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 probable future revenues associated with costs that Entergy expects to recover from customers through the regulatory ratemaking process under which the Utility business operates. Regulatory liabilities represent probable future reductions in revenues associated with amounts that Entergy expects to benefit customers through the regulatory ratemaking process under which the Utility business operates. 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, 2020 and 2019:

Other Regulatory Assets

Entergy


	2020	2019
	(In Millions)
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)	$3,027.5	$2,942.4
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	1,018.9	920.4
Removal costs (Note 9)	893.8	421.0
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Hurricane Laura, Hurricane Delta, and Hurricane Zeta and Storm Cost Recovery Filings with Retail Regulators and Note 5 - Securitization Bonds)	379.2	372.8
Retired electric and gas meters - recovered through retail rates as determined by retail regulators	192.1	205.6
Opportunity Sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding) (b)	131.8	116.3
Deferred COVID-19 costs recovery period to be determined (Note 2 - Retail Rate Proceedings) (b)	105.7	—
Unamortized loss on reacquired debt - recovered over term of debt	79.2	66.6
Retail rate deferrals - recovered through rate riders as rates are redetermined by retail regulators	66.0	15.7
Attorney General litigation costs - recovered over a six-year period through March 2026 (b)	25.3	29.5
New nuclear generation development costs - recovery through formula rate plan December 2014 through November 2022 (b)	14.2	21.6
Little Gypsy costs – recovered through securitization (Note 5 - Entergy Louisiana Securitization Bonds - Little Gypsy)	7.5	29.9



Other	135.3	150.3
Entergy Total	$6,076.5	$5,292.1

Entergy Arkansas


	2020	2019
	(In Millions)
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)	$831.5	$796.5
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	479.3	433.0
Removal costs (Note 9)	212.6	168.9
Opportunity sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding) (b)	131.8	116.3
Retired electric meters - recovered over 15-year period through March 2034	46.9	50.4
Storm damage costs - recovered either through securitization or retail rates (Note 5 - Entergy Arkansas Securitization Bonds)	42.7	46.1
Unamortized loss on reacquired debt - recovered over term of debt	24.7	18.3
Retail rate deferrals - recovered through rate riders as rates are redetermined annually (b)	12.6	2.3
Deferred COVID-19 costs - recovery period to be determined (Note 2 - Retail Rate Proceedings) (b)	10.5	—
ANO Fukushima and Flood Barrier costs - recovered through retail rates through February 2026 (Note 2 - Retail Rate Proceedings) (b)	9.1	10.9
Other	30.7	24.2
Entergy Arkansas Total	$1,832.4	$1,666.9

Entergy Louisiana


	2020	2019
	(In Millions)
Pension & postretirement costs (Note 11 - Qualified Pension Plans and Non-Qualified Pension Plans) (a)	$799.4	$787.7
Removal costs (Note 9)	302.5	—
Asset Retirement Obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	299.0	262.5
Retired electric meters - recovered over a 22-year period through July 2041	96.4	101.1
Storm damage costs - recovered through retail rates (Note 2 - Hurricane Laura, Hurricane Delta, and Hurricane Zeta and Storm Cost Recovery Filings with Retail Regulators)	94.0	45.7
Deferred COVID-19 costs - recovery period to be determined (Note 2 - Retail Rate Proceedings) (b)	48.8	—
Unamortized loss on reacquired debt - recovered over term of debt	26.6	20.4
New nuclear generation development costs - recovery through formula rate plan December 2014 through November 2022 (b)	14.0	21.2
Business combination external costs deferral - recovery through formula rate plan December 2015 through November 2025 (b)	9.2	10.8
River Bend AFUDC - recovered through August 2025 (Note 1 - River Bend AFUDC)	7.2	9.1
Little Gypsy costs – recovered through securitization (Note 5 - Entergy Louisiana Securitization Bonds - Little Gypsy)	5.1	27.6
Other	23.9	29.1
Entergy Louisiana Total	$1,726.1	$1,315.2

Entergy Mississippi


	2020	2019
	(In Millions)
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)	$242.7	$234.4
Removal costs (Note 9)	107.3	80.8
Retail rate deferrals - returned through rate riders as rates are redetermined annually	44.3	7.5
Attorney General litigation costs - recovered over a six-year period through March 2026 (b)	25.3	29.5
Deferred COVID-19 costs - recovery period to be determined (Note 2 - Retail Rate Proceedings) (b)	19.2	—
Unamortized loss on reacquired debt - recovered over term of debt	13.5	14.9
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a)	7.9	7.8
Other	7.1	3.1
Entergy Mississippi Total	$467.3	$378.0

Entergy New Orleans


	2020	2019
	(In Millions)
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)	$75.7	$85.9
Removal costs - (Note 9)	63.2	52.9
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Hurricane Laura, Hurricane Delta, and Hurricane Zeta and Note 5 - Entergy New Orleans Securitization Bonds - Hurricane Isaac)	55.2	59.6
Retired meters - recovered over a 12-year period through July 2031 (b)	21.7	24.6
Deferred COVID-19 costs recovery period to be determined (Note 2 - Retail Rate Proceedings) (b)	14.3	—

Rate case costs - recovered over a three-year period through July 2022 (Note 2 - Retail Rate Proceedings)	5.7	7.0
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a)	5.2	4.9
New Orleans Power Station deferral – recovered over a five-year period through October 2025 (Note 2 - Retail Rate Proceedings)	5.0	—

Algiers customer migration costs - recovered over a five-year period through July 2024 (Note 2 - Retail Rate Proceedings)	3.9	4.9
Unamortized loss on reacquired debt - recovered over term of debt	1.9	2.3

Other	15.0	17.3
Entergy New Orleans Total	$266.8	$259.4

Entergy Texas


	2020	2019
	(In Millions)
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Hurricane Laura, Hurricane Delta, and Hurricane Zeta and Note 5 - Entergy Texas Securitization Bonds)	$187.3	$221.4
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)	140.1	167.7
Removal costs (Note 9)	115.3	42.5
Retired electric meters - recovered over 13-year period through February 2032	26.0	28.4
Neches and Sabine costs - recovered over a 10-year period through September 2028 (Note 2 - Retail Rate Proceedings)	18.8	21.2
Deferred COVID-19 costs recovery period to be determined (Note 2 - Retail Rate Proceedings) (b)	12.9	—
Unamortized loss on reacquired debt - recovered over term of debt	10.5	7.7
Transition to competition costs - recovered over a 15-year period through February 2021	2.1	14.9

Other	11.7	8.8
Entergy Texas Total	$524.7	$512.6

System Energy


	2020		2019
	(In Millions)
Asset retirement obligation - recovery dependent upon timing of decommissioning (Note 9) (a)	$226.3		$210.9
Pension & postretirement costs (Note 11 - Qualified Pension Plans and Other Postretirement Benefits) (a)	217.8		200.3
Removal costs - recovered through depreciation rates (Note 9)	92.9		75.9
Unamortized loss on reacquired debt - recovered over term of debt	2.0		3.0
System Energy Total	$	539.0	$	490.1

(a)Does not earn a return on investment, but is offset by related liabilities.

(b)Does not earn a return on investment.

Hurricane Laura, Hurricane Delta, and Hurricane Zeta

In August and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of the Utility’s service territories in Louisiana, including New Orleans, Texas, and, to a lesser extent, in Arkansas and Mississippi. The storms resulted in widespread power 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. Total restoration costs for the repair and/or replacement of the electrical system damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta are currently estimated to be approximately $2.4 billion, including $2.0 billion at Entergy Louisiana, $300 million at Entergy Texas, and $40 million at Entergy New Orleans. The estimate includes approximately $1.98 billion in capital costs, including $1.67 billion at Entergy Louisiana, $245 million at Entergy Texas, and $30 million at Entergy New Orleans and approximately $420 million in non-capital costs, including $330 million at Entergy Louisiana, $55 million at Entergy Texas, and $10 million at Entergy New Orleans. This estimate includes all costs to restore power and repair or replace the damages from the hurricanes, except for the cost to repair or replace damage incurred to an Entergy Louisiana transmission line in southeast Louisiana, and the amount of that cost could be significant. The restoration plan for this transmission line and the related cost estimate is still being evaluated.

Entergy recorded accounts payable and corresponding construction work in progress and regulatory assets for the estimated costs incurred that were necessary to return customers to service. Entergy recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. There are well-established mechanisms and precedent for addressing these catastrophic events and providing for recovery of prudently incurred storm costs in accordance with applicable regulatory and legal principles. Because Entergy has not gone through the regulatory process regarding these storm costs, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.

The Utility operating companies are considering all available avenues to recover storm-related costs from Hurricane Laura, Hurricane Delta, and Hurricane Zeta including accessing funded storm reserve escrows and securitization. In November 2020, Entergy Louisiana drew $257 million from its funded storm reserves. Each Utility operating company is responsible for its restoration cost obligations and for recovering or financing its storm-related costs. Storm cost recovery or financing will be subject to review by applicable regulatory authorities.

In October 2020, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments to facilitate issuance of shorter-term 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.

In December 2020, Entergy Louisiana provided the LPSC with notification that it intends to initiate a storm cost recovery proceeding in the near future, which will permit the LPSC to retain any outside consultants and counsel needed to review the storm cost recovery application. In February 2021 the LPSC voted to retain outside counsel and consultants to assist in the review of Entergy Louisiana’s upcoming storm cost recovery application, which is expected to be filed in March 2021.

Other Regulatory Liabilities

Entergy


	2020	2019
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)	$1,694.1	$1,300.1
Louisiana Act 55 financing savings obligation (Note 3) (b)	144.3	97.1
Vidalia purchased power agreement (Note 8) (b)	115.7	127.3
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually	75.1	62.3
Grand Gulf sale-leaseback - (Note 5 - Grand Gulf Sale-Leaseback Transactions)	55.6	55.6
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
Future formula rate plan revenue reductions (Note 2 - Retail Rate Proceedings)	43.5	51.1
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)	29.7	37.2
Internal restructuring guaranteed tax credits (Note 2 - Internal Restructuring)	26.4	33.0
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates December 2015 through November 2024	21.5	35.7
Advanced metering system (AMS) surcharge - return to customers dependent upon AMS spend	20.1	25.3
Excess decommissioning recovery for Willow Glen - (Note 14 - Dispositions)	—	21.2
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement	10.7	17.8
Income tax rate change - returned to electric and gas customers through retail rates (Note 2 - Retail Rate Proceedings)	7.3	13.9


Other	35.5	39.0
Entergy Total	$2,323.9	$1,961.0

Entergy Arkansas


	2020	2019
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)	$597.4	$460.3

Future formula rate plan revenue reductions (Note 2 - Retail Rate Proceedings)	43.5	46.6
Internal restructuring guaranteed customer credits (Note 2 - Retail Rate Proceedings)	26.4	33.0
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually	19.6	19.7

Entergy Arkansas Total	$686.9	$559.6

Entergy Louisiana


	2020	2019
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)	$567.7	$436.5
Louisiana Act 55 financing savings obligation (Note 3)	144.3	97.1
Vidalia purchased power agreement (Note 8) (b)	115.7	127.3
Asset Retirement Obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)	29.7	37.1
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates December 2015 through November 2024	21.5	35.7


Excess decommissioning recovery for Willow Glen - returned over one-year period through retail rates (Note 14 - Dispositions)	—	21.2




Other	39.4	39.2
Entergy Louisiana Total	$918.3	$794.1

Entergy Mississippi


	2020	2019
	(In Millions)
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually	$14.2	$14.6
Grand Gulf Over-Recovery - returned to customers through rate riders as rates are redetermined annually	1.0	2.4
Future formula rate plan revenue reductions (Note 2 - Retail Rate Proceedings)	—	4.5
Other	0.6	—
Entergy Mississippi Total	$15.8	$21.5

Entergy Texas


	2020	2019
	(In Millions)
Advanced metering system (AMS) surcharge - returned to customers dependent upon AMS spend	$20.1	$25.3
Income tax rate change - refunded through a rate rider (Note 2 - Retail Rate Proceedings)	6.5	10.4
Transition to competition costs - returned to customers through rate riders when rates are redetermined periodically	3.2	3.8
Other	2.5	2.6
Entergy Texas Total	$32.3	$42.1

System Energy


	2020	2019
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)	$529.0	$403.3
Grand Gulf sale-leaseback - (Note 5 - Grand Gulf Sale-Leaseback Transactions)	55.6	55.6
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
Grand Gulf sale-leaseback accumulated deferred income taxes (a)	25.7	12.3
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement	10.7	17.8

System Energy Total	$665.4	$533.4

(a)Offset by related asset.

(b)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% effective January 2018, the Vidalia purchased power agreement regulatory liability was reduced by $30.5 million and the Louisiana Act 55 financing savings obligation regulatory liabilities were reduced by $25 million, with corresponding increases 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.

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, including its effects on Entergy’s and the Registrant Subsidiaries’ regulatory asset/liability for income taxes.

Entergy Arkansas

Consistent with its previously stated intent to return unprotected excess accumulated deferred income taxes to customers as expeditiously as possible, Entergy Arkansas initiated a tariff proceeding in February 2018 proposing to establish a tax adjustment rider to provide retail customers with certain tax benefits of $467 million associated with the Tax Act. For the residential customer class, unprotected excess accumulated deferred income taxes were returned to customers over a 21-month period from April 2018 through December 2019. For all other customer classes, unprotected excess accumulated deferred income taxes were returned to customers over a nine-month period from April 2018 through December 2018. A true-up provision also was included in the rider, with any over- or under-returned unprotected excess accumulated deferred income taxes credited or billed to customers during the billing month of January 2020, with any residual amounts of over- or under-returned unprotected excess

accumulated deferred income taxes to be flowed through Entergy Arkansas’s energy cost recovery rider. In March 2018 the APSC approved the tax adjustment rider effective with the first billing cycle of April 2018.

As discussed below, in July 2018, Entergy Arkansas made its formula rate plan filing to set its formula rate for the 2019 calendar year. A hearing was held in May 2018 regarding the APSC’s inquiries into the effects of the Tax Act, including Entergy Arkansas’s proposal to utilize its formula rate plan rider for its customers to realize the remaining benefits of the Tax Act. Entergy Arkansas’s formula rate plan rider included a netting adjustment that compared actual annual results to the allowed rate of return on common equity. In July 2018 the APSC issued an order agreeing with Entergy Arkansas’s proposal to have the effects of the Tax Act on current income tax expense flow through Entergy Arkansas’s formula rate plan rider and with Entergy Arkansas’s treatment of protected and unprotected excess accumulated deferred income taxes. The APSC also directed Entergy Arkansas to submit in the tax adjustment rider proceeding, discussed above, the adjustments to all other riders affected by the Tax Act and to include an amendment for a true up mechanism where a rider affected by the Tax Act does not already contain a true-up mechanism. Pursuant to a 2018 settlement agreement in Entergy Arkansas’s formula rate plan proceeding, Entergy Arkansas also removed the net operating loss accumulated deferred income tax asset caused by the Tax Act from Entergy Arkansas’s tax adjustment rider. Entergy Arkansas’s compliance tariff filings were accepted by the APSC in October 2018. In February 2021, pursuant to its 2020 formula rate plan evaluation report settlement, Entergy Arkansas flowed $5.6 million in credits to customers through the tax adjustment rider based on the outcome of certain federal tax positions and a decrease in the state tax rate; the tax adjustment rider will be closed after the credits are issued.

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 which, as discussed below, Entergy Louisiana filed in June 2018.

Entergy Mississippi

Entergy Mississippi filed its 2018 formula rate plan in March 2018 and included a proposal to return all of its unprotected excess accumulated deferred income taxes to customers through rates or in exchange for other assets, or a combination of both, by the end of 2018. In June 2018 the MPSC approved a stipulation filed by Entergy Mississippi and the Mississippi Public Utilities Staff in Entergy Mississippi’s formula rate plan filing that addressed Entergy Mississippi’s 2018 formula rate plan evaluation report and the ratemaking effects of the Tax Act. The stipulation provided for incorporating the reduction of the statutory federal income tax rate through Entergy Mississippi’s formula rate plan. The stipulation approved in June 2018 provided for the flow-back of protected excess accumulated deferred income taxes over the remaining lives of the assets through the formula rate plan. The stipulation also provided for the offset of unprotected excess accumulated deferred income taxes of $127.2 million against net utility plant and $2.2 million against other regulatory assets, and the return to customers of the remaining balance of unprotected excess accumulated deferred income taxes as recovery of a portion of fuel oil inventory and customer bill credits over a three-month period from July 2018 through September 2018, with an insignificant true-up reflected in the November 2018 power management rider filing. Entergy Mississippi recorded the reduction against net utility plant and other regulatory assets in June 2018. In third quarter 2018, Entergy Mississippi returned

unprotected excess accumulated deferred income taxes of $25.8 million through customer bill credits and $5.8 million through the sale of fuel oil inventory.

Entergy New Orleans

After enactment of the Tax Act the City Council passed a resolution ordering Entergy New Orleans to, effective January 1, 2018, record deferred regulatory liabilities to account for the Tax Act’s effect on Entergy New Orleans’s revenue requirement and to make a filing by mid-March 2018 regarding the Tax Act’s effects on Entergy New Orleans’s operating income and rate base and potential mechanisms for customers to receive benefits of the Tax Act. The City Council’s resolution also directed Entergy New Orleans to request that Entergy Services file with the FERC for revisions of the Unit Power Sales Agreement and MSS-4 replacement tariffs to address the return of excess accumulated deferred income taxes. Entergy submitted filings of this type to the FERC.

In March 2018, Entergy New Orleans filed its response to the resolution stating that the Tax Act reduced income tax expense from what was then reflected in rates by approximately $8.2 million annually for electric operations and by approximately $1.3 million annually for gas operations. In the filing, Entergy New Orleans proposed to return to customers from June 2018 through August 2019 the benefits of the reduction in income tax expense and its unprotected excess accumulated deferred income taxes through a combination of bill credits and investments in energy efficiency programs, grid modernization, and Smart City projects. Entergy New Orleans submitted supplemental information in April 2018 and May 2018. Shortly thereafter, Entergy New Orleans and the City Council’s advisors reached an agreement in principle that provides for benefits that will be realized by Entergy New Orleans customers through bill credits that started in July 2018 and offsets to future investments in energy efficiency programs, grid modernization, and Smart City projects, as well as additional benefits related to the filings made at the FERC. The agreement in principle was approved by the City Council in June 2018.

Entergy Texas

After enactment of the Tax Act the PUCT issued an order requiring most utilities, including Entergy Texas, beginning January 25, 2018, to record a regulatory liability for the difference between revenues collected under existing rates and revenues that would have been collected had existing rates been set using the new federal income tax rates and also for the balance of excess accumulated deferred income taxes. Entergy Texas had previously provided information to the PUCT staff and stated that it expected the PUCT to address the lower tax expense as part of Entergy Texas’s rate case expected to be filed in May 2018.

In May 2018, Entergy Texas filed its 2018 base rate case with the PUCT. Entergy Texas’s proposed rates and revenues reflected the inclusion of the federal income tax reductions due to the Tax Act. The PUCT issued an order in December 2018 establishing that 1) $25 million be credited to customers through a rider to reflect the lower federal income tax rate applicable to Entergy Texas from January 2018 through the date new rates were implemented, 2) $242.5 million of protected excess accumulated deferred income taxes be returned to customers through base rates under the average rate assumption method over the lives of the associated assets, and 3) $185.2 million of unprotected excess accumulated deferred income taxes be returned to customers through a rider. The unprotected excess accumulated deferred income taxes rider includes carrying charges and is in effect over a period of 12 months for larger customers and over a period of four years for other customers.

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. The retail regulators of the Utility operating companies that are parties to the Unit

Power Sales Agreement challenged the treatment and amount of excess accumulated deferred income tax liabilities associated with uncertain tax positions related to nuclear decommissioning. In July 2020 the presiding ALJ in the proceeding issued an initial decision finding that there is an additional $147 million in unprotected excess accumulated deferred income taxes related to System Energy’s uncertain decommissioning tax deduction. The initial decision determined that System Energy should have included the $147 million in its March 2018 filing. System Energy had not included credits related to the effect of the Tax Act on the uncertain decommissioning tax position because it was uncertain whether the IRS would allow the deduction. The initial decision rejected both System Energy’s alternative argument that any crediting should occur over a ten-year period and the retail regulators’ argument that any crediting should occur over a two-year period. Instead, the initial decision concluded that System Energy should credit the additional unprotected excess accumulated deferred income taxes in a single lump sum revenue requirement reduction following a FERC order addressing the initial decision.

The ALJ initial decision is an interim step in the FERC litigation process. In September 2020, System Energy filed a brief on exceptions with the FERC, re-urging its positions and requesting the reversal of the ALJ’s initial decision. In December 2020, the LPSC, APSC, MPSC, City Council, and FERC trial staff filed briefs opposing exceptions. The FERC will review the case and issue an order in the proceeding, and the FERC may accept, reject, or modify the ALJ’s initial decision in whole or in part. Credits, if any, that might be required will only become due after the FERC issues its order reviewing the initial decision.

As discussed below in “Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue,” in September 2020 the IRS issued a Notice of Proposed Adjustment (NOPA) and Entergy executed it. In September 2020, System Energy filed a motion to lodge the NOPA into the record in the FERC proceeding. In October 2020 the LPSC, APSC, MPSC, City Council, and FERC trial staff filed oppositions to System Energy’s motion. As a result of the NOPA, System Energy filed, in October 2020, a new Federal Power Act section 205 filing at the FERC to credit the excess accumulated deferred income taxes resulting from the decommissioning uncertain tax position. System Energy proposes to credit the entire amount of the excess accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position by issuing a one-time credit of $17.8 million. In November 2020, the LPSC, APSC, MPSC, and City Council filed a protest to the filing, and System Energy responded.

In November 2020 the IRS issued the Revenue Agent’s Report (RAR) for the 2014-2015 tax years and in December 2020 Entergy executed it. In December 2020, System Energy filed a motion to lodge the RAR into the record in the FERC proceeding addressing the Tax Cuts and Jobs Act. In January 2021 the LPSC, APSC, MPSC, and City Council filed a joint answer opposing System Energy’s motion, and the FERC trial staff also filed an answer opposing System Energy’s motion.

As a result of the RAR, in December 2020, System Energy also filed an amendment to its Federal Power Act section 205 filing to credit excess accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position. The amendment proposed the inclusion of the RAR as support for the filing. In December 2020, the LPSC, APSC, and City Council filed a protest in response to the amendment, reiterating objections to the filing to credit excess accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position. 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.

In November 2020, System Energy filed a motion to vacate the ALJ’s decision, arguing that it had been overtaken by changed circumstances because of the IRS’s determination resulting from the NOPA and RAR. In January 2021 the LPSC, APSC, MPSC, and City Council filed a joint answer opposing System Energy’s motion, and the FERC trial staff also filed an answer opposing System Energy’s motion. There is no formal deadline for FERC to rule on the motion.

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, 2020 and 2019 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.


	2020	2019
	(In Millions)
Entergy Arkansas (a)	$15.2	$14.0
Entergy Louisiana (b)	$170.4	$112.5
Entergy Mississippi	($14.7)	($70.4)
Entergy New Orleans (b)	$6.2	($0.8)
Entergy Texas	($85.4)	($13.0)

(a)Includes $68.2 million in 2020 and $67.7 million in 2019 of fuel and purchased power costs whose recovery periods are indeterminate but are expected to be recovered over a period greater than twelve months.

(b)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.

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 previously noted, subject to certain timelines and conditions set forth in the settlement agreement. See the “ANO Damage, Outage, and NRC Reviews” section in Note 8 to the financial statements for further discussion of the ANO stator incident.

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 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 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 has initiated an audit of the 2017 fuel costs. The time in which the audit will be complete is uncertain at this time.

In March 2019, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $0.01882 per kWh to $0.01462 per kWh and became effective with the first billing cycle in April 2019. In March 2019 the Arkansas Attorney General filed a response to Entergy Arkansas’s annual adjustment and included with its filing a motion for investigation of alleged overcharges to customers in connection with the FERC’s October 2018 order in the opportunity sales proceeding. Entergy Arkansas filed its response to the Attorney General’s motion in April 2019 in which Entergy Arkansas stated its intent to initiate a proceeding to address recovery issues related to the October 2018 FERC order. In May 2019, Entergy Arkansas initiated the opportunity sales recovery proceeding, discussed below, and requested that the APSC establish that proceeding as the single designated proceeding in which interested parties may assert claims related to the appropriate retail rate treatment of the FERC October 2018 order and related FERC orders in the opportunity sales proceeding. In June 2019 the APSC granted Entergy Arkansas’s request and also denied the Attorney General’s motion in the energy cost recovery proceeding seeking an investigation into Entergy Arkansas’s annual energy cost recovery rider adjustment and referred the evaluation of such matters to the opportunity sales recovery proceeding.

In March 2020, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $0.01462 per kWh to $0.01052 per kWh. The redetermined rate became effective with the first billing cycle in April 2020 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.

In July 2014 the LPSC authorized its staff to initiate an audit of the fuel adjustment clause filings by Entergy Gulf States Louisiana, whose business was combined with Entergy Louisiana in 2015. The audit includes a review of the reasonableness of charges flowed through Entergy Gulf States Louisiana’s fuel adjustment clause for the period from 2010 through 2013. In January 2019 the LPSC staff consultant issued its audit report. In its report, the LPSC staff consultant recommended that Entergy Louisiana refund approximately $900,000, plus interest, to customers based upon the imputation of a claim of vendor fault in servicing its nuclear plant. Entergy Louisiana recorded a provision in the first quarter 2019 for the potential outcome of the audit. In August 2019, Entergy Louisiana filed direct testimony challenging the basis for the LPSC staff’s recommended disallowance and providing an alternative calculation of replacement power costs should it be determined that a disallowance is appropriate. Entergy Louisiana’s calculation would require no refund to customers.

In July 2014 the LPSC authorized its staff to initiate an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed by Entergy Louisiana through its fuel adjustment clause for the period from 2010 through 2013. In January 2019 the LPSC staff issued its audit report recommending that Entergy Louisiana refund approximately $7.3 million, plus interest, to customers based upon the imputation of a claim of vendor fault in servicing its nuclear plant. Entergy Louisiana recorded a provision in the first quarter 2019 for the potential outcome of the audit. In August 2019, Entergy Louisiana filed direct testimony challenging the basis for the LPSC staff’s recommended disallowance and providing an alternative calculation of replacement power costs should it be determined that a disallowance is appropriate. Entergy Louisiana’s calculation would require a refund to customers of approximately $4.3 million, plus interest, as compared to the LPSC staff’s recommendation of $7.3 million, plus interest. Responsive testimony was filed by the LPSC staff and intervenors in September 2019; all parties either agreed with or did not oppose Entergy Louisiana’s alternative calculation of replacement power costs.

In November 2019 the pending LPSC proceedings for the 2010-2013 Entergy Louisiana and Entergy Gulf States Louisiana audits were consolidated to facilitate a settlement of both fuel audits. In December 2019 an unopposed settlement was reached that requires a refund to legacy Entergy Louisiana customers of approximately $2.3 million, including interest, and no refund to legacy Entergy Gulf States Louisiana customers. The LPSC approved the settlement in January 2020. A one-time refund was made in February 2020.

In June 2016 the LPSC issued notice of audits of Entergy Louisiana’s fuel adjustment clause filings for the period 2014 through 2015 and purchased gas adjustment clause filings for the period 2012 through 2015. In recognition of the business combination that occurred in 2015, the audit notice was issued to Entergy Louisiana and also includes a review of charges to legacy Entergy Gulf States Louisiana customers prior to the business combination. The audits include a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2014 through 2015 and charges flowed through Entergy Louisiana’s purchased gas adjustment clause for the period from 2012 through 2015. Regarding the fuel adjustment clause filing, the LPSC staff issued a report in January 2021 that did not recommend a disallowance for the period 2014 through 2015 recoveries, but did propose various reporting requirements. Entergy Louisiana is currently reviewing the LPSC staff recommendations regarding reporting requirements. Regarding the purchased gas adjustment clause filings, the LPSC staff issued a report in February 2020 that did not recommend a disallowance for the period 2012 through 2015 recoveries. The LPSC issued an order in September 2020 accepting the LPSC staff’s report.

In May 2018 the LPSC staff provided notice of audits 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 2016 through 2017. In February 2020 the LPSC staff issued an audit report recommending a disallowance of approximately $29 thousand. Entergy Louisiana submitted a letter disputing the basis of the proposed disallowance but indicated that due to the amount at issue it would not oppose the recommended refund. The LPSC staff and Entergy Louisiana submitted a joint report noting each party’s position on the substantive issues in the matter and recommending resolution of the matters. The LPSC issued an order in September 2020 resolving the matter and ordering a refund of approximately $29 thousand. In January 2021 the LPSC issued a notice closing the matter.

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. Discovery commenced in September 2020 and is ongoing.

Entergy Mississippi

Entergy Mississippi’s rate schedules include an energy cost recovery rider that is adjusted annually to reflect accumulated over- or under-recoveries. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.

In January 2017 the MPSC certified to the Mississippi Legislature the audit reports of its independent auditors for the fuel year ending September 30, 2016. In November 2017 the Mississippi Public Utilities Staff separately engaged a consultant to review the September 2016 outage at the Grand Gulf Nuclear Station and to review ongoing operations at Grand Gulf. This engagement continues, and subsequently, was expanded to include all outages at Grand Gulf that occurred through 2019.

In November 2017, 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 $61.5 million as of September 30, 2017. In January 2018 the MPSC approved the proposed energy cost factors effective for February 2018 bills.

In November 2018, 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 $57 million as of September 30, 2018. In January 2019 the MPSC approved the proposed energy cost factor effective for February 2019 bills.

In November 2019, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation included $39.6 million of prior over-recovery flowing back to customers beginning February 2020. Entergy Mississippi’s balance in its deferred fuel account did not decrease as expected after implementation of the new factor. In an effort to assist customers during the COVID-19 pandemic, in May 2020, Entergy Mississippi requested an interim adjustment to the energy cost recovery rider to credit approximately $50 million from the over-recovered balance in the deferred fuel account to customers over four consecutive billing months. The MPSC approved this interim adjustment in May 2020 effective for June through September 2020 bills.

In November 2020, 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 over-recovery of approximately $24.4 million as of September 30, 2020. In January 2021 the MPSC approved the proposed energy cost factor effective for February 2021 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. Semi-annual revisions of the fixed fuel factor are 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. A fuel reconciliation is required to be filed at least once every three years and outside of a base rate case filing.

In December 2017, Entergy Texas filed an application for a fuel refund of approximately $30.5 million for the months of May 2017 through October 2017. Also in December 2017, the PUCT’s ALJ approved the refund on an interim basis. For most customers, the refunds flowed through bills from January 2018 through March 2018. The fuel refund was approved by the PUCT in March 2018.

In September 2019, Entergy Texas filed an application to reconcile its fuel and purchased power costs for the period from April 2016 through March 2019. During the reconciliation period, Entergy Texas incurred approximately $1.6 billion in Texas jurisdictional eligible fuel and purchased power expenses, net of certain revenues credited to such expenses and other adjustments. Entergy Texas estimated an under-recovery balance of approximately $25.8 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning April 2019. In March 2020 an intervenor filed testimony proposing that the PUCT disallow: (1) $2 million in replacement power costs associated with generation outages during the reconciliation period; and (2) $24.4 million associated with the operation of the Spindletop natural gas storage facility during the reconciliation period. In April 2020, Entergy Texas filed rebuttal testimony refuting all points raised by the intervenor. In June 2020 the parties filed a stipulation and settlement agreement, which included a $1.2 million disallowance not associated with any particular issue raised by any party. The PUCT approved the settlement in August 2020.

In July 2020, Entergy Texas filed an application with the PUCT to implement an interim fuel refund of $25.5 million, including interest. Entergy Texas proposes that the interim fuel refund be implemented beginning with the first August 2020 billing cycle over a three-month period for smaller customers and in a lump sum amount in the billing month of August 2020 for transmission-level customers. The interim fuel refund was approved in July 2020, and Entergy Texas began refunds in August 2020.

In February 2021, Entergy Texas filed an application to implement a fuel refund for a cumulative over-recovery of approximately $75 million that is primarily attributable to settlements received by Entergy Texas from MISO related to Hurricane Laura. Entergy Texas planned to issue the refund over the period of March through August 2021. On February 22, 2021, Entergy Texas filed a motion to abate its fuel refund proceeding to assess how the February 2021 winter storm impacted Entergy Texas’s fuel over-recovery position.

Retail Rate Proceedings

Filings with the APSC (Entergy Arkansas)

Retail Rates

2018 Formula Rate Plan Filing

In July 2018, Entergy Arkansas filed with the APSC its 2018 formula rate plan filing to set its formula rate for the 2019 calendar year. The filing showed Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2019 test period to be below the formula rate plan bandwidth. Additionally, the filing included the first netting adjustment under the current formula rate plan for the historical test year 2017, reflecting the change in formula rate plan revenues associated with actual 2017 results when compared to the allowed rate of return on equity. The filing included a projected $73.4 million revenue deficiency for 2019 and a $95.6 million revenue deficiency for the 2017 historical test year, for a total revenue requirement of $169 million for this filing. 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 four percent of total revenue, which originally was $65.4 million but was increased to $66.7 million based upon the APSC staff’s updated calculation of 2018 revenue. In October 2018, Entergy Arkansas and the parties to the proceeding filed joint motions to approve a partial settlement agreement as to certain factual issues and agreed to brief contested legal issues. In November 2018 the APSC held a hearing and was briefed on a contested legal issue. In December 2018 the APSC issued a decision related to the initial legal brief, approved the partial settlement agreement and $66.7 million revenue requirement increase, as well as Entergy Arkansas’s formula rate plan, with updated rates going into effect for the first billing cycle of January 2019.

2019 Formula Rate Plan Filing

In July 2019, Entergy Arkansas filed with the APSC its 2019 formula rate plan filing to set its formula rate for the 2020 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2020 and a netting adjustment for the historical year 2018. The total proposed formula rate plan rider revenue change designed to produce a target rate of return on common equity of 9.75% is $15.3 million, which is based upon a deficiency of approximately $61.9 million for the 2020 projected year, netted with a credit of approximately $46.6 million in the 2018 historical year netting adjustment. During 2018 Entergy Arkansas experienced higher-than expected sales volume, and actual costs were lower than forecasted. These changes, coupled with a reduced income tax rate resulting from the Tax Cuts and Jobs Act, resulted in the credit for the historical year netting adjustment. In the fourth quarter 2018, Entergy Arkansas recorded a provision of $35.1 million that reflected the estimate of the historical year netting adjustment that was expected to be included in the 2019 filing. In 2019, Entergy Arkansas recorded additional provisions totaling $11.5 million to reflect the updated estimate of the historical year netting adjustment included in the 2019 filing. In October 2019 other parties in the proceeding filed their errors and objections requesting certain adjustments to Entergy Arkansas’s filing that would reduce or eliminate Entergy Arkansas’s proposed revenue change. Entergy Arkansas filed its response addressing the requested adjustments in October 2019. In its response, Entergy Arkansas accepted certain of the adjustments recommended by the General Staff of the APSC that would reduce the proposed formula rate plan rider revenue change to $14 million. Entergy Arkansas disputed the remaining adjustments proposed by the parties. In October 2019, Entergy Arkansas filed a unanimous settlement agreement with the other parties in the proceeding seeking APSC approval of a revised total formula rate plan rider revenue change of $10.1 million. In its July 2019 formula rate plan filing, Entergy Arkansas proposed to recover an $11.2 million regulatory asset, amortized over five years, associated with specific costs related to the potential construction of scrubbers at the White Bluff plant. Although Entergy Arkansas does not concede that the regulatory asset lacks merit, for purposes of reaching a settlement on the total formula rate plan rider amount, Entergy Arkansas agreed not to include the White Bluff scrubber regulatory asset cost in the 2019 formula rate plan filing or future filings. Entergy Arkansas recorded a write-off in 2019 of the $11.2 million White Bluff scrubber regulatory asset. In December 2019 the APSC approved the settlement as being

in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2020.

2020 Formula Rate Plan Filing

In July 2020, Entergy Arkansas filed with the APSC its 2020 formula rate plan filing to set its formula rate for the 2021 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2021, as amended through subsequent filings in the proceeding, and a netting adjustment for the historical year 2019. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2021 projected year is 8.22% resulting in a revenue deficiency of $64.3 million. The earned rate of return on common equity for the 2019 historical year was 9.07% resulting in a $23.9 million netting adjustment. The total proposed revenue change for the 2021 projected year and 2019 historical year netting adjustment was $88.2 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 $74.3 million. In October 2020 other parties in the proceeding filed their errors and objections recommending certain adjustments, and Entergy Arkansas filed responsive testimony disputing these adjustments. As part of the formula rate plan tariff the calculation for the revenue constraint was updated based on actual revenues which had the effect of reducing the initially-proposed $74.3 million revenue requirement increase to $72.6 million. In October 2020, Entergy Arkansas filed with the APSC a unanimous settlement agreement reached with the other parties that resolved all but one issue. As a result of the settlement agreement, Entergy Arkansas’s requested revenue increase was $68.4 million, including a $44.5 million increase for the projected 2021 year and a $23.9 million netting adjustment. The remaining issue litigated concerned the methodology used to calculate the netting adjustment within the formula rate plan. In December 2020 the APSC issued an order rejecting the netting adjustment method used by Entergy Arkansas. Applying the approach ordered by the APSC changed the netting adjustment for the 2019 historical year from a $23.9 million deficiency to $43.5 million excess. Overall, the decision reduced Entergy Arkansas’s revenue adjustment for 2021 to $1 million. In December 2020, Entergy Arkansas filed a petition for rehearing of the APSC’s decision, and in January 2021 the APSC granted further consideration of Entergy Arkansas’s petition. Based on the progress of the proceeding to date, in December 2020, Entergy Arkansas recorded a regulatory liability of $43.5 million to reflect the netting adjustment for 2019, as included in the APSC’s December 2020 order, which would be returned to customers in 2021. Also with the formula rate plan filing, Entergy Arkansas is requesting an extension of the formula rate plan rider for a second five-year term. Decisions by the APSC on the netting adjustment rehearing and the extension are expected in March 2021.

COVID-19 Orders

In April 2020, in light of the COVID-19 pandemic, the APSC issued an order requiring utilities, to the extent they had not already done so, to suspend service disconnections during the remaining pendency of the Arkansas Governor’s emergency declaration or until the APSC rescinds the directive. The order also authorizes utilities to establish a regulatory asset to record costs resulting from the suspension of service disconnections, directs that in future proceedings the APSC will consider whether the request for recovery of these regulatory assets is reasonable and necessary, and requires utilities to track and report the costs and any savings directly attributable to suspension of disconnects. In May 2020 the APSC approved Entergy Arkansas expanding deferred payment agreements to assist customers during the COVID-19 pandemic. Quarterly reporting began in August 2020 and the APSC ordered additional reporting in October 2020 regarding utilities’ transitional plans for ending the moratorium on service disconnects. In February 2021 the APSC issued an order finding that it is not in the public interest to immediately lift the moratorium on service disconnects, but to announce a target date of May 3, 2021. In March 2021 the APSC will issue an order either confirming the lifting of the moratorium on service disconnects or extending the moratorium. As of December 31, 2020, Entergy Arkansas recorded a regulatory asset of $10.5 million for costs associated with the COVID-19 pandemic.

Internal Restructuring

In November 2017, Entergy Arkansas filed an application with the APSC seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy Arkansas to a new entity, which would ultimately be owned by an existing Entergy subsidiary holding company. In July 2018, Entergy Arkansas filed a settlement, reached by all parties in the APSC proceeding, resolving all issues. The APSC approved the settlement agreement and restructuring in August 2018. Pursuant to the settlement agreement, Entergy Arkansas will credit retail customers $39.6 million over six years, beginning in 2019. Entergy Arkansas also received the required FERC and NRC approvals.

In November 2018, Entergy Arkansas undertook a multi-step restructuring, including the following:

•Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.

•Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.

•Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Arkansas Power, LLC, a Texas limited liability company (Entergy Arkansas Power), and Entergy Arkansas Power assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.

•Entergy Arkansas, Inc. contributed the membership interests in Entergy Arkansas Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Arkansas Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.

In December 2018, Entergy Arkansas, Inc. changed its name to Entergy Utility Property, Inc., and Entergy Arkansas Power then changed its name to Entergy Arkansas, LLC. Entergy Arkansas, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Arkansas, Inc. The transaction was accounted for as a transaction between entities under common control.

Filings with the LPSC (Entergy Louisiana)

Retail Rates - Electric

2017 Formula Rate Plan Filing

In June 2018, Entergy Louisiana filed its formula rate plan evaluation report for its 2017 calendar year operations. The 2017 test year evaluation report produced an earned return on equity of 8.16%, due in large part to revenue-neutral realignments to other recovery mechanisms. Without these realignments, the evaluation report produces an earned return on equity of 9.88% and a resulting base rider formula rate plan revenue increase of $4.8 million. Excluding the Tax Act credits provided for by the tax reform adjustment mechanisms, total formula rate plan revenues were further increased by a total of $98 million as a result of the evaluation report due to adjustments to the additional capacity and MISO cost recovery mechanisms of the formula rate plan, and implementation of the transmission recovery mechanism. In August 2018, Entergy Louisiana filed a supplemental formula rate plan evaluation report to reflect changes from the 2016 test year formula rate plan proceedings, a decrease to the transmission recovery mechanism to reflect lower actual capital additions, and a decrease to evaluation period expenses to reflect the terms of a new power sales agreement. Based on the August 2018 update, Entergy Louisiana recognized a total decrease in formula rate plan revenue of approximately $17.6 million. Results of the updated 2017 evaluation report filing were implemented with the September 2018 billing month subject to refund and review by the LPSC staff and intervenors. In accordance with the terms of the formula rate plan, in September 2018 the LPSC staff and intervenors submitted their responses to Entergy Louisiana’s original formula rate plan evaluation report and supplemental compliance updates. The LPSC staff asserted objections/reservations

regarding 1) Entergy Louisiana’s proposed rate adjustments associated with the return of excess accumulated deferred income taxes pursuant to the Tax Act and the treatment of accumulated deferred income taxes related to reductions of rate base; 2) Entergy Louisiana’s reservation regarding treatment of a regulatory asset related to certain special orders by the LPSC; and 3) test year expenses billed from Entergy Services to Entergy Louisiana. Intervenors also objected to Entergy Louisiana’s treatment of the regulatory asset related to certain special orders by the LPSC. A procedural schedule has not yet been established to resolve these issues.

Entergy Louisiana also included in its filing a presentation of an initial proposal to combine the legacy Entergy Louisiana and legacy Entergy Gulf States Louisiana residential rates, which combination, if approved, would be accomplished on a revenue-neutral basis intended not to affect the rates of other customer classes.

Commercial operation at J. Wayne Leonard Power Station (formerly St. Charles Power Station) commenced in May 2019. In May 2019, Entergy Louisiana filed an update to its 2017 formula rate plan evaluation report to include the estimated first-year revenue requirement of $109.5 million associated with the J. Wayne Leonard Power Station. The resulting interim adjustment to rates became effective with the first billing cycle of June 2019. In June 2020, Entergy Louisiana submitted information to the LPSC to review the prudence of Entergy Louisiana’s management of the project. In August 2020 discovery commenced and a procedural schedule was established with a hearing in July 2021.

2018 Formula Rate Plan Filing

In May 2019, Entergy Louisiana filed its formula rate plan evaluation report for its 2018 calendar year operations. The 2018 test year evaluation report produced an earned return on common equity of 10.61% leading to a base rider formula rate plan revenue decrease of $8.9 million. While base rider formula rate plan revenue will decrease as a result of this filing, overall formula rate plan revenues will increase by approximately $118.7 million. This outcome is primarily driven by a reduction to the credits previously flowed through the tax reform adjustment mechanism and an increase in the transmission recovery mechanism, partially offset by reductions in the additional capacity mechanism revenue requirements and extraordinary cost items. The filing is subject to review by the LPSC. Resulting rates were implemented in September 2019, subject to refund.

Entergy Louisiana also included in its filing a presentation of an initial proposal to combine the legacy Entergy Louisiana and legacy Entergy Gulf States Louisiana residential rates, which combination, if approved, would be accomplished on a revenue-neutral basis intended not to affect the rates of other customer classes. Entergy Louisiana contemplates that any combination of residential rates resulting from this request would be implemented with the results of the 2019 test year formula rate plan filing.

Several parties intervened in the proceeding and the LPSC staff filed its report of objections/reservations in accordance with the applicable provisions of the formula rate plan. In its report the LPSC staff re-urged reservations with respect to the outstanding issues from the 2017 test year formula rate plan filing and disputed the inclusion of certain affiliate costs for test years 2017 and 2018. The LPSC staff objected to Entergy Louisiana’s proposal to combine residential rates but proposed the setting of a status conference to establish a procedural schedule to more fully address the issue. The LPSC staff also reserved its right to object to the treatment of the sale of Willow Glen reflected in the evaluation report and to the August 2019 compliance update, which was made primarily to update the capital additions reflected in the formula rate plan’s transmission recovery mechanism, based on limited time to review it. Additionally, since the completion of certain transmission projects, the LPSC staff issued supplemental data requests addressing the prudence of Entergy Louisiana’s expenditures in connection with those projects. Entergy Louisiana has responded to all such requests.

Commercial operation at Lake Charles Power Station commenced in March 2020. In March 2020, Entergy Louisiana filed an update to its 2018 formula rate plan evaluation report to include the estimated first-year revenue requirement of $108 million associated with the Lake Charles Power Station. The resulting interim adjustment to rates became effective with the first billing cycle of April 2020.

In an effort to narrow the remaining issues in formula rate plan test years 2017 and 2018, Entergy Louisiana provided notice to the parties in October 2020 that it was withdrawing its request to combine residential rates. Entergy Louisiana noted that the withdrawal is without prejudice to Entergy Louisiana’s right to seek to combine residential rates in a future proceeding.

2019 Formula Rate Plan Filing

In May 2020, Entergy Louisiana filed with the LPSC its formula rate plan evaluation report for its 2019 calendar year operations. The 2019 test year evaluation report produced an earned return on common equity of 9.66%. As such, no change to base rider formula rate plan revenue is required. Although base rider formula rate plan revenue will not change as a result of this filing, overall formula rate plan revenues will increase by approximately $103 million. This outcome is driven by the removal of prior year credits associated with the sale of the Willow Glen Power Station and an increase in the transmission recovery mechanism. Also contributing to the overall change is an increase in legacy formula rate plan revenue requirements driven by legacy Entergy Louisiana capacity cost true-ups and higher annualized legacy Entergy Gulf States Louisiana revenues due to higher billing determinants, offset by reductions in MISO cost recovery mechanism and tax reform adjustment mechanism revenue requirements. In August 2020 the LPSC staff submitted a list of items for which it needs additional information to confirm the accuracy and compliance of the 2019 test year evaluation report. The LPSC staff objected to a proposed revenue neutral adjustment regarding a certain rider as being beyond the scope of permitted formula rate plan adjustments. Rates reflected in the May 2020 filing, with the exception of the revenue neutral rider adjustment, and as updated in an August 2020 filing, were implemented in September 2020, subject to refund. Entergy Louisiana is in the process of providing additional information and details on the May 2020 filing as requested by the LPSC staff.

In November 2020, Entergy Louisiana accepted ownership of the Washington Parish Energy Center and filed an update to its 2019 formula rate plan evaluation report to include the estimated first-year revenue requirement of $35 million associated with the Washington Parish Energy Center. The resulting interim adjustment to rates became effective with the first billing cycle of December 2020. In January 2021, Entergy Louisiana filed an update to its 2019 formula rate plan evaluation report to include the implementation of a scheduled step-up in its nuclear decommissioning revenue requirement and a true-up for under-collections of nuclear decommissioning expenses. The total rate adjustment would increase formula rate plan revenues by approximately $1.2 million. The resulting interim adjustment to rates became effective with the first billing cycle of February 2021.

Request for Extension and Modification of Formula Rate Plan

In May 2020, Entergy Louisiana filed with the LPSC its application for authority to extend its formula rate plan. In its application, Entergy Louisiana seeks to maintain a 9.8% return on equity, with a bandwidth of 60 basis points above and below the midpoint, with a first-year midpoint reset. Entergy Louisiana also seeks to maintain its existing additional capacity mechanism, tax reform adjustment mechanism, transmission recovery mechanism, and the MISO cost recovery mechanism. Entergy Louisiana also seeks to add a distribution cost recovery mechanism which operates in substantially the same manner as the transmission recovery mechanism, seeks to utilize end of period rate base to calculate cost of service, and requests a deferral of certain expenses incurred for outside of right-of-way vegetation programs. Settlement discussions are ongoing.

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. There has been no further activity in the investigation since May 2019.

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 addition, utilities may seek future recovery, subject to LPSC review and approval, of losses and expenses incurred due to compliance with the LPSC’s COVID-19 orders. The suspension of late fees and disconnects for non-pay was extended until the first billing cycle after July 16, 2020. In January 2021, Entergy Louisiana resumed disconnections for customers in all customer classes with past-due balances that have not made payment arrangements. Utilities seeking to recover the regulatory asset must formally petition the LPSC to do so, identifying the direct and indirect costs for which recovery is sought. Any such request is subject to LPSC review and approval. As of December 31, 2020, Entergy Louisiana recorded a regulatory asset of $48.8 million for costs associated with the COVID-19 pandemic.

Filings with the MPSC (Entergy Mississippi)

Retail Rates

2018 Formula Rate Plan Filing

In March 2018, Entergy Mississippi submitted its formula rate plan 2018 test year filing and 2017 look-back filing showing Entergy Mississippi’s earned return for the historical 2017 calendar year and projected earned return for the 2018 calendar year, in large part as a result of the lower federal corporate income tax rate effective in 2018, to be within the formula rate plan bandwidth, resulting in no change in rates. In June 2018, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a stipulation that confirmed that Entergy Mississippi’s earned returns for both the 2017 look-back filing and 2018 test year were within the respective formula rate plan bandwidths. In June 2018 the MPSC approved the stipulation, which resulted in no change in rates. See “Regulatory activity regarding the Tax Cuts and Jobs Act” above for additional discussion regarding the treatment of the effects of the lower federal corporate income tax rate.

Formula Rate Plan Revisions

In October 2018, Entergy Mississippi proposed revisions to its formula rate plan that would provide for a mechanism in the formula rate plan, the interim capacity rate adjustment mechanism, to recover the non-fuel related costs of additional owned capacity acquired by Entergy Mississippi, including the non-fuel annual ownership costs of the Choctaw Generating Station, as well as to allow similar cost recovery treatment for other future capacity acquisitions, such as the Sunflower Solar Facility, that are approved by the MPSC. In December 2019 the MPSC approved Entergy Mississippi’s proposed revisions to its formula rate plan to provide for an interim capacity rate adjustment mechanism to recover the $59 million first-year annual revenue requirement associated with the non-fuel ownership costs of the Choctaw Generating Station, which Entergy Mississippi began billing in January 2020. The MPSC must approve recovery through the interim capacity rate adjustment for each new resource. In addition, the MPSC approved revisions to the formula rate plan which allows Entergy Mississippi to begin billing rate adjustments effective April 1 of the filing year on a temporary basis subject to refund or credit to customers, subject to final MPSC order. The MPSC also authorized Entergy Mississippi to remove vegetation management costs from the formula rate plan and recover these costs through the establishment of a vegetation management rider. Effective with the April 2020 billing cycle, Entergy Mississippi implemented a rider to recover $22 million in vegetation management costs.

2019 Formula Rate Plan Filing

In March 2019, Entergy Mississippi submitted its formula rate plan 2019 test year filing and 2018 look-back filing showing Entergy Mississippi’s earned return for the historical 2018 calendar year to be above the

formula rate plan bandwidth and projected earned return for the 2019 calendar year to be below the formula rate plan bandwidth. The 2019 test year filing shows a $36.8 million rate increase is necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.94% return on rate base, within the formula rate plan bandwidth. The 2018 look-back filing compares actual 2018 results to the approved benchmark return on rate base and shows a $10.1 million interim decrease in formula rate plan revenues is necessary. In the fourth quarter 2018, Entergy Mississippi recorded a provision of $9.3 million that reflected the estimate of the difference between the 2018 expected earned rate of return on rate base and an established performance-adjusted benchmark rate of return under the formula rate plan performance-adjusted bandwidth mechanism. In the first quarter 2019, Entergy Mississippi recorded a $0.8 million increase in the provision to reflect the amount shown in the look-back filing. In June 2019, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed that the 2019 test year filing showed that a $32.8 million rate increase is necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.93% return on rate base, within the formula rate plan bandwidth. Additionally, pursuant to the joint stipulation, Entergy Mississippi’s 2018 look-back filing reflected an earned return on rate base of 7.81% in calendar year 2018 which is above the look-back benchmark return on rate base of 7.13%, resulting in an $11 million decrease in formula rate plan revenues on an interim basis through May 2020. In the second quarter 2019, Entergy Mississippi recorded an additional $0.9 million increase in the provision to reflect the $11 million shown in the look-back filing. In June 2019 the MPSC approved the joint stipulation with rates effective for the first billing cycle of July 2019.

2020 Formula Rate Plan Filing

In March 2020, Entergy Mississippi submitted its formula rate plan 2020 test year filing and 2019 look-back filing showing Entergy Mississippi’s earned return for the historical 2019 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2020 calendar year to be below the formula rate plan bandwidth. The 2020 test year filing shows a $24.6 million rate increase is necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.51% return on rate base, within the formula rate plan bandwidth. The 2019 look-back filing compares actual 2019 results to the approved benchmark return on rate base and reflects the need for a $7.3 million interim increase in formula rate plan revenues. In accordance with the MPSC-approved revisions to the formula rate plan, Entergy Mississippi implemented a $24.3 million interim rate increase, reflecting a cap equal to 2% of 2019 retail revenues, effective with the April 2020 billing cycle, subject to refund. In June 2020, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed that the 2020 test year filing showed that a $23.8 million rate increase is necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.51% return on rate base, within the formula rate plan bandwidth. Pursuant to the joint stipulation, Entergy Mississippi’s 2019 look-back filing reflected an earned return on rate base of 6.75% in calendar year 2019, which is within the look-back bandwidth. As a result, there is no change in formula rate plan revenues in the 2019 look-back filing. In June 2020 the MPSC approved the joint stipulation with rates effective for the first billing cycle of July 2020. In the June 2020 order the MPSC directed Entergy Mississippi to submit revisions to its formula rate plan to realign recovery of costs from its energy efficiency cost recovery rider to its formula rate plan. In November 2020 the MPSC approved Entergy Mississippi’s revisions to its formula rate plan providing for the realignment of energy efficiency costs to its formula rate plan, the deferral of energy efficiency expenditures into a regulatory asset, and the elimination of its energy efficiency cost recovery rider effective with the January 2022 billing cycle.

COVID-19 Orders

In March 2020 the MPSC issued an order suspending disconnections for a period of sixty days. The MPSC extended the order on disconnections through May 26, 2020. In April 2020 the MPSC issued an order authorizing utilities to defer incremental costs and expenses associated with COVID-19 compliance and to seek future recovery through rates of the prudently incurred incremental costs and expenses. In December 2020, Entergy Mississippi resumed disconnections to commercial, industrial, and governmental customers with past-due balances that have not made payment arrangements. In January 2021, Entergy Mississippi resumed disconnecting service for residential

customers with past-due balances that have not made arrangements with the company. As of December 31, 2020, Entergy Mississippi recorded a regulatory asset of $19.2 million for costs associated with the COVID-19 pandemic.

Internal Restructuring

In March 2018, Entergy Mississippi filed an application with the MPSC seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy Mississippi to a new entity, which would ultimately be held by an existing Entergy subsidiary holding company. In September 2018, Entergy Mississippi and the Mississippi Public Utilities Staff entered into and filed a joint stipulation regarding the restructuring filing. In September 2018 the MPSC issued an order accepting the stipulation in its entirety and approving the restructuring and credits of $27 million to retail customers over six years, consisting of annual payments of $4.5 million for the years 2019-2024. Entergy Mississippi also received the required FERC approval.

In November 2018, Entergy Mississippi undertook a multi-step restructuring, including the following:

•Entergy Mississippi, Inc. redeemed its outstanding preferred stock, at the aggregate redemption price of approximately $21.2 million.

•Entergy Mississippi, Inc. converted from a Mississippi corporation to a Texas corporation.

•Under the Texas Business Organizations Code (TXBOC), Entergy Mississippi, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Mississippi Power and Light, LLC, a Texas limited liability company (Entergy Mississippi Power and Light), and Entergy Mississippi Power and Light assumed substantially all of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Mississippi, Inc. remained in existence and held the membership interests in Entergy Mississippi Power and Light.

•Entergy Mississippi, Inc. contributed the membership interests in Entergy Mississippi Power and Light to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Mississippi Power and Light is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.

In December 2018, Entergy Mississippi, Inc. changed its name to Entergy Utility Enterprises, Inc., and Entergy Mississippi Power and Light then changed its name to Entergy Mississippi, LLC. Entergy Mississippi, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Mississippi, Inc. The restructuring was accounted for as a transaction between entities under common control.

In December 2018, Entergy Mississippi filed its notice of intent to implement the restructuring credit rider to allow Entergy Mississippi to return credits of $27 million to retail customers over six years. In January 2019 the MPSC approved the proposed restructuring credit adjustment factor, which is effective for bills rendered beginning February 2019.

Filings with the City Council (Entergy New Orleans)

Retail Rates

Energy Efficiency

In December 2019, Entergy New Orleans filed an application with the City Council seeking approval of an implementation plan for the Energy Smart program from April 2020 through December 2022. Entergy New Orleans proposed to recover the costs of the program through mechanisms previously approved by the City Council or through the energy efficiency cost recovery rider, which was approved in the 2018 combined rate case resolution. In January 2020 the City Council’s advisors recommended that, beginning with Program Year 10, the City Council allow Entergy New Orleans to earn a utility performance incentive of 7% of Energy Smart costs for each year in

which Entergy New Orleans achieves 100% of the City Council’s savings targets for Energy Smart. In February 2020 the City Council approved Entergy New Orleans’s application.

2018 Base Rate Case

In September 2018, Entergy New Orleans filed an electric and gas base rate case with the City Council. The filing requested a 10.5% return on equity for electric operations with opportunity to earn a 10.75% return on equity through a performance adder provision of the electric formula rate plan in subsequent years under a formula rate plan and requested a 10.75% return on equity for gas operations. The proposed electric rates in the revised filing reflect a net reduction of $20.3 million. The reduction in electric rates includes a base rate increase of $135.2 million, of which $131.5 million is associated with moving costs currently collected through fuel and other riders into base rates, plus a request for an advanced metering surcharge to recover $7.1 million associated with advanced metering infrastructure, offset by a net decrease of $31.1 million related to fuel and other riders. The filing also included a proposed gas rate decrease of $142 thousand. Entergy New Orleans’s rates reflected the inclusion of federal income tax reductions due to the Tax Act and the provisions of a previously-approved agreement in principle determining how the benefits of the Tax Act would flow. Entergy New Orleans included cost of service studies for electric and gas operations for the twelve months ended December 31, 2017 and the projected twelve months ending December 31, 2018. In addition, Entergy New Orleans included capital additions expected to be placed into service for the period through December 31, 2019. Entergy New Orleans based its request for a change in rates on the projected twelve months ending December 31, 2018.

The filing’s major provisions included: (1) a new electric rate structure, which realigns the revenue requirement associated with capacity and long-term service agreement expense from certain existing riders to base revenue, provides for the recovery of the cost of advanced metering infrastructure, and partially blends rates for Entergy New Orleans’s customers residing in Algiers with customers residing in the remainder of Orleans Parish through a three-year phase-in; (2) contemporaneous cost recovery riders for investments in energy efficiency/demand response, incremental changes in capacity/long-term service agreement costs, grid modernization investment, and gas infrastructure replacement investment; and (3) formula rate plans for both electric and gas operations. In February 2019 the City Council’s advisors and several intervenors filed testimony in response to Entergy New Orleans’s application. The City Council’s advisors recommended, among other things, overall rate reductions of approximately $33 million in electric rates and $3.8 million in gas rates. Certain intervenors recommended overall rate reductions of up to approximately $49 million in electric rates and $5 million in gas rates. An evidentiary hearing was held in June 2019, and the record and post-hearing briefs were submitted in July 2019.

In October 2019 the City Council’s Utility Committee approved a resolution for a change in electric and gas rates for consideration by the full City Council that included a 9.35% return on common equity, an equity ratio of the lesser of 50% or Entergy New Orleans’s actual equity ratio, and a total reduction in revenues that Entergy New Orleans initially estimated to be approximately $39 million ($36 million electric; $3 million gas). At its November 7, 2019 meeting, the full City Council approved the resolution that had previously been approved by the City Council’s Utility Committee. Based on the approved resolution, in the fourth quarter 2019 Entergy New Orleans recorded an accrual of $10 million that reflects the estimate of the revenue billed in 2019 to be refunded to customers in 2020 based on an August 2019 effective date for the rate decrease. Entergy New Orleans also recorded a total of $12 million in regulatory assets for rate case costs and information technology costs associated with integrating Algiers customers with Entergy New Orleans’s legacy system and records. Entergy New Orleans will also be allowed to recover $10 million of retired general plant costs over a 20-year period.

The resolution directed Entergy New Orleans to submit a compliance filing within 30 days of the date of the resolution to facilitate the eventual implementation of rates, including all necessary calculations and conforming rate schedules and riders. The electric formula rate plan rider includes, among other things, 1) a provision for forward-looking adjustments to include known and measurable changes realized up to 12 months after the evaluation period; 2) a decoupling mechanism; and 3) recognition that Entergy New Orleans is authorized to make an in-service adjustment to the formula rate plan to include the non-fuel cost of the New Orleans Power Station in

rates, unless the two pending appeals in the New Orleans Power Station proceeding have not concluded. Under this circumstance, Entergy New Orleans shall be permitted to defer the New Orleans Power Station non-fuel costs, including the cost of capital, until Entergy New Orleans commences non-fuel cost recovery. After taking into account the requirements for submission of the compliance filing, the total annual revenue requirement reduction required by the resolution was refined to approximately $45 million ($42 million electric, including $29 million in rider reductions; $3 million gas). In January 2020 the City Council’s advisors found that the rates calculated by Entergy New Orleans and reflected in the December 2019 compliance filing should be implemented, except with respect to the City Council-approved energy efficiency cost recovery rider, which rider calculation should take into account events to be determined by the City Council in the future. Also in response to the resolution, Entergy New Orleans filed timely a petition for appeal and judicial review and for stay of or injunctive relief alleging that the resolution is unlawful in failing to produce just and reasonable rates. A hearing on the requested injunction was scheduled in Civil District Court for February 2020, but by joint motion of the City Council and Entergy New Orleans, the Civil District Court issued an order for a limited remand to the City Council to consider a potential agreement in principle/stipulation at its February 20, 2020 meeting. On February 17, 2020, Entergy New Orleans filed with the City Council an agreement in principle between Entergy New Orleans and the City Council’s advisors. On February 20, 2020, the City Council voted to approve the proposed agreement in principle and issued a resolution modifying the required treatment of certain accumulated deferred income taxes. As a result of the agreement in principle, the total annual revenue requirement reduction will be approximately $45 million ($42 million electric, including $29 million in rider reductions; and $3 million gas). Entergy New Orleans fully implemented the new rates in April 2020. In January 2021, pursuant to the agreement in principle approved by the City Council in October 2020, Entergy New Orleans filed with Civil District Court a motion seeking to dismiss its petition for judicial review of the City Council’s resolution in the 2018 combined rate case.

Commercial operation of the New Orleans Power Station commenced in May 2020. In accordance with the City Council resolution issued in the 2018 base rate case proceeding, Entergy New Orleans had been deferring the New Orleans Power Station non-fuel costs pending the conclusion of the appellate proceedings. In October 2020 the Louisiana Supreme Court denied all writ applications relating to the New Orleans Power Station. With those denials, Entergy New Orleans began recovering New Orleans Power Station costs in rates in November 2020. As of December 31, 2020 the regulatory asset for the deferral of New Orleans Power Station non-fuel costs was $5 million. Entergy New Orleans is recovering the costs over a five-year period that began in November 2020. In December 2020 the Alliance for Affordable Energy and Sierra Club filed a joint motion with the City Council to institute a prudence review to investigate the costs of the New Orleans Power Station. On January 28, 2021, the City Council passed a resolution giving parties 30 days to respond to the motion. Entergy New Orleans plans to respond to the motion.

2020 Formula Rate Plan Filing

Entergy New Orleans’s first annual filing under the three-year formula rate plan approved by the City Council in November 2019 was originally due to be filed in April 2020. The authorized return on equity under the approved three-year formula rate plan is 9.35% for both electric and gas operations. The City Council approved several extensions of the deadline to allow additional time to assess the effects of the COVID-19 pandemic on the New Orleans community, Entergy New Orleans customers, and Entergy New Orleans itself. In October 2020 the City Council approved an agreement in principle filed by Entergy New Orleans that results in Entergy New Orleans foregoing its 2020 formula rate plan filing and shifting the three-year formula rate plan to filings in 2021, 2022, and 2023. Key provisions of the agreement in principle include: changing the lower of actual equity ratio or 50% equity ratio approved in the rate case to a hypothetical capital structure of 51% equity and 49% debt for the duration of the three-year formula rate plan; changing the 2% depreciation rate for the New Orleans Power Station approved in the rate case to 3%; retention of over-recovery of $2.2 million in rider revenues; recovery of $1.4 million of certain rate case expenses outside of the earnings band; recovery of the New Orleans Solar Station costs upon commercial operation; and Entergy New Orleans’s dismissal of its 2018 rate case appeal.

COVID-19 Orders

In March 2020, Entergy New Orleans voluntarily suspended customer disconnections for non-payment of utility bills through May 2020. Subsequently, the City Council ordered that the moratorium be extended to August 1, 2020. In May 2020 the City Council issued an accounting order authorizing Entergy New Orleans to establish a regulatory asset for incremental COVID-19-related expenses. In January 2021, Entergy New Orleans resumed disconnecting service to commercial and small business customers with past-due balances that have not made payment arrangements. In February 2021 the City Council adopted a resolution suspending residential customer disconnections for non-payment of utility bills and suspending the assessment and accumulation of late fees on residential customers with past-due balances through May 15, 2021. As of December 31, 2020, Entergy New Orleans recorded a regulatory asset of $14.3 million for costs associated with the COVID-19 pandemic.

In June 2020 the City Council established the City Council Cares Program and directed Entergy New Orleans to use the approximately $7 million refund received from the Entergy Arkansas opportunity sales FERC proceeding, currently being held in escrow, and approximately $15 million of non-securitized storm reserves to fund this program, which is intended to provide temporary bill relief to customers who become unemployed during the COVID-19 pandemic. The program became effective July 1, 2020, and offers qualifying residential customers bill credits of $100 per month for up to four months, for a maximum of $400 in residential customer bill credits. As of December 31, 2020, credits of $3.4 million have been applied to customer bills under the City Council Cares Program.

Filings with the PUCT and Texas Cities (Entergy Texas)

Retail Rates

2018 Base Rate Case

In May 2018, Entergy Texas filed a base rate case with the PUCT seeking an increase in base rates and rider rates of approximately $166 million, of which $48 million is associated with moving costs currently being collected through riders into base rates such that the total incremental revenue requirement increase is approximately $118 million. The base rate case was based on a 12-month test year ending December 31, 2017. In addition, Entergy Texas included capital additions placed into service for the period of April 1, 2013 through December 31, 2017, as well as a post-test year adjustment to include capital additions placed in service by June 30, 2018.

In October 2018 the parties filed an unopposed settlement resolving all issues in the proceeding and a motion for interim rates effective for usage on and after October 17, 2018. The unopposed settlement reflects the following terms: a base rate increase of $53.2 million (net of costs realigned from riders and including updated depreciation rates), a $25 million refund to reflect the lower federal income tax rate applicable to Entergy Texas from January 25, 2018 through the date new rates are implemented, $6 million of capitalized skylining tree hazard costs will not be recovered from customers, $242.5 million of protected excess accumulated deferred income taxes, which includes a tax gross-up, will be returned to customers through base rates under the average rate assumption method over the lives of the associated assets, and $185.2 million of unprotected excess accumulated deferred income taxes, which includes a tax gross-up, will be returned to customers through a rider. The unprotected excess accumulated deferred income taxes rider will include carrying charges and will be in effect over a period of 12 months for large customers and over a period of four years for other customers. The settlement also provides for the deferral of $24.5 million of costs associated with the remaining book value of the Neches and Sabine 2 plants, previously taken out of service, to be recovered over a ten-year period and the deferral of $20.5 million of costs associated with Hurricane Harvey to be recovered over a 12-year period, each beginning in October 2018. The settlement provides final resolution of all issues in the matter, including those related to the Tax Act. In October 2018 the ALJ granted the unopposed motion for interim rates to be effective for service rendered on or after October 17, 2018. In December 2018 the PUCT issued an order approving the unopposed settlement.

Distribution Cost Recovery Factor (DCRF) Rider

In March 2019, Entergy Texas filed with the PUCT a request to set a new DCRF rider. The proposed new DCRF rider is designed to collect approximately $3.2 million annually from Entergy Texas’s retail customers based on its capital invested in distribution between January 1, 2018 and December 31, 2018. In September 2019 the PUCT issued an order approving rates, which had been effective on an interim basis since June 2019, at the level proposed in Entergy Texas’s application.

In March 2020, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The proposed rider is designed to collect from Entergy Texas’s retail customers approximately $23.6 million annually, or $20.4 million in incremental annual DCRF revenue beyond Entergy Texas’s then-effective DCRF rider, based on its capital invested in distribution between January 1, 2019 and December 31, 2019. In May and June 2020 intervenors filed testimony recommending reductions in Entergy Texas’s annual revenue requirement of approximately $0.3 million and $4.1 million. The parties briefed the contested issues in this matter and a proposal for decision was issued in September 2020 recommending a $4.1 million revenue reduction related to non-Advanced Metering System meters included in the DCRF calculation. The parties filed exceptions to the proposal for decision and replies to those exceptions in September 2020. In October 2020 the PUCT issued a final order approving a $16.3 million incremental annual DCRF revenue increase.

In October 2020, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The proposed rider is designed to collect from Entergy Texas’s retail customers approximately $26.3 million annually, or $6.8 million in incremental annual revenues beyond Entergy Texas’s currently effective DCRF rider based on its capital invested in distribution between January 1, 2020 and August 31, 2020. In February 2021 the administrative law judge with the State Office of Administrative Hearings approved Entergy Texas's agreed motion for interim rates, which will go into effect in March 2021. The administrative law judge also adopted a procedural schedule setting a hearing on the merits, if necessary, in April 2021.

Transmission Cost Recovery Factor (TCRF) Rider

In December 2018, Entergy Texas filed with the PUCT a request to set a new TCRF rider. The proposed new TCRF rider is 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 August 2019, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The amended TCRF rider is designed to collect approximately $19.4 million annually from Entergy Texas’s retail customers based on its capital invested in transmission between January 1, 2018 and June 30, 2019, which is $16.7 million in incremental annual revenue above the $2.7 million approved in the prior pending TCRF proceeding. In January 2020 the PUCT issued an order approving an unopposed settlement providing for recovery of the requested revenue requirement. Entergy Texas implemented the amended rider beginning with bills covering usage on and after January 23, 2020.

In October 2020, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The proposed rider is designed to collect from Entergy Texas’s retail customers approximately $51 million annually, or $31.6 million in incremental annual revenues beyond Entergy Texas’s currently effective TCRF rider based on its capital invested in transmission between July 1, 2019 and August 31, 2020. A procedural schedule was established with a hearing scheduled in March 2021. In February 2021, Entergy Texas filed an agreed motion to abate the procedural schedule, noting that the parties had reached a settlement in principle, and the administrative law judge granted the motion to abate.

COVID-19 Orders

In March 2020 the PUCT authorized electric utilities to record as a regulatory asset expenses resulting from the effects of COVID-19. In future proceedings the PUCT will consider whether each utility's request for recovery of these regulatory assets is reasonable and necessary, the appropriate period of recovery, and any amount of carrying costs thereon. In March 2020 the PUCT ordered a moratorium on disconnections for nonpayment for all customer classes, but, in April 2020, revised the disconnect moratorium to apply only to residential customers. The PUCT allowed the moratorium to expire on June 13, 2020, but on July 17, 2020, the PUCT re-established the disconnect moratorium for residential customers until August 31, 2020. In January 2021, Entergy Texas resumed disconnections for customers with past-due balances that have not made payment arrangements. As of December 31, 2020, Entergy Texas recorded a regulatory asset of $12.9 million for costs associated with the COVID-19 pandemic.

Generation Cost Recovery Rider

In October 2020, Entergy Texas filed an application to establish a generation cost recovery rider with an initial annual revenue requirement of approximately $91 million to begin recovering a return of and on its capital investment in the Montgomery County Power Station through August 31, 2020. In December 2020, Entergy Texas filed an unopposed settlement supporting a generation cost recovery rider with an annual revenue requirement of approximately $86 million. The settlement revenue requirement is based on a depreciation rate intended to fully depreciate Montgomery County Power Station over 38 years and the removal of certain costs from Entergy Texas’s request. Under the settlement, Entergy Texas retains the right to propose a different depreciation rate and seek recovery of a majority of the costs removed from its request in its next base rate proceeding. On January 14, 2021, the PUCT approved the generation cost recovery rider settlement rates on an interim basis and abated the proceeding. Within 60 days of Montgomery County Power Station being placed in service on January 1, 2021, Entergy Texas will file to update its generation cost recovery rider to include investment in Montgomery County Power Station after August 31, 2020. The current estimated cost of Montgomery County Power Station, including transmission interconnection and network upgrades, is approximately $921 million. Of this investment, approximately $765 million is eligible to begin being recovered through the generation cost recovery rider. Entergy Texas will address recovery of the remainder of its Montgomery County Power Station investment through other rate mechanisms.

In December 2020, Entergy Texas filed an application to amend its generation cost recovery rider to reflect its acquisition of the Hardin County Peaking Facility, which is expected to close in April 2021. The initial generation cost recovery rider rates proposed in the application represent no change from the generation cost recovery rider rates to be established in Entergy Texas’ previous generation cost recovery rider proceeding. Once Entergy Texas has acquired the Hardin County Peaking Facility, its investment in the facility will be reflected in the updated filing to Entergy Texas’ application, which will be made within 60 days of the acquisition’s closing.

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. The December 2018 compliance filing is pending FERC action. 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)
	Principal	Interest	Total
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 have been 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 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.

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 scheduled a hearing for February 26, 2021 regarding issues addressed in the pre-trial conference report.

Complaints Against System Energy

Return on Equity and Capital Structure Complaints

In January 2017 the APSC and MPSC filed a complaint with the FERC against System Energy. The complaint seeks 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 current return on equity under the Unit Power Sales Agreement is 10.94%, which was established in a rate proceeding that became final in July 2001.

The APSC and MPSC complaint alleges that the return on equity is unjust and unreasonable because capital market and other considerations indicate that it is excessive. The complaint requests proceedings to investigate the return on equity and establish a lower return on equity, and also requests that the FERC establish January 23, 2017 as a refund effective date. The complaint includes return on equity analysis that purports to establish that the range of reasonable return on equity for System Energy is between 8.37% and 8.67%. System Energy answered the complaint in February 2017 and disputes that a return on equity of 8.37% to 8.67% is 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 have been 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 requests similar relief from the FERC with respect to System Energy’s return on equity and also requests the FERC to investigate System Energy’s capital structure. The APSC, MPSC, and 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 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 MPSC complaint for hearing. The parties addressed an order (issued in a separate proceeding involving New England transmission owners) that proposed modifying the FERC’s standard methodology for determining return on equity. In September 2018, System Energy filed a request for rehearing and the LPSC filed a request for rehearing or reconsideration of the FERC’s August 2018 order. The LPSC’s request referenced an amended complaint that it filed on the same day 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 submitted a response 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. As noted below, in June 2019 settlement discussions were terminated 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.

In January 2019 the LPSC and the APSC and MPSC filed direct testimony in the return on equity proceeding. For the refund period January 23, 2017 through April 23, 2018, the LPSC argues for an authorized return on equity for System Energy of 7.81% and the APSC and MPSC argue for an authorized return on equity for System Energy of 8.24%. For the refund period April 27, 2018 through July 27, 2019, and for application on a prospective basis, the LPSC argues for an authorized return on equity for System Energy of 7.97% and the APSC and MPSC argue for an authorized return on equity for System Energy of 8.41%. In March 2019, System Energy submitted answering testimony. For the first refund period, System Energy’s testimony argues for a return on equity of 10.10% (median) or 10.70% (midpoint). For the second refund period, System Energy’s testimony shows that the calculated returns on equity for the first period fall within the range of presumptively just and reasonable returns on equity, and thus the second complaint should be dismissed (and the first period return on equity used going forward). If the FERC nonetheless were to set a new return on equity for the second period (and going forward), System Energy argues the return on equity should be either 10.32% (median) or 10.69% (midpoint).

In May 2019 the FERC trial staff filed its direct and answering testimony in the return on equity proceeding. For the first refund period, the FERC trial staff calculates an authorized return on equity for System Energy of 9.89% based on the application of FERC’s proposed methodology. The FERC trial staff’s direct and answering testimony noted that an authorized return on equity of 9.89% for the first refund period was within the range of presumptively just and reasonable returns on equity for the second refund period, as calculated using a study period ending January 31, 2019 for the second refund period.

In June 2019, System Entergy filed testimony responding to the testimony filed by the FERC trial staff. Among other things, System Energy’s testimony rebutted arguments raised by the FERC trial staff and provided updated calculations for the second refund period based on the study period ending May 31, 2019. For that refund period, System Energy’s testimony shows that strict application of the return on equity methodology proposed by the FERC staff indicates that the second complaint would not be dismissed, and the new return on equity would be set at 9.65% (median) or 9.74% (midpoint). System Energy’s testimony argues that these results are insufficient in light of benchmarks such as state returns on equity and treasury bond yields, and instead proposes that the calculated returns on equity for the second period should be either 9.91% (median) or 10.3% (midpoint). System Energy’s testimony also argues that, under application of its proposed modified methodology, the 10.10% return on equity calculated for the first refund period would fall within the range of presumptively just and reasonable returns on equity for the second refund period.

Also in June 2019, the FERC’s Chief ALJ issued an order terminating settlement discussions in the amended complaint addressing System Energy’s capital structure. The ALJ consolidated the amended capital structure complaint with the ongoing return on equity proceeding and set new procedural deadlines for the consolidated hearing.

In August 2019 the LPSC and the APSC and MPSC filed rebuttal testimony in the return on equity proceeding and direct and answering testimony relating to System Energy’s capital structure. The LPSC re-argues for an authorized return on equity for System Energy of 7.81% for the first refund period and 7.97% for the second refund period. The APSC and MPSC argue for an authorized return on equity for System Energy of 8.26% for the first refund period and 8.32% for the second refund period. With respect to capital structure, the LPSC proposes that the FERC establish a hypothetical capital structure for System Energy for ratemaking purposes. Specifically, the LPSC proposes that System Energy’s common equity ratio be set to Entergy Corporation’s equity ratio of 37% equity and 63% debt. In the alternative, the LPSC argues that the equity ratio should be no higher than 49%, the composite equity ratio of System Energy and the other Entergy operating companies who purchase under the Unit Power Sales Agreement. The APSC and MPSC recommend that 35.98% be set as the common equity ratio for System Energy. As an alternative, the APSC and MPSC propose that System Energy’s common equity be set at 46.75% based on the median equity ratio of the proxy group for setting the return on equity.

In September 2019 the FERC trial staff filed its rebuttal testimony in the return on equity proceeding. For the first refund period, the FERC trial staff calculates an authorized return on equity for System Energy of 9.40% based on the application of the FERC’s proposed methodology and an updated proxy group. For the second refund period, based on the study period ending May 31, 2019, the FERC trial staff rebuttal testimony argues for a return on equity of 9.63%. In September 2019 the FERC trial staff also filed direct and answering testimony relating to System Energy’s capital structure. The FERC trial staff argues 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 calculates the average capital structure for its proposed proxy group of 46.74% common equity, and 53.26% debt.

In October 2019, System Energy filed answering testimony disputing the FERC trial staff’s, the LPSC’s, and the APSC’s and MPSC’s arguments for the use of a hypothetical capital structure and arguing that the use of System Energy’s actual capital structure is just and reasonable.

In November 2019, in a proceeding that did not involve System Energy, the FERC issued an order addressing the methodology for determining the return on equity applicable to transmission owners in MISO. Thereafter, the procedural schedule in the System Energy proceeding was amended to allow the participants to file supplemental testimony addressing the order in the MISO transmission owner proceeding (Opinion No. 569).

In February 2020 the LPSC, the MPSC and APSC, and the FERC trial staff filed supplemental testimony addressing Opinion No. 569 and how it would affect the return on equity evaluation for the two complaint periods concerning System Energy. For the first refund period, based on their respective interpretations and applications of the Opinion No. 569 methodology, the LPSC argues for an authorized return on equity for System Energy of 8.44%; the MPSC and APSC argue for an authorized return on equity of 8.41%; and the FERC trial staff argues for an authorized return on equity of 9.22%. For the second refund period and on a prospective basis, based on their respective interpretations and applications of the Opinion No. 569 methodology, the LPSC argues for an authorized return on equity for System Energy of 7.89%; the MPSC and APSC argue that an authorized return on equity of 8.01% may be appropriate; and the FERC trial staff argues for an authorized return on equity of 8.66%.

In April 2020, System Energy filed supplemental answering testimony addressing Opinion No. 569. System Energy argues that the Opinion No. 569 methodology is conceptually and analytically defective for purposes of establishing just and reasonable authorized return on equity determinations and proposes an alternative approach. As its primary recommendation, System Energy continues to support the return on equity determinations in its March 2019 testimony for the first refund period and its June 2019 testimony for the second refund period. Under the Opinion No. 569 methodology, System Energy calculates a “presumptively just and reasonable range” for the authorized return on equity for the first refund period of 8.57% to 9.52%, and for the second refund period of 8.28% to 9.11%. System Energy argues that these ranges are not just and reasonable results. Under its proposed alternative methodology, System Energy calculates an authorized return on equity of 10.26% for the first refund period, which also falls within the presumptively just and reasonable range calculated for the second refund period and prospectively.

In May 2020 the FERC issued an order on rehearing of Opinion No. 569 (Opinion No. 569-A). In June 2020 the procedural schedule in the System Energy proceeding was further revised in order to allow parties to address the Opinion No. 569-A methodology. Pursuant to the revised schedule, in June 2020, the LPSC, MPSC and APSC, and the FERC trial staff filed supplemental testimony addressing Opinion No. 569-A and how it would affect the return on equity evaluation for the two complaint periods concerning System Energy. For the first refund period, based on their respective interpretations and applications of the Opinion No. 569-A methodology, the LPSC argues for an authorized return on equity for System Energy of 7.97%; the MPSC and APSC argue for an authorized return on equity of 9.24%; and the FERC trial staff argues 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 argues for an authorized return on equity for System Energy of 7.78%; the MPSC and APSC argue that an authorized return on equity of 9.15% may be appropriate if the second complaint is not dismissed; and the FERC trial staff argues for an authorized return on equity of 9.09% if the second complaint is not dismissed.

Pursuant to the revised procedural schedule, in July 2020, System Energy filed supplemental testimony addressing Opinion No. 569-A. System Energy argues 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. As its primary recommendation, System Energy argues for the use of a methodology that incorporates four separate financial models, including the constant growth form of the discounted cash flow model and the empirical capital asset pricing model. Based on application of its recommended methodology, System Energy argues for an authorized return on equity of 10.12% for the first refund period, which also falls within the presumptively just and reasonable range calculated for the second refund period and prospectively. Under the Opinion No. 569-A methodology, System Energy calculates an authorized return on equity of 9.44% for the first refund period, which also falls within the presumptively just and reasonable range calculated for the second refund period and prospectively.

The parties and FERC trial staff filed final rounds of testimony in August 2020. The hearing before a FERC ALJ occurred in late-September through early-October 2020, post-hearing briefing took place in November and December 2020, and the initial decision is due in March 2021. System Energy recorded a provision against revenue for the potential outcome of this proceeding.

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 alleges 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 is double-recovering costs by including both the lease payments and the capital additions in Unit Power Sales Agreement billings. The complaint also claims 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 alleges that System Energy violated various other reporting and accounting requirements and should have sought prior FERC approval of the lease renewal. The complaint seeks various forms of relief from the FERC. The complaint seeks 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. The complaint also asks that the FERC disallow and refund the lease costs of the sale-leaseback renewal on grounds of imprudence, investigate System Energy’s treatment of a DOE litigation payment, and impose certain forward-looking procedural protections, including audit rights for retail regulators of the Unit Power Sales Agreement formula rates. The APSC, MPSC, and 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 is inconsistent with a FERC-approved settlement to which the LPSC is a party and that explicitly authorizes 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 fails 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. The FERC established 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. In March 2019 the LPSC, MPSC, APSC and City Council filed direct testimony. The LPSC testimony sought refunds that include 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, and the cost of capital additions associated with the sale-leaseback interest, as well as interest on those amounts.

In June 2019 System Energy filed answering testimony arguing that the FERC should reject all claims for refunds. Among other things, System Energy argued that claims for refunds of the costs of lease renewal payments and capital additions should be rejected because those costs were recovered consistent with the Unit Power Sales Agreement formula rate, System Energy was not over or double recovering any costs, and ratepayers will save costs over the initial and renewal terms of the leases. System Energy argued that claims for refunds associated with liabilities arising from uncertain tax positions should be rejected because the liabilities do not provide cost-free capital, the repayment timing of the liabilities is uncertain, and the outcome of the underlying tax positions is uncertain. System Energy’s testimony also challenged the refund calculations supplied by the other parties.

In August 2019 the FERC trial staff filed direct and answering testimony seeking refunds for rate base reductions for liabilities associated with uncertain tax positions. The FERC trial staff also argued that System Energy recovered $32 million more than it should have in depreciation expense for capital additions. In September 2019, System Energy filed cross-answering testimony disputing the FERC trial staff’s arguments for refunds, stating that the FERC trial staff’s position regarding depreciation rates for capital additions is not unreasonable, but explaining that 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 will also involve changes to accumulated depreciation, accumulated deferred income taxes, and other formula elements as needed. In October 2019 the LPSC filed rebuttal testimony increasing the amount of refunds sought for liabilities associated with uncertain tax positions. The LPSC seeks approximately $512 million plus interest, which is approximately $191 million through December 31, 2020. The FERC trial staff also filed rebuttal testimony in which it seeks refunds of a similar amount as the LPSC for the liabilities associated with uncertain tax positions. The LPSC testimony also argued that adjustments to depreciation rates should affect rate base on a prospective basis only.

A hearing was held before a FERC ALJ in November 2019. In April 2020 the ALJ issued an 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 is 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 is 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 System Energy’s rate base should have been reduced for those liabilities. If the ALJ’s initial decision is upheld, the estimated refund for this issue through December 31, 2020, is approximately $422 million, plus interest, which is approximately $110 million through December 31, 2020. 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. If the initial decision is affirmed on this issue, System Energy estimates refunds of approximately $19 million, which includes interest through December 31, 2020.

The ALJ initial decision is an interim step in the FERC litigation process, and an ALJ’s determinations made in an initial decision are not controlling on the FERC. The ALJ in the initial decision acknowledges that these are issues of first impression before the FERC. 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, MPSC, APSC, City Council, and the FERC trial staff opposed the exceptions filed by System Energy. Also in October 2020 the MPSC, APSC, and the City Council filed briefs adopting the exceptions of the LPSC and the FERC trial staff. The case is pending before the FERC, which will review the case and issue an order on the proceeding, and the FERC may accept, reject, or modify the ALJ’s initial decision in whole or in part. Refunds, if any, that might be required will only become due after the FERC issues its order reviewing the initial decision.

In addition, in September 2020, the IRS issued a Notice of Proposed Adjustment (NOPA) and Entergy executed it. The NOPA memorializes 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 proposes 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, APSC, MPSC, and 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, APSC, MPSC, and 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 propose the inclusion of the RAR as support for the filings. In December 2020 the LPSC, APSC, and City Council filed a protest in response to the amendments, reiterating their prior objections to the filings. 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.

LPSC Authorization of 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 notes 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. The LPSC directive authorizes its staff to file complaints at the FERC “necessary to address these rate issues, to request a full investigation into the rates charged by System Energy for Grand Gulf power, and to seek rate refund, rate reduction, and such other remedies as may be necessary and appropriate to protect Louisiana ratepayers.” The LPSC directive further stated that the LPSC has seen “information suggesting that the Grand Gulf plant has been significantly underperforming compared to other nuclear plants in the United States, has had several extended and unexplained outages, and has been plagued with serious safety concerns.” The LPSC expressed concern that the costs paid by Entergy Louisiana's retail customers may have been detrimentally impacted, and authorized “the filing of a FERC complaint to address these performance issues and to seek appropriate refund, rate reduction, and other remedies as may be appropriate.”

The first of the additional complaints was filed at the FERC by the LPSC, the APSC, the MPSC, and the City Council in September 2020. The new complaint raises 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 overlap with the previous complaints. The filed rate allegations not previously raised are 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 lease refinancing costs in rate base as prepayments; improperly included nuclear decommissioning outage costs in rate base; failed to include categories of accumulated deferred income taxes as a reduction 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 alleges are unjust and unreasonable include: incentive and executive compensation, lack of an equity re-opener, lobbying, and private airplane travel. The new complaint also requests 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 new 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 is warranted because all claims fall into one or more of the following categories: the claims have been raised and are being litigated in another proceeding; the claims do not present a prima facie case and do not satisfy the threshold burden to establish a complaint proceeding; the claims are 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 are barred or waived by the legal doctrine of laches; and/or the claims have 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 January 2021 the

complainants filed a response to System Energy’s November 2020 answer, and in February 2021, System Energy filed a response to the complainant’s response.

The operational prudence-related complaint has not been filed as of this date, and the LPSC directive did not set a date for the filing.

Unit Power Sales Agreement

In August 2017, System Energy submitted to the FERC proposed amendments to 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. The filing proposes limited amendments to the Unit Power Sales Agreement to adopt (1) updated rates for use in calculating Grand Gulf plant depreciation and amortization expenses and (2) updated nuclear decommissioning cost annual revenue requirements, both of which are recovered through the Unit Power Sales Agreement rate formula. The amendments result in lower charges to the Utility operating companies that buy capacity and energy from System Energy under the Unit Power Sales Agreement. The changes were based on updated depreciation and nuclear decommissioning studies that take into account the renewal of Grand Gulf’s operating license for a term through November 1, 2044.

In September 2017 the FERC accepted System Energy’s proposed Unit Power Sales Agreement amendments, subject to further proceedings to consider the justness and reasonableness of the amendments. Because the amendments proposed a rate decrease, the FERC also initiated an investigation under section 206 of the Federal Power Act to determine if the rate decrease should be lower than proposed. The FERC accepted the proposed amendments effective October 1, 2017, subject to refund pending the outcome of the further settlement and/or hearing proceedings, and established a refund effective date of October 11, 2017 with respect to the rate decrease. In June 2018, System Energy filed with the FERC an uncontested settlement relating to the updated depreciation rates and nuclear decommissioning cost annual revenue requirements. In August 2018 the FERC issued an order accepting the settlement. In the third quarter 2018, System Energy recorded a reduction in depreciation expense of approximately $26 million, representing the cumulative difference in depreciation expense resulting from the depreciation rates used from October 11, 2017 through September 30, 2018 and the depreciation rates included in the settlement filing accepted by the FERC.

Storm Cost Recovery Filings with Retail Regulators

Entergy Louisiana

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 Louisiana Utilities Restoration Corporation (LURC) and the Louisiana State Bond Commission.

In August 2014 the Louisiana Local Government Environmental Facilities and Community Development Authority (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 LLC, a company wholly-owned and consolidated by Entergy, that carry a 7.5% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2014, and the membership interests have a liquidation price of $100 per unit. The preferred membership

interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1.75 billion.

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.

In the first quarter 2020, Entergy and the IRS agreed upon and settled on the treatment of funds received by Entergy Louisiana in conjunction with the Act 55 financing of Hurricane Isaac storm costs, which resulted in a net reduction of income tax expense of approximately $32 million. As a result of the settlement, the position was partially sustained and Entergy Louisiana recorded a reduction of income tax expense of approximately $58 million primarily due to the reversal of liabilities for uncertain tax positions in excess of the agreed-upon settlement. Entergy recorded an increase to income tax expense of $26 million primarily resulting from the reduction of the deferred tax asset, associated with utilization of the net operating loss as a result of the settlement. This adjustment recorded by Entergy also accounted for the tax rate change of the Tax Cuts and Jobs Act. As a result of the IRS settlement, Entergy Louisiana recorded a $29 million ($21 million net-of-tax) regulatory charge and a corresponding regulatory liability to reflect its obligation to customers pursuant to the LPSC Hurricane Isaac Act 55 financing order.

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 LLC, a company wholly-owned and consolidated by Entergy, that carry a 9% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2010, and the membership interests have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion.

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 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 LLC, a company wholly-owned and consolidated by Entergy, 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 LLC that carry a 10% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2008 and have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion.

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 are 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

Entergy Mississippi has 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 exceeds $15 million, the collection of the storm damage provision ceases until such time that the accumulated storm damage provision becomes less than $10 million. Entergy Mississippi’s storm damage provision balance has been less than $10 million since May 2019, and Entergy Mississippi has been billing the monthly storm damage provision since July 2019.

Rate And Regulatory Matters

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 probable future revenues associated with costs that Entergy expects to recover from customers through the regulatory ratemaking process under which the Utility business operates. Regulatory liabilities represent probable future reductions in revenues associated with amounts that Entergy expects to benefit customers through the regulatory ratemaking process under which the Utility business operates. 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, 2020 and 2019:

Other Regulatory Assets

Entergy


	2020	2019
	(In Millions)
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)	$3,027.5	$2,942.4
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	1,018.9	920.4
Removal costs (Note 9)	893.8	421.0
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Hurricane Laura, Hurricane Delta, and Hurricane Zeta and Storm Cost Recovery Filings with Retail Regulators and Note 5 - Securitization Bonds)	379.2	372.8
Retired electric and gas meters - recovered through retail rates as determined by retail regulators	192.1	205.6
Opportunity Sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding) (b)	131.8	116.3
Deferred COVID-19 costs recovery period to be determined (Note 2 - Retail Rate Proceedings) (b)	105.7	—
Unamortized loss on reacquired debt - recovered over term of debt	79.2	66.6
Retail rate deferrals - recovered through rate riders as rates are redetermined by retail regulators	66.0	15.7
Attorney General litigation costs - recovered over a six-year period through March 2026 (b)	25.3	29.5
New nuclear generation development costs - recovery through formula rate plan December 2014 through November 2022 (b)	14.2	21.6
Little Gypsy costs – recovered through securitization (Note 5 - Entergy Louisiana Securitization Bonds - Little Gypsy)	7.5	29.9



Other	135.3	150.3
Entergy Total	$6,076.5	$5,292.1

Entergy Arkansas


	2020	2019
	(In Millions)
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)	$831.5	$796.5
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	479.3	433.0
Removal costs (Note 9)	212.6	168.9
Opportunity sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding) (b)	131.8	116.3
Retired electric meters - recovered over 15-year period through March 2034	46.9	50.4
Storm damage costs - recovered either through securitization or retail rates (Note 5 - Entergy Arkansas Securitization Bonds)	42.7	46.1
Unamortized loss on reacquired debt - recovered over term of debt	24.7	18.3
Retail rate deferrals - recovered through rate riders as rates are redetermined annually (b)	12.6	2.3
Deferred COVID-19 costs - recovery period to be determined (Note 2 - Retail Rate Proceedings) (b)	10.5	—
ANO Fukushima and Flood Barrier costs - recovered through retail rates through February 2026 (Note 2 - Retail Rate Proceedings) (b)	9.1	10.9
Other	30.7	24.2
Entergy Arkansas Total	$1,832.4	$1,666.9

Entergy Louisiana


	2020	2019
	(In Millions)
Pension & postretirement costs (Note 11 - Qualified Pension Plans and Non-Qualified Pension Plans) (a)	$799.4	$787.7
Removal costs (Note 9)	302.5	—
Asset Retirement Obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	299.0	262.5
Retired electric meters - recovered over a 22-year period through July 2041	96.4	101.1
Storm damage costs - recovered through retail rates (Note 2 - Hurricane Laura, Hurricane Delta, and Hurricane Zeta and Storm Cost Recovery Filings with Retail Regulators)	94.0	45.7
Deferred COVID-19 costs - recovery period to be determined (Note 2 - Retail Rate Proceedings) (b)	48.8	—
Unamortized loss on reacquired debt - recovered over term of debt	26.6	20.4
New nuclear generation development costs - recovery through formula rate plan December 2014 through November 2022 (b)	14.0	21.2
Business combination external costs deferral - recovery through formula rate plan December 2015 through November 2025 (b)	9.2	10.8
River Bend AFUDC - recovered through August 2025 (Note 1 - River Bend AFUDC)	7.2	9.1
Little Gypsy costs – recovered through securitization (Note 5 - Entergy Louisiana Securitization Bonds - Little Gypsy)	5.1	27.6
Other	23.9	29.1
Entergy Louisiana Total	$1,726.1	$1,315.2

Entergy Mississippi


	2020	2019
	(In Millions)
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)	$242.7	$234.4
Removal costs (Note 9)	107.3	80.8
Retail rate deferrals - returned through rate riders as rates are redetermined annually	44.3	7.5
Attorney General litigation costs - recovered over a six-year period through March 2026 (b)	25.3	29.5
Deferred COVID-19 costs - recovery period to be determined (Note 2 - Retail Rate Proceedings) (b)	19.2	—
Unamortized loss on reacquired debt - recovered over term of debt	13.5	14.9
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a)	7.9	7.8
Other	7.1	3.1
Entergy Mississippi Total	$467.3	$378.0

Entergy New Orleans


	2020	2019
	(In Millions)
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)	$75.7	$85.9
Removal costs - (Note 9)	63.2	52.9
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Hurricane Laura, Hurricane Delta, and Hurricane Zeta and Note 5 - Entergy New Orleans Securitization Bonds - Hurricane Isaac)	55.2	59.6
Retired meters - recovered over a 12-year period through July 2031 (b)	21.7	24.6
Deferred COVID-19 costs recovery period to be determined (Note 2 - Retail Rate Proceedings) (b)	14.3	—

Rate case costs - recovered over a three-year period through July 2022 (Note 2 - Retail Rate Proceedings)	5.7	7.0
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a)	5.2	4.9
New Orleans Power Station deferral – recovered over a five-year period through October 2025 (Note 2 - Retail Rate Proceedings)	5.0	—

Algiers customer migration costs - recovered over a five-year period through July 2024 (Note 2 - Retail Rate Proceedings)	3.9	4.9
Unamortized loss on reacquired debt - recovered over term of debt	1.9	2.3

Other	15.0	17.3
Entergy New Orleans Total	$266.8	$259.4

Entergy Texas


	2020	2019
	(In Millions)
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Hurricane Laura, Hurricane Delta, and Hurricane Zeta and Note 5 - Entergy Texas Securitization Bonds)	$187.3	$221.4
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)	140.1	167.7
Removal costs (Note 9)	115.3	42.5
Retired electric meters - recovered over 13-year period through February 2032	26.0	28.4
Neches and Sabine costs - recovered over a 10-year period through September 2028 (Note 2 - Retail Rate Proceedings)	18.8	21.2
Deferred COVID-19 costs recovery period to be determined (Note 2 - Retail Rate Proceedings) (b)	12.9	—
Unamortized loss on reacquired debt - recovered over term of debt	10.5	7.7
Transition to competition costs - recovered over a 15-year period through February 2021	2.1	14.9

Other	11.7	8.8
Entergy Texas Total	$524.7	$512.6

System Energy


	2020		2019
	(In Millions)
Asset retirement obligation - recovery dependent upon timing of decommissioning (Note 9) (a)	$226.3		$210.9
Pension & postretirement costs (Note 11 - Qualified Pension Plans and Other Postretirement Benefits) (a)	217.8		200.3
Removal costs - recovered through depreciation rates (Note 9)	92.9		75.9
Unamortized loss on reacquired debt - recovered over term of debt	2.0		3.0
System Energy Total	$	539.0	$	490.1

(a)Does not earn a return on investment, but is offset by related liabilities.

(b)Does not earn a return on investment.

Hurricane Laura, Hurricane Delta, and Hurricane Zeta

In August and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of the Utility’s service territories in Louisiana, including New Orleans, Texas, and, to a lesser extent, in Arkansas and Mississippi. The storms resulted in widespread power 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. Total restoration costs for the repair and/or replacement of the electrical system damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta are currently estimated to be approximately $2.4 billion, including $2.0 billion at Entergy Louisiana, $300 million at Entergy Texas, and $40 million at Entergy New Orleans. The estimate includes approximately $1.98 billion in capital costs, including $1.67 billion at Entergy Louisiana, $245 million at Entergy Texas, and $30 million at Entergy New Orleans and approximately $420 million in non-capital costs, including $330 million at Entergy Louisiana, $55 million at Entergy Texas, and $10 million at Entergy New Orleans. This estimate includes all costs to restore power and repair or replace the damages from the hurricanes, except for the cost to repair or replace damage incurred to an Entergy Louisiana transmission line in southeast Louisiana, and the amount of that cost could be significant. The restoration plan for this transmission line and the related cost estimate is still being evaluated.

Entergy recorded accounts payable and corresponding construction work in progress and regulatory assets for the estimated costs incurred that were necessary to return customers to service. Entergy recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. There are well-established mechanisms and precedent for addressing these catastrophic events and providing for recovery of prudently incurred storm costs in accordance with applicable regulatory and legal principles. Because Entergy has not gone through the regulatory process regarding these storm costs, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.

The Utility operating companies are considering all available avenues to recover storm-related costs from Hurricane Laura, Hurricane Delta, and Hurricane Zeta including accessing funded storm reserve escrows and securitization. In November 2020, Entergy Louisiana drew $257 million from its funded storm reserves. Each Utility operating company is responsible for its restoration cost obligations and for recovering or financing its storm-related costs. Storm cost recovery or financing will be subject to review by applicable regulatory authorities.

In October 2020, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments to facilitate issuance of shorter-term 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.

In December 2020, Entergy Louisiana provided the LPSC with notification that it intends to initiate a storm cost recovery proceeding in the near future, which will permit the LPSC to retain any outside consultants and counsel needed to review the storm cost recovery application. In February 2021 the LPSC voted to retain outside counsel and consultants to assist in the review of Entergy Louisiana’s upcoming storm cost recovery application, which is expected to be filed in March 2021.

Other Regulatory Liabilities

Entergy


	2020	2019
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)	$1,694.1	$1,300.1
Louisiana Act 55 financing savings obligation (Note 3) (b)	144.3	97.1
Vidalia purchased power agreement (Note 8) (b)	115.7	127.3
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually	75.1	62.3
Grand Gulf sale-leaseback - (Note 5 - Grand Gulf Sale-Leaseback Transactions)	55.6	55.6
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
Future formula rate plan revenue reductions (Note 2 - Retail Rate Proceedings)	43.5	51.1
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)	29.7	37.2
Internal restructuring guaranteed tax credits (Note 2 - Internal Restructuring)	26.4	33.0
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates December 2015 through November 2024	21.5	35.7
Advanced metering system (AMS) surcharge - return to customers dependent upon AMS spend	20.1	25.3
Excess decommissioning recovery for Willow Glen - (Note 14 - Dispositions)	—	21.2
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement	10.7	17.8
Income tax rate change - returned to electric and gas customers through retail rates (Note 2 - Retail Rate Proceedings)	7.3	13.9


Other	35.5	39.0
Entergy Total	$2,323.9	$1,961.0

Entergy Arkansas


	2020	2019
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)	$597.4	$460.3

Future formula rate plan revenue reductions (Note 2 - Retail Rate Proceedings)	43.5	46.6
Internal restructuring guaranteed customer credits (Note 2 - Retail Rate Proceedings)	26.4	33.0
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually	19.6	19.7

Entergy Arkansas Total	$686.9	$559.6

Entergy Louisiana


	2020	2019
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)	$567.7	$436.5
Louisiana Act 55 financing savings obligation (Note 3)	144.3	97.1
Vidalia purchased power agreement (Note 8) (b)	115.7	127.3
Asset Retirement Obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)	29.7	37.1
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates December 2015 through November 2024	21.5	35.7


Excess decommissioning recovery for Willow Glen - returned over one-year period through retail rates (Note 14 - Dispositions)	—	21.2




Other	39.4	39.2
Entergy Louisiana Total	$918.3	$794.1

Entergy Mississippi


	2020	2019
	(In Millions)
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually	$14.2	$14.6
Grand Gulf Over-Recovery - returned to customers through rate riders as rates are redetermined annually	1.0	2.4
Future formula rate plan revenue reductions (Note 2 - Retail Rate Proceedings)	—	4.5
Other	0.6	—
Entergy Mississippi Total	$15.8	$21.5

Entergy Texas


	2020	2019
	(In Millions)
Advanced metering system (AMS) surcharge - returned to customers dependent upon AMS spend	$20.1	$25.3
Income tax rate change - refunded through a rate rider (Note 2 - Retail Rate Proceedings)	6.5	10.4
Transition to competition costs - returned to customers through rate riders when rates are redetermined periodically	3.2	3.8
Other	2.5	2.6
Entergy Texas Total	$32.3	$42.1

System Energy


	2020	2019
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)	$529.0	$403.3
Grand Gulf sale-leaseback - (Note 5 - Grand Gulf Sale-Leaseback Transactions)	55.6	55.6
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
Grand Gulf sale-leaseback accumulated deferred income taxes (a)	25.7	12.3
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement	10.7	17.8

System Energy Total	$665.4	$533.4

(a)Offset by related asset.

(b)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% effective January 2018, the Vidalia purchased power agreement regulatory liability was reduced by $30.5 million and the Louisiana Act 55 financing savings obligation regulatory liabilities were reduced by $25 million, with corresponding increases 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.

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, including its effects on Entergy’s and the Registrant Subsidiaries’ regulatory asset/liability for income taxes.

Entergy Arkansas

Consistent with its previously stated intent to return unprotected excess accumulated deferred income taxes to customers as expeditiously as possible, Entergy Arkansas initiated a tariff proceeding in February 2018 proposing to establish a tax adjustment rider to provide retail customers with certain tax benefits of $467 million associated with the Tax Act. For the residential customer class, unprotected excess accumulated deferred income taxes were returned to customers over a 21-month period from April 2018 through December 2019. For all other customer classes, unprotected excess accumulated deferred income taxes were returned to customers over a nine-month period from April 2018 through December 2018. A true-up provision also was included in the rider, with any over- or under-returned unprotected excess accumulated deferred income taxes credited or billed to customers during the billing month of January 2020, with any residual amounts of over- or under-returned unprotected excess

accumulated deferred income taxes to be flowed through Entergy Arkansas’s energy cost recovery rider. In March 2018 the APSC approved the tax adjustment rider effective with the first billing cycle of April 2018.

As discussed below, in July 2018, Entergy Arkansas made its formula rate plan filing to set its formula rate for the 2019 calendar year. A hearing was held in May 2018 regarding the APSC’s inquiries into the effects of the Tax Act, including Entergy Arkansas’s proposal to utilize its formula rate plan rider for its customers to realize the remaining benefits of the Tax Act. Entergy Arkansas’s formula rate plan rider included a netting adjustment that compared actual annual results to the allowed rate of return on common equity. In July 2018 the APSC issued an order agreeing with Entergy Arkansas’s proposal to have the effects of the Tax Act on current income tax expense flow through Entergy Arkansas’s formula rate plan rider and with Entergy Arkansas’s treatment of protected and unprotected excess accumulated deferred income taxes. The APSC also directed Entergy Arkansas to submit in the tax adjustment rider proceeding, discussed above, the adjustments to all other riders affected by the Tax Act and to include an amendment for a true up mechanism where a rider affected by the Tax Act does not already contain a true-up mechanism. Pursuant to a 2018 settlement agreement in Entergy Arkansas’s formula rate plan proceeding, Entergy Arkansas also removed the net operating loss accumulated deferred income tax asset caused by the Tax Act from Entergy Arkansas’s tax adjustment rider. Entergy Arkansas’s compliance tariff filings were accepted by the APSC in October 2018. In February 2021, pursuant to its 2020 formula rate plan evaluation report settlement, Entergy Arkansas flowed $5.6 million in credits to customers through the tax adjustment rider based on the outcome of certain federal tax positions and a decrease in the state tax rate; the tax adjustment rider will be closed after the credits are issued.

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 which, as discussed below, Entergy Louisiana filed in June 2018.

Entergy Mississippi

Entergy Mississippi filed its 2018 formula rate plan in March 2018 and included a proposal to return all of its unprotected excess accumulated deferred income taxes to customers through rates or in exchange for other assets, or a combination of both, by the end of 2018. In June 2018 the MPSC approved a stipulation filed by Entergy Mississippi and the Mississippi Public Utilities Staff in Entergy Mississippi’s formula rate plan filing that addressed Entergy Mississippi’s 2018 formula rate plan evaluation report and the ratemaking effects of the Tax Act. The stipulation provided for incorporating the reduction of the statutory federal income tax rate through Entergy Mississippi’s formula rate plan. The stipulation approved in June 2018 provided for the flow-back of protected excess accumulated deferred income taxes over the remaining lives of the assets through the formula rate plan. The stipulation also provided for the offset of unprotected excess accumulated deferred income taxes of $127.2 million against net utility plant and $2.2 million against other regulatory assets, and the return to customers of the remaining balance of unprotected excess accumulated deferred income taxes as recovery of a portion of fuel oil inventory and customer bill credits over a three-month period from July 2018 through September 2018, with an insignificant true-up reflected in the November 2018 power management rider filing. Entergy Mississippi recorded the reduction against net utility plant and other regulatory assets in June 2018. In third quarter 2018, Entergy Mississippi returned

unprotected excess accumulated deferred income taxes of $25.8 million through customer bill credits and $5.8 million through the sale of fuel oil inventory.

Entergy New Orleans

After enactment of the Tax Act the City Council passed a resolution ordering Entergy New Orleans to, effective January 1, 2018, record deferred regulatory liabilities to account for the Tax Act’s effect on Entergy New Orleans’s revenue requirement and to make a filing by mid-March 2018 regarding the Tax Act’s effects on Entergy New Orleans’s operating income and rate base and potential mechanisms for customers to receive benefits of the Tax Act. The City Council’s resolution also directed Entergy New Orleans to request that Entergy Services file with the FERC for revisions of the Unit Power Sales Agreement and MSS-4 replacement tariffs to address the return of excess accumulated deferred income taxes. Entergy submitted filings of this type to the FERC.

In March 2018, Entergy New Orleans filed its response to the resolution stating that the Tax Act reduced income tax expense from what was then reflected in rates by approximately $8.2 million annually for electric operations and by approximately $1.3 million annually for gas operations. In the filing, Entergy New Orleans proposed to return to customers from June 2018 through August 2019 the benefits of the reduction in income tax expense and its unprotected excess accumulated deferred income taxes through a combination of bill credits and investments in energy efficiency programs, grid modernization, and Smart City projects. Entergy New Orleans submitted supplemental information in April 2018 and May 2018. Shortly thereafter, Entergy New Orleans and the City Council’s advisors reached an agreement in principle that provides for benefits that will be realized by Entergy New Orleans customers through bill credits that started in July 2018 and offsets to future investments in energy efficiency programs, grid modernization, and Smart City projects, as well as additional benefits related to the filings made at the FERC. The agreement in principle was approved by the City Council in June 2018.

Entergy Texas

After enactment of the Tax Act the PUCT issued an order requiring most utilities, including Entergy Texas, beginning January 25, 2018, to record a regulatory liability for the difference between revenues collected under existing rates and revenues that would have been collected had existing rates been set using the new federal income tax rates and also for the balance of excess accumulated deferred income taxes. Entergy Texas had previously provided information to the PUCT staff and stated that it expected the PUCT to address the lower tax expense as part of Entergy Texas’s rate case expected to be filed in May 2018.

In May 2018, Entergy Texas filed its 2018 base rate case with the PUCT. Entergy Texas’s proposed rates and revenues reflected the inclusion of the federal income tax reductions due to the Tax Act. The PUCT issued an order in December 2018 establishing that 1) $25 million be credited to customers through a rider to reflect the lower federal income tax rate applicable to Entergy Texas from January 2018 through the date new rates were implemented, 2) $242.5 million of protected excess accumulated deferred income taxes be returned to customers through base rates under the average rate assumption method over the lives of the associated assets, and 3) $185.2 million of unprotected excess accumulated deferred income taxes be returned to customers through a rider. The unprotected excess accumulated deferred income taxes rider includes carrying charges and is in effect over a period of 12 months for larger customers and over a period of four years for other customers.

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. The retail regulators of the Utility operating companies that are parties to the Unit

Power Sales Agreement challenged the treatment and amount of excess accumulated deferred income tax liabilities associated with uncertain tax positions related to nuclear decommissioning. In July 2020 the presiding ALJ in the proceeding issued an initial decision finding that there is an additional $147 million in unprotected excess accumulated deferred income taxes related to System Energy’s uncertain decommissioning tax deduction. The initial decision determined that System Energy should have included the $147 million in its March 2018 filing. System Energy had not included credits related to the effect of the Tax Act on the uncertain decommissioning tax position because it was uncertain whether the IRS would allow the deduction. The initial decision rejected both System Energy’s alternative argument that any crediting should occur over a ten-year period and the retail regulators’ argument that any crediting should occur over a two-year period. Instead, the initial decision concluded that System Energy should credit the additional unprotected excess accumulated deferred income taxes in a single lump sum revenue requirement reduction following a FERC order addressing the initial decision.

The ALJ initial decision is an interim step in the FERC litigation process. In September 2020, System Energy filed a brief on exceptions with the FERC, re-urging its positions and requesting the reversal of the ALJ’s initial decision. In December 2020, the LPSC, APSC, MPSC, City Council, and FERC trial staff filed briefs opposing exceptions. The FERC will review the case and issue an order in the proceeding, and the FERC may accept, reject, or modify the ALJ’s initial decision in whole or in part. Credits, if any, that might be required will only become due after the FERC issues its order reviewing the initial decision.

As discussed below in “Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue,” in September 2020 the IRS issued a Notice of Proposed Adjustment (NOPA) and Entergy executed it. In September 2020, System Energy filed a motion to lodge the NOPA into the record in the FERC proceeding. In October 2020 the LPSC, APSC, MPSC, City Council, and FERC trial staff filed oppositions to System Energy’s motion. As a result of the NOPA, System Energy filed, in October 2020, a new Federal Power Act section 205 filing at the FERC to credit the excess accumulated deferred income taxes resulting from the decommissioning uncertain tax position. System Energy proposes to credit the entire amount of the excess accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position by issuing a one-time credit of $17.8 million. In November 2020, the LPSC, APSC, MPSC, and City Council filed a protest to the filing, and System Energy responded.

In November 2020 the IRS issued the Revenue Agent’s Report (RAR) for the 2014-2015 tax years and in December 2020 Entergy executed it. In December 2020, System Energy filed a motion to lodge the RAR into the record in the FERC proceeding addressing the Tax Cuts and Jobs Act. In January 2021 the LPSC, APSC, MPSC, and City Council filed a joint answer opposing System Energy’s motion, and the FERC trial staff also filed an answer opposing System Energy’s motion.

As a result of the RAR, in December 2020, System Energy also filed an amendment to its Federal Power Act section 205 filing to credit excess accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position. The amendment proposed the inclusion of the RAR as support for the filing. In December 2020, the LPSC, APSC, and City Council filed a protest in response to the amendment, reiterating objections to the filing to credit excess accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position. 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.

In November 2020, System Energy filed a motion to vacate the ALJ’s decision, arguing that it had been overtaken by changed circumstances because of the IRS’s determination resulting from the NOPA and RAR. In January 2021 the LPSC, APSC, MPSC, and City Council filed a joint answer opposing System Energy’s motion, and the FERC trial staff also filed an answer opposing System Energy’s motion. There is no formal deadline for FERC to rule on the motion.

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, 2020 and 2019 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.


	2020	2019
	(In Millions)
Entergy Arkansas (a)	$15.2	$14.0
Entergy Louisiana (b)	$170.4	$112.5
Entergy Mississippi	($14.7)	($70.4)
Entergy New Orleans (b)	$6.2	($0.8)
Entergy Texas	($85.4)	($13.0)