that the accumulated vegetation management and storm damage provision would become less than $60 million.

The Mississippi Public Utilities Staff reviewed the storm-related costs submitted by Entergy Mississippi and found them prudent. In June 2024 the MPSC considered and unanimously granted the relief sought by Entergy Mississippi, including authorization to credit any remaining funds in the storm escrow account to Entergy
Mississippi’s storm damage provision and to close the storm escrow account and approving the new storm damage mitigation and restoration rider. Entergy Mississippi’s storm escrow account was liquidated in July 2024, and the new combined storm damage mitigation and restoration rider became effective with the July 2024 billing cycle. Additionally, Entergy Mississippi made a compliance filing to cease billing under the existing vegetation management rider schedule as of the same billing cycle.

Entergy New Orleans

Hurricane Ida

In August 2021, Hurricane Ida caused significant damage to Entergy New Orleans’s service area, including Entergy’s electrical grid. The storm resulted in widespread power outages, including the loss of 100% of Entergy New Orleans’s load and damage to distribution and transmission infrastructure, including the loss of connectivity to the eastern interconnection. In September 2021, Entergy New Orleans withdrew $39 million from its funded storm reserves. In June 2022, Entergy New Orleans filed an application with the City Council requesting approval and certification that storm restoration costs associated with Hurricane Ida of approximately $170 million, which included $11 million in estimated costs, were reasonable, necessary, and prudently incurred to enable Entergy New Orleans to restore electric service to its customers and to repair Entergy New Orleans’s electric utility infrastructure. In addition, estimated carrying costs through December 2022 related to Hurricane Ida restoration costs were $9 million. Also, Entergy New Orleans requested approval that the $39 million withdrawal from its funded storm reserve in September 2021 and $7 million in excess storm reserve escrow withdrawals related to Hurricane Zeta in October 2020 and prior miscellaneous storms were properly applied to Hurricane Ida storm restoration costs, the application of which reduced the amount to be recovered from Entergy New Orleans customers by $46 million.

Additionally, in February 2022, Entergy New Orleans and the LURC filed with the City Council a securitization application requesting that the City Council review Entergy New Orleans’s storm reserve and increase the storm reserve funding level to $150 million, to be funded through securitization. In August 2022 the City Council’s advisors recommended that the City Council authorize a single securitization bond issuance to fund Entergy New Orleans’s storm recovery reserves to an amount sufficient to: (1) allow recovery of all of Entergy New Orleans’s unrecovered storm recovery costs following Hurricane Ida, subject to City Council review and certification; (2) provide initial funding of storm recovery reserves for future storms to a level of $75 million; and (3) fund the storm recovery bonds’ upfront financing costs. In September 2022, Entergy New Orleans and the City Council’s advisors entered into an agreement in principle, which was approved by the City Council along with a financing order in October 2022, which authorized Entergy New Orleans and the LURC to proceed with a single securitization bond issuance of approximately $206 million (subject to further adjustment and review pursuant to the Final Issuance Advice Letter process set forth in the financing order), with $125 million of that total to be used for interim recovery, subject to City Council review and certification, to be allocated to unrecovered Hurricane Ida storm recovery costs; $75 million of that total to provide for a storm recovery reserve for future storms; and the remainder to fund the recovery of the storm recovery bonds’ upfront financing costs.

In December 2022, Entergy New Orleans and the LURC filed with the City Council the Final Issuance Advice Letter for a securitization bond issuance in the amount of $209.3 million, the final structuring, terms, and pricing of which were approved by the City Council in accordance with the financing order. Also in December 2022 the LCDA issued $209.3 million in bonds pursuant to the Louisiana Electric Utility Storm Recovery Securitization Act, Part V-B of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana Regular Session of 2021. The LCDA loaned $201.8 million of bond proceeds, net of certain debt service and issuance costs, to the LURC. The LURC used the proceeds to purchase from Entergy New Orleans the storm recovery property, which is the right to collect storm recovery charges sufficient to pay the storm recovery bonds and associated financing costs, and Entergy New Orleans deposited $200 million in a restricted storm reserve escrow account as a storm damage reserve for Entergy New Orleans and received directly $1.8 million in estimated upfront financing costs. Subsequently, Entergy New Orleans withdrew $125 million from the newly securitized
storm reserve to cover Hurricane Ida storm recovery costs, subject to a final determination from the City Council regarding the prudency of the storm recovery costs.

Entergy and Entergy New Orleans do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA, and there is no recourse against Entergy or Entergy New Orleans in the event of a bond default. To service the bonds, Entergy New Orleans collects a storm recovery charge on behalf of the LURC and remits the collections to the bond indenture trustee. Entergy and Entergy New Orleans do not report the collections as revenue because Entergy New Orleans is merely acting as the billing and collection agent for the LURC.

In August 2023 the City Council advisors issued a report recommending that the City Council find that Entergy New Orleans prudently incurred approximately $164.1 million in storm restoration costs and $7.5 million in carrying charges and that such costs have already been properly recovered by Entergy New Orleans through withdrawals from the storm reserve escrow account. The City Council advisors also recommended that the City Council find that approximately $1.2 million in storm restoration costs had already been recovered through Entergy New Orleans’s base rates and that approximately $0.9 million in unused credits be applied against future storm costs. In August 2023 the City Council hearing officer certified the evidentiary record. In December 2023 the City Council approved a resolution adopting the advisors’ report and recommendations.

Entergy Texas

Hurricane Laura, Hurricane Delta, and Winter Storm Uri

In August 2020 and October 2020, Hurricane Laura and Hurricane Delta caused extensive damage to Entergy Texas’s service area. In February 2021, Winter Storm Uri also caused damage to Entergy Texas’s service area. The storms resulted in widespread power outages, significant damage primarily to distribution and transmission infrastructure, and the loss of sales during the power outages. In April 2021, Entergy Texas filed an application with the PUCT requesting a determination that approximately $250 million of system restoration costs associated with Hurricane Laura, Hurricane Delta, and Winter Storm Uri, including approximately $200 million in capital costs and approximately $50 million in non-capital costs, were reasonable and necessary to enable Entergy Texas to restore electric service to its customers and Entergy Texas’s electric utility infrastructure. The filing also included the projected balance of approximately $13 million of a regulatory asset containing previously approved system restoration costs related to Hurricane Harvey. In September 2021 the parties filed an unopposed settlement agreement, pursuant to which Entergy Texas removed from the amount to be securitized approximately $4.3 million that will instead be charged to its storm reserve, $5 million related to no particular issue, of which Entergy Texas would be permitted to seek recovery in a future proceeding, and approximately $300 thousand related to attestation costs. In December 2021 the PUCT issued an order approving the unopposed settlement and determining system restoration costs of $243 million related to Hurricane Laura, Hurricane Delta, and Winter Storm Uri and the $13 million projected remaining balance of the Hurricane Harvey system restoration costs were eligible for securitization. The order also determines that Entergy Texas can recover carrying costs on the system restoration costs related to Hurricane Laura, Hurricane Delta, and Winter Storm Uri.

In July 2021, Entergy Texas filed with the PUCT an application for a financing order to approve the securitization of the system restoration costs that are the subject of the April 2021 application. In November 2021 the parties filed an unopposed settlement agreement supporting the issuance of a financing order consistent with Entergy Texas’s application and with minor adjustments to certain upfront and ongoing costs to be incurred to facilitate the issuance and serving of system restoration bonds. In January 2022 the PUCT issued a financing order consistent with the unopposed settlement. As a result of the financing order, Entergy Texas reclassified $153 million from utility plant to other regulatory assets.

In April 2022, Entergy Texas Restoration Funding II, LLC, a company wholly-owned and consolidated by Entergy Texas, issued $290.85 million of senior secured system restoration bonds (securitization bonds). With the
proceeds, Entergy Texas Restoration Funding II purchased from Entergy Texas the transition property, which is the right to recover from customers through a system restoration charge amounts sufficient to service the securitization bonds. Entergy Texas began cost recovery through the system restoration charge effective with the first billing cycle of May 2022 and the system restoration charge is expected to remain in place up to 15 years. See Note 5 to the financial statements for a discussion of the April 2022 issuance of the securitization bonds.