Rate And Regulatory Matters

12 Months Ended

Dec. 31, 2018

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, 2018 and 2017:

Other Regulatory Assets

Entergy

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$2,611.5		$2,642.3
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	814.3		746.0
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 – Storm Cost Recovery Filings with Retail Regulators) (Note 5)	452.7		558.9
Removal costs - recovered through depreciation rates (Note 9)	375.8		436.5
Opportunity Sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding)	116.3		109.8
Unamortized loss on reacquired debt - recovered over term of debt	74.5		82.9
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy)	52.1		73.7
Retail rate deferrals - recovered through rate riders as rates are redetermined by retail regulators	39.0		86.4
New nuclear generation development costs (Note 2 - New Nuclear Generation Development Costs) (b)	29.0		36.4
Transition to competition costs - recovered over a 15-year period through February 2021	26.7		37.7
Other	154.6		125.1
Entergy Total		$4,746.5		$4,935.7

Entergy Arkansas

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$747.2		$757.0
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	381.7		345.2
Removal costs - recovered through depreciation rates (Note 9)	138.3		176.9
Opportunity sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding)	116.3		109.8
Storm damage costs - recovered either through securitization or retail rates (Note 5 - Entergy Arkansas Securitization Bonds)	60.7		76.2
Unamortized loss on reacquired debt - recovered over term of debt	21.2		24.3
Retail rate deferrals - recovered through rate riders as rates are redetermined annually	20.5		28.2
ANO Fukushima and Flood Barrier costs - recovered through retail rates through February 2026 (Note 2 - Retail Rate Proceedings) (b)	12.6		14.4
Other	36.5		35.4
Entergy Arkansas Total		$1,535.0		$1,567.4

Entergy Louisiana

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (a)		$711.8		$724.6
Asset Retirement Obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	232.9		218.6
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy)	49.8		71.4
New nuclear generation development costs - recovery through formula rate plan December 2014 through November 2022 (Note 2 - New Nuclear Generation Development Costs) (b)	28.5		35.8
Unamortized loss on reacquired debt - recovered over term of debt	22.5		24.7
Storm damage costs - recovered through retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)	17.9		14.3
Business combination external costs deferral - recovery through formula rate plan December 2015 through November 2025 (b)	12.4		14.1
River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC)	11.0		12.9
Other	18.3		29.4
Entergy Louisiana Total		$1,105.1		$1,145.8

Entergy Mississippi

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$215.9		$218.7
Removal costs - recovered through depreciation rates (Note 9)	63.5		91.6
Attorney General litigation costs (Note 2 - Mississippi Attorney General Complaint) (b)	23.6		9.3
Retail rate deferrals - recovered through rate riders as rates are redetermined annually	16.6		49.4
Unamortized loss on reacquired debt - recovered over term of debt	16.2		17.6
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a)	7.2		7.6
Other	—		3.7
Entergy Mississippi Total		$343.0		$397.9

Entergy New Orleans

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$96.2		$102.8
Storm damage costs, including hurricane costs - recovered through retail rates and securitization (Note 2 - Storm Cost Recovery Filings with Retail Regulators)	70.4		82.3
Removal costs - recovered through depreciation rates (Note 9)	49.3		44.8
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a)	4.5		4.3
Unamortized loss on reacquired debt - recovered over term of debt	2.6		3.0
Rate case costs - recovered over a 6-year period through September 2021 (Note 2 - Retail Rate Proceedings)	1.9		2.6
Retail rate deferrals - recovered through rate riders as rates are redetermined monthly or annually	—		4.4
Other	4.9		7.2
Entergy New Orleans Total		$229.8		$251.4

Entergy Texas

	2018		2017
	(In Millions)
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 5 - Entergy Texas Securitization Bonds)		$303.6		$386.1
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)	171.8		169.2
Removal costs - recovered through depreciation rates (Note 9)	50.9		55.2
Transition to competition costs - recovered over a 15-year period through February 2021	26.7		37.7
Neches and Sabine costs - recovered over a ten-year period through September 2028 (Note 2 - Retail Rate Proceedings) (b)	23.6		—
Unamortized loss on reacquired debt - recovered over term of debt	8.2		8.7
Other	13.2		4.5
Entergy Texas Total		$598.0		$661.4

System Energy

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Other Postretirement Benefits) (a)		$179.3		$202.7
Asset retirement obligation - recovery dependent upon timing of decommissioning (Note 9) (a)	186.9		169.1
Removal costs - recovered through depreciation rates (Note 9)	76.4		67.9
Unamortized loss on reacquired debt - recovered over term of debt	3.8		4.6
System Energy Total		$446.4		$444.3

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

(b) Does not earn a return on investment.

Other Regulatory Liabilities

Entergy

	2018		2017
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)		$815.9		$989.3
Vidalia purchased power agreement (Note 8) (b)	139.7		151.6
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) (b)	111.1		124.8
Income tax rate change - returned to electric and gas customers through retail rates (Note 2 - Retail Rate Proceedings)	74.7		—
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions)	67.9		67.9
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination)	50.8		65.8
Grand Gulf over-recovery - will be refunded through rate riders as rates are redetermined annually	48.6		—
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)	44.4		—
Internal restructuring guaranteed customer credits (Note 2 - Retail Rate Proceedings)	39.6		—
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)	39.1		36.7
Excess decommissioning recovery for Willow Glen - (Note 14 - Dispositions)	31.9		—
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement	25.0		32.1
Removal costs - returned to customers through depreciation rates (Note 9)	18.8		32.4
Other	68.4		43.5
Entergy Total		$1,620.3		$1,588.5

Entergy Arkansas

	2018		2017
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)		$297.2		$354.0
Internal restructuring guaranteed customer credits (Note 2 - Retail Rate Proceedings)	39.6		—
Future formula rate plan revenue reductions (Note 2 - Retail Rate Proceedings)	35.1		—
Grand Gulf over-recovery - will be refunded through rate riders as rates are redetermined annually	26.0		—
Other	4.8		9.6
Entergy Arkansas Total		$402.7		$363.6

Entergy Louisiana

	2018		2017
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)		$274.1		$323.7
Vidalia purchased power agreement (Note 8) (b)	139.7		151.6
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) (b)	111.1		124.8
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination)	50.8		65.8
Income tax rate change - returned to electric customers through retail rates September 2018 through August 2019 (Note 2 - Retail Rate Proceedings)	49.9		—
Asset Retirement Obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)	39.1		36.7
Excess decommissioning recovery for Willow Glen - (Note 14 - Dispositions)	31.9		—
Removal costs - returned to customers through depreciation rates (Note 9)	18.8		32.4
Other	33.4		26.1
Entergy Louisiana Total		$748.8		$761.1

Entergy Mississippi

	2018		2017
	(In Millions)
Grand Gulf Over-Recovery - returned to customers through rate riders when rates are redetermined annually		$22.6		$—
Future formula rate plan revenue reductions (Note 2 - Retail Rate Proceedings)	9.3		—
Other	1.7		0.9
Entergy Mississippi Total		$33.6		$0.9

Entergy Texas

	2018		2017
	(In Millions)
Income tax rate change - refunded through a rate rider (Note 2 - Retail Rate Proceedings)		$23.1		$—
Advanced metering system surcharge (Note 2 - Advanced Metering Infrastructure (AMI) Filings)	16.5		—
Transition to competition costs - returned to customers through rate riders when rates are redetermined periodically	4.2		4.8
Other	4.1		2.1
Entergy Texas Total		$47.9		$6.9

System Energy

	2018		2017
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 17) (a)		$244.6		$311.6
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions)	67.9		67.9
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
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement	25.0		32.1
System Energy Total		$381.9		$456.0

(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 $25.0 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 will be 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 to be 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 existing formula rate plan rider for its customers to realize the remaining benefits of the Tax Act. Entergy Arkansas’s formula rate plan rider includes a netting adjustment that compares 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.

Entergy Louisiana

In a 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 will be 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. Entergy Mississippi’s formula rate plan includes a look-back evaluation report filing in March 2019 that will compare actual 2018 results to the allowed return on rate base. The stipulation approved in June 2018 provides 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 any true-up to be 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. In November 2018, Entergy Mississippi’s annual redetermination of the annual factor to be applied under the power management rider included an insignificant true-up to the amount of unprotected excess accumulated deferred income taxes. In January 2019 the MPSC approved the proposed power management cost factor effective for February 2019 bills.

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. In both a memorandum issued prior to the open meeting when the order was discussed and during the discussions at the open meeting regarding the order, the PUCT indicated that it would consider utility earnings in determining the treatment of the liability and the effects of the Tax Act. 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. Entergy Texas also stated that it would be inappropriate for the PUCT to require a refund of the reduction in income tax expense in 2018 resulting from the Act on a retroactive basis and without a comprehensive review of Entergy Texas’s cost of service and earned return on equity.

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 will 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 will 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 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 larger customers and over a period of four years for other customers.

System Energy

In a filing made with the FERC in March 2018, Entergy proposed revisions to the Unit Power Sales Agreement, among other agreements, to reflect the effects of the Tax Act. In the filing System Energy proposed to return all of its 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 are ongoing.

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, 2018 and 2017 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.

	2018			2017
	(In Millions)
Entergy Arkansas (a)		$86.5			$130.4
Entergy Louisiana (b)		$136.7			$96.7
Entergy Mississippi		$8.0			$32.4
Entergy New Orleans (b)		$2.8			($3.7	)
Entergy Texas		($19.7	)		($67.3	)

(a) Includes $67.3 million in 2018 and $67.1 million in 2017 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

Production Cost Allocation Rider

The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings, which are discussed in the “System Agreement Cost Equalization Proceedings” section below.

In May 2016, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected recovery of the production cost allocation rider true-up adjustment of the 2014 and 2015 unrecovered retail balance in the amount of $1.9 million. Additionally, the redetermined rates reflected the recovery of a $1.9 million System Agreement bandwidth remedy payment resulting from a compliance filing pursuant to the FERC’s December 2015 order related to test year 2009 production costs. The rates for the 2016 production cost allocation rider update were effective July 2016 through June 2017.

In May 2017, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected a credit amount of $0.3 million resulting from a compliance filing pursuant to the FERC’s September 2016 order. Additionally, the redetermined rate reflected recovery of the production cost allocation rider true-up adjustment of the 2016 unrecovered retail balance in the amount of $0.3 million. Because of the small effect of the 2017 production cost allocation rider update, Entergy Arkansas proposed to reduce the effective period of the update to one month, July 2017. After the one month collection period, rates were set to zero for all rate classes for the period August 2017 through June 2018.

In May 2018, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected recovery of the 2017 under-recovered retail balance and a $2.8 million payment by Entergy Arkansas associated with a compliance filing pursuant to a March 2018 FERC order related to 2010 production costs. The rates for the 2018 production cost allocation rider update are effective July 2018 through June 2019.

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.

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 December 2011 the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates.  The audit included a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 2005 through 2009.  In March 2016 the LPSC staff consultant issued its audit report. In its report, the LPSC staff consultant recommended that Entergy Louisiana refund approximately $8.6 million, plus interest, to customers and realign the recovery of approximately $12.7 million from Entergy Gulf States Louisiana’s fuel adjustment clause to base rates. In September 2016 the LPSC staff filed testimony stating that it was no longer recommending a disallowance of $3.4 million of the $8.6 million discussed above, but otherwise maintained the positions from its report. Subsequently, the parties entered into a settlement, which was approved by the LPSC in November 2016. The settlement recognized the dry cask storage recovery method issue, which was addressed in the separate proceeding approved by the LPSC in October 2017, provided for a refund of $5 million, which was made to legacy Entergy Gulf States Louisiana customers in December 2016, and resolved all other issues raised in the audit.

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 is evaluating the staff’s recommended disallowance.

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 consultant issued its audit report. In its report, the LPSC staff consultant recommended 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 is evaluating the staff’s recommended disallowance.

In June 2016 the LPSC staff provided notice of audits of Entergy Louisiana’s fuel adjustment clause filings and purchased gas adjustment clause filings. In recognition of the business combination that occurred in 2015, the audit notice was issued to Entergy Louisiana and will also include a review of charges to legacy Entergy Gulf States Louisiana customers prior to the business combination. The audit includes 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. Discovery commenced in March 2017. No report of audit has been issued.

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.  Discovery commenced in September 2018.  No report of audit has been issued.

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 November 2015, 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 a projected over-recovery balance of $48 million projected through January 31, 2016. In January 2016 the MPSC approved the redetermined annual factor effective February 1, 2016. The MPSC further ordered, however, that due to the significant change in natural gas price forecasts since Entergy Mississippi’s filing in November 2015 Entergy Mississippi should file a revised fuel factor with the MPSC no later than February 1, 2016. Pursuant to that order, Entergy Mississippi submitted a revised fuel factor. Additionally, because Entergy Mississippi’s projected over-recovery balance for the period ending January 31, 2016 was $68 million, in February 2016, Entergy Mississippi filed for another interim adjustment to the energy cost factor effective April 2016 to flow through to customers the projected over-recovery balance over a six-month period. That interim adjustment was approved by the MPSC in February 2016 effective for April 2016 bills.

In November 2016, 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 less than $2 million as of September 30, 2016. In January 2017 the MPSC approved the annual factor effective with February 2017 bills. Also 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 its order, the MPSC expressly reserved the right to review and determine the recoverability of any and all purchased power expenditures made during fiscal year 2016. The MPSC hired independent auditors to conduct an annual operations audit and a financial audit. The independent auditors issued their audit reports in December 2017. The audit reports included several recommendations for action by Entergy Mississippi but did not recommend any cost disallowances. In January 2018 the MPSC certified the audit reports to the Mississippi Legislature. In November 2017 the Public Utilities Staff separately engaged a consultant to review the outage at the Grand Gulf Nuclear Station that began in 2016. The review is currently in progress.

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. Entergy Mississippi proposed a two-tiered energy cost factor designed to promote overall rate stability throughout 2018 particularly during the summer months. 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.

Mississippi Attorney General Complaint

The Mississippi Attorney General filed a complaint in state court in December 2008 against Entergy Corporation, Entergy Mississippi, Entergy Services, and Entergy Power alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution.  The complaint is wide ranging and relates to tariffs and procedures under which Entergy Mississippi purchases power not generated in Mississippi to meet electricity demand.  Entergy believes the complaint is unfounded.  In December 2008 the defendant Entergy companies removed the Attorney General’s lawsuit to U.S. District Court in Jackson, Mississippi. In June 2010 the MPSC authorized the deferral of certain legal expenses associated with this litigation until it is resolved. As of December 31, 2018, Entergy Mississippi has a regulatory asset of $23.6 million for these deferred legal expenses. Pre-trial and settlement conferences were held in October 2018. In October 2018 the District Court rescheduled the trial to April 2019.

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 July 2015 certain parties filed briefs in a PUCT proceeding asserting that Entergy Texas should refund to retail customers an additional $10.9 million in bandwidth remedy payments Entergy Texas received related to calendar year 2006 production costs.  In October 2015 an ALJ issued a proposal for decision recommending that the additional bandwidth remedy payments be refunded to retail customers. In January 2016 the PUCT issued its order affirming the ALJ’s recommendation, and Entergy Texas filed a motion for rehearing of the PUCT’s decision, which the PUCT denied. In March 2016, Entergy Texas filed a complaint in Federal District Court for the Western District of Texas and a petition in the Travis County (State) District Court appealing the PUCT’s decision. The pending appeals did not stay the PUCT’s decision. In April 2016, Entergy Texas filed with the PUCT an application to refund to customers approximately $56.2 million. The refund resulted from (i) $41.8 million of fuel cost recovery over-collections through February 2016, (ii) the $10.9 million in bandwidth remedy payments, discussed above, that Entergy Texas received related to calendar year 2006 production costs, and (iii) $3.5 million in bandwidth remedy payments that Entergy Texas received related to 2006-2008 production costs. In June 2016, Entergy Texas filed an unopposed settlement agreement that added additional over-recovered fuel costs for the months of March and April 2016. The settlement resulted in a $68 million refund. The ALJ approved the refund on an interim basis and it was made to most customers over a four-month period beginning with the first billing cycle of July 2016. In July 2016 the PUCT issued an order approving the interim refund. The federal appeal of the PUCT’s January 2016 decision was heard in December 2016, and the Federal District Court granted Entergy Texas’s requested relief. In January 2017 the PUCT and an intervenor filed petitions for appeal of the Federal District Court ruling to the U.S. Court of Appeals for the Fifth Circuit. Oral argument was held before the Fifth Circuit in February 2018. In April 2018 the Fifth Circuit reversed the decision of the Federal District Court, reinstating the original PUCT decision. In October 2018, Entergy Texas filed notice of nonsuit in its appeal to the Travis County District Court regarding the PUCT’s January 2016 decision.

In July 2016, Entergy Texas filed an application to reconcile its fuel and purchased power costs for the period April 1, 2013 through March 31, 2016. During the reconciliation period, Entergy Texas incurred approximately $1.77 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 over-recovery balance of approximately $19.3 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning April 2016. Entergy Texas also noted, however, that the estimated $19.3 million over collection was being refunded to customers as a portion of the interim fuel refund beginning with the first billing cycle of July 2016, discussed above. Entergy Texas also requested a prudence finding for each of the fuel-related contracts and arrangements entered into or modified during the reconciliation period that have not been reviewed by the PUCT in a prior proceeding. In December 2016, Entergy Texas entered into a stipulation and settlement agreement resulting in a $6 million disallowance not associated with any particular issue raised and a refund of the over-recovery balance of $21 million as of November 30, 2016, to most customers beginning April 2017 through June 2017. This settlement was developed concurrently with the stipulation and settlement agreement in the 2016 transmission cost recovery factor rider amendment discussed below, and the terms and conditions in both settlements are interdependent. The fuel reconciliation settlement was approved by the PUCT in March 2017 and the refunds were made.

In June 2017, Entergy Texas filed an application for a fuel refund of approximately $30.7 million for the months of December 2016 through April 2017. For most customers, the refunds flowed through bills for the months of July 2017 through September 2017. The fuel refund was approved by the PUCT in August 2017.

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.

Retail Rate Proceedings

Filings with the APSC (Entergy Arkansas)

Retail Rates

2015 Base Rate Filing

In April 2015, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. The filing notified the APSC of Entergy Arkansas’s intent to implement a forward test year formula rate plan pursuant to Arkansas legislation passed in 2015, and requested a retail rate increase of $268.4 million, with a net increase in revenue of $167 million. The filing requested a 10.2% return on common equity. In December 2015, Entergy Arkansas, the APSC staff, and certain of the intervenors in the rate case filed with the APSC a joint motion for approval of a settlement of the case that proposed a retail rate increase of approximately $225 million with a net increase in revenue of approximately $133 million; an authorized return on common equity of 9.75%; and a formula rate plan tariff that provides a +/- 50 basis point band around the 9.75% allowed return on common equity. A significant portion of the rate increase is related to Entergy Arkansas’s acquisition in March 2016 of Union Power Station Power Block 2 for a base purchase price of $237 million. The settlement agreement also provided for amortization over a 10-year period of $7.7 million of previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance. In February 2016 the APSC approved the settlement with one exception that reduced the retail rate increase proposed in the settlement by $5 million. The settling parties agreed to the APSC modifications in February 2016. The new rates were effective February 24, 2016 and began billing with the first billing cycle of April 2016. In March 2016, Entergy Arkansas made a compliance filing regarding the new rates that included an interim base rate adjustment surcharge, effective with the first billing cycle of April 2016, to recover the incremental revenue requirement for the period February 24, 2016 through March 31, 2016. The interim base rate adjustment surcharge was designed to recover a total of $21.1 million over the nine-month period from April 2016 through December 2016.

2016 Formula Rate Plan Filing

In July 2016, Entergy Arkansas filed with the APSC its 2016 formula rate plan filing showing Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2017 test period to be below the formula rate plan bandwidth. The filing requested a $67.7 million revenue requirement increase to achieve Entergy Arkansas’s target earned return on common equity of 9.75%. In October 2016, Entergy Arkansas filed with the APSC revised formula rate plan attachments with an updated request for a $54.4 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors, as well as three additional adjustments identified as appropriate by Entergy Arkansas. In November 2016 a hearing was held and the APSC issued an order directing the parties to brief certain issues. In December 2016 the APSC approved a settlement agreement and the $54.4 million revenue requirement increase with approximately $25 million of the $54.4 million revenue requirement subject to possible future adjustment and refund to customers with interest. The APSC requested supplemental information for some of Entergy Arkansas’s requested nuclear expenditures. In December 2016 the APSC approved Entergy Arkansas’s formula rate plan compliance tariff, and the rates became effective with the first billing cycle of January 2017. In April 2017, Entergy Arkansas filed a motion consented to by all parties requesting that it be permitted to submit the supplemental information requested by the APSC in conjunction with its 2017 formula rate plan filing, which was subsequently made in July 2017 and is discussed below. In May 2017 the APSC approved the joint motion and proposal to review Entergy Arkansas’s supplemental information on a concurrent schedule with the 2017 formula rate plan filing. In October 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement resolving all issues in the proceeding and providing for recovery of the 2017 and 2018 nuclear costs. In December 2017 the APSC approved the settlement agreement and recovery of the 2017 and 2018 nuclear costs.

2017 Formula Rate Plan Filing

In July 2017, Entergy Arkansas filed with the APSC its 2017 formula rate plan filing showing Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2018 test period to be below the formula rate plan bandwidth.  The filing projected a $129.7 million revenue requirement increase to achieve Entergy Arkansas’s target earned return on common equity of 9.75%.  Entergy Arkansas’s formula rate plan is subject to a four percent annual revenue constraint and the projected annual revenue requirement increase exceeded the four percent, resulting in a proposed increase for the 2017 formula rate plan of $70.9 million. In October 2017, Entergy Arkansas filed with the APSC revised formula rate plan attachments that projected a $126.2 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors. The revised formula rate plan filing included a proposed $71.1 million revenue requirement increase based on a revision to the four percent constraint calculation. In October 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement resolving all issues in the proceeding and providing for recovery of the 2017 and 2018 nuclear costs. In December 2017 the APSC approved the settlement agreement and the $71.1 million revenue requirement increase, as well as Entergy Arkansas’s formula rate plan compliance tariff, and the rates became effective with the first billing cycle of January 2018.

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 shows 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 includes 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 includes a projected $73.4 millionrevenue 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 exceeds the constraint, the resulting increase is 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, which included additional actual revenues for 2018. 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 certain 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. An additional schedule was issued by the APSC for briefing other contested issues, the outcome of which did not affect the 2018 filing but could affect future Entergy Arkansas formula rate plan filings. That briefing was completed in February 2019, and the APSC has not indicated when a decision on those issues can be expected.

Similar to the 2018 filing, the formula rate plan filing that will be made in 2019 to set the formula rates for the 2020 calendar year will include a netting adjustment that will compare projected costs and sales for 2018 that were approved in the 2017 formula rate plan filing to actual 2018 costs and sales data. In the fourth quarter 2018, Entergy Arkansas recorded a provision of $35.1 million that reflects the estimate of the historical year netting adjustment that will be included in the 2019 filing to reflect the change in formula rate plan revenues associated with actual 2018 results when compared to the allowed rate of return on equity. 

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. Entergy Arkansas also filed a notice with the Missouri Public Service Commission in December 2017 out of an abundance of caution, although Entergy Arkansas does not serve any retail customers in Missouri. In April 2018 the Missouri Public Service Commission approved Entergy Arkansas’s filing. 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

2015 Formula Rate Plan Filing

In May 2016, Entergy Louisiana filed its formula rate plan evaluation report for its 2015 calendar year operations. The evaluation report reflected an earned return on common equity of 9.07%. As such, no adjustment to base formula rate plan revenue was required. The following other adjustments, however, were required under the formula rate plan: an increase in the legacy Entergy Louisiana additional capacity mechanism of $14.2 million; a separate increase in legacy Entergy Louisiana revenue of $10 million primarily to reflect the effects of the termination of the System Agreement; an increase in the legacy Entergy Gulf States Louisiana additional capacity mechanism of $0.5 million; a decrease in legacy Entergy Gulf States Louisiana revenue of $58.7 million primarily to reflect the effects of the termination of the System Agreement; and an increase of $11 million to the MISO cost recovery mechanism. Rates were implemented with the first billing cycle of September 2016, subject to refund. Following implementation of the as-filed rates in September 2016, there were several interim updates to Entergy Louisiana’s formula rate plan, including the one submitted in December 2016, reflecting implementation of the settlement of the Waterford 3 replacement steam generator project prudence review described below. In June 2017 the LPSC staff and Entergy Louisiana filed a joint report of proceedings, which was accepted by the LPSC in June 2017, finalizing the results of the May 2016 evaluation report, interim updates, and corresponding proceedings with no changes to rates already implemented.

2016 Formula Rate Plan Filing

In May 2017, Entergy Louisiana filed its formula rate plan evaluation report for its 2016 calendar year operations. The evaluation report reflected an earned return on common equity of 9.84%. As such, no adjustment to base formula rate plan revenue was required. Adjustments, however, were required under the formula rate plan; the 2016 formula rate plan evaluation report showed a decrease in formula rate plan revenue of approximately $16.9 million, comprised of a decrease in legacy Entergy Louisiana formula rate plan revenue of $3.5 million, a decrease in legacy Entergy Gulf States Louisiana formula rate plan revenue of $9.7 million, and a decrease in incremental formula rate plan revenue of $3.7 million. Additionally, the formula rate plan evaluation report called for a decrease of $40.5 million in the MISO cost recovery revenue requirement from $46.8 million to $6.3 million. Rates reflecting these adjustments were implemented with the first billing cycle of September 2017, subject to refund. In September 2017 the LPSC issued its report indicating that no changes to Entergy Louisiana’s original formula rate plan evaluation report were required but reserved for several issues, including Entergy Louisiana’s September 2017 update to its formula rate plan evaluation report.  In July 2018, Entergy Louisiana and the LPSC staff filed an unopposed joint report setting forth a correction to the annualization calculation, the effect of which was a net $3.5 million revenue requirement reduction and indicating that there are no outstanding issues with the 2016 formula rate plan report, the supplemental report, or the interim updates.  In September 2018 the LPSC approved the unopposed joint report.

Formula Rate Plan Extension Through 2019 Test Year

In August 2017, Entergy Louisiana filed a request with the LPSC seeking to extend its formula rate plan for three years (2017-2019) with limited modifications of its terms.  Those modifications include: a one-time resetting of base rates to the midpoint of the band at Entergy Louisiana’s authorized return on equity of 9.95% for the 2017 test year; narrowing of the formula rate plan bandwidth from a total of 160 basis points to 80 basis points; and a forward-looking mechanism that would allow Entergy Louisiana to recover certain transmission-related costs contemporaneously with when those projects begin delivering benefits to customers.  In April 2018 the LPSC approved an unopposed joint motion filed by Entergy Louisiana and the LPSC staff that settled the matter. The settlement extended the formula rate plan for three years, providing for rates through at least August 2021. In addition to retaining the major features of the traditional formula rate plan, substantive features of the extended formula rate plan include:

• a mid-point reset of formula rate plan revenues to a 9.95% earned return on common equity for the 2017 test year and for the St. Charles Power Station when it enters commercial operation;

• a 9.8% target earned return on common equity for the 2018 and 2019 test years;

• narrowing of the common equity bandwidth to plus or minus 60 basis points around the target earned return on common equity;

• a cap on potential revenue increase of $35 million for the 2018 evaluation period, and $70 million for the cumulative 2018 and 2019 evaluation periods, on formula rate plan cost of service rate increases (the cap excludes rate changes associated with the transmission recovery mechanism described below and rate changes associated with additional capacity);

• a framework for the flow back of certain tax benefits created by the Tax Act to customers, as described in “Regulatory activity regarding the Tax Cuts and Jobs Act” above; and

• a transmission recovery mechanism providing for the opportunity to recover certain transmission-related expenditures in excess of $100 million annually for projects placed in service up to one month prior to rate change outside of sharing that is designed to operate in a fashion similar to the additional capacity mechanism.

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.

Waterford 3 Replacement Steam Generator Project

Following the completion of the Waterford 3 replacement steam generator project, the LPSC undertook a prudence review in connection with a filing made by Entergy Louisiana in April 2013 with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs. In July 2014 the LPSC staff filed testimony recommending potential project and replacement power cost disallowances of up to $71 million, citing a need for further explanation or documentation from Entergy Louisiana.  An intervenor filed testimony recommending disallowance of $141 million of incremental project costs, claiming the steam generator fabricator was imprudent.  Entergy Louisiana provided further documentation and explanation requested by the LPSC staff. An evidentiary hearing was held in December 2014. Entergy Louisiana believed that the replacement steam generator costs were prudently incurred and applicable legal principles supported their recovery in rates.  Nevertheless, Entergy Louisiana recorded a write-off of $16 million of Waterford 3’s plant balance in December 2014 because of the uncertainty at the time associated with the resolution of the prudence review. In December 2015 the ALJ issued a proposed recommendation, which was subsequently finalized, concluding that Entergy Louisiana prudently managed the Waterford 3 replacement steam generator project, including the selection, use, and oversight of contractors, and could not reasonably have anticipated the damage to the steam generators. Nevertheless, the ALJ concluded that Entergy Louisiana was liable for the conduct of its contractor and subcontractor and, therefore, recommended a disallowance of $67 million in capital costs. Additionally, the ALJ concluded that Entergy Louisiana did not sufficiently justify the incurrence of $2 million in replacement power costs during the replacement outage. Although the ALJ’s recommendation had not yet been considered by the LPSC, after considering the progress of the proceeding in light of the ALJ recommendation, Entergy Louisiana recorded in the fourth quarter 2015 approximately $77 million in charges, including a $45 million asset write-off and a $32 million regulatory charge, to reflect that a portion of the assets associated with the Waterford 3 replacement steam generator project was no longer probable of recovery. Entergy Louisiana maintained that the ALJ’s recommendation contained significant factual and legal errors.

In October 2016 the parties reached a settlement in this matter. The settlement was approved by the LPSC in December 2016. The settlement effectively provided for an agreed-upon disallowance of $67 million of plant, which had been previously written off by Entergy Louisiana, as discussed above. The refund to customers of approximately $71 million as a result of the settlement approved by the LPSC was made to customers in January 2017. Of the $71 million of refunds, $68 million was credited to customers through Entergy Louisiana’s formula rate plan, outside of sharing, and $3 million through its fuel adjustment clause. Entergy Louisiana had previously recorded a provision of $48 million for this refund. The previously-recorded provision included the cumulative revenues recorded through December 2016 related to the $67 million of disallowed plant. An additional regulatory charge of $23 million was recorded in fourth quarter 2016 to reflect the effects of the settlement. The settlement also provided that Entergy Louisiana could retain the value associated with potential service credits agreed to by the project contractor, to the extent they are realized in the future. Following a review by the parties, an unopposed joint report of proceedings was filed by the LPSC staff and Entergy Louisiana in May 2017 and the LPSC accepted the joint report of proceedings resolving the matter.

Union Power Station and Deactivation or Retirement Decisions for Entergy Louisiana Plants

In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC for approval of the acquisition and cost recovery of two power blocks of the Union Power Station for an expected base purchase price of approximately $237 million per power block, subject to adjustments. In September 2015, Entergy Gulf States Louisiana agreed to settlement terms with all parties for Entergy Gulf States Louisiana’s purchase of the two power blocks. In October 2015 the LPSC voted unanimously to approve the uncontested settlement which finds, among other things, that acquisition of Power Blocks 3 and 4 is in the public interest and, therefore, prudent. The business combination of Entergy Gulf States Louisiana and Entergy Louisiana received regulatory approval and closed in October 2015 making Entergy Louisiana the named purchaser of Power Blocks 3 and 4 of the Union Power Station. In March 2016, Entergy Louisiana acquired Power Blocks 3 and 4 of Union Power Station for an aggregate purchase price of approximately $475 million and implemented rates to collect the estimated first-year revenue requirement with the first billing cycle of March 2016.

As a term of the LPSC-approved settlement authorizing the purchase of Power Blocks 3 and 4 of the Union Power Station, Entergy Louisiana agreed to make a filing with the LPSC to review its decisions to deactivate Ninemile 3 and Willow Glen 2 and 4 and its decision to retire Little Gypsy 1.  In January 2016, Entergy Louisiana made its compliance filing with the LPSC. Entergy Louisiana, LPSC staff, and intervenors participated in a technical conference in March 2016 where Entergy Louisiana presented information on its deactivation/retirement decisions for these four units in addition to information on the current deactivation decisions for the ten-year planning horizon. Parties requested further proceedings on the prudence of the decision to deactivate Willow Glen 2 and 4.  No party contested the prudence of the decision to deactivate Willow Glen 2 and 4 or suggested reactivation of these units; however, issues were raised related to Entergy Louisiana’s decision to give up its transmission service rights in MISO for Willow Glen 2 and 4 rather than placing the units into suspended status for the three-year term permitted by MISO. In March 2018 the LPSC adopted the ALJ’s recommended order finding that Entergy Louisiana did not demonstrate that its decision to permanently surrender transmission rights for the mothballed (not retired) Willow Glen 2 and 4 units was reasonable and that Entergy Louisiana should hold customers harmless from increased transmission expenses should those units be reactivated. Because no party or the LPSC suggested that Willow Glen 2 and 4 should be reactivated and because the cost to return those units to service far exceeded the revenue the units were expected to generate in MISO, Entergy Louisiana retired Willow Glen 2 and 4 in March 2018. Entergy Louisiana submitted a compliance filing regarding retirement of Willow Glen 2 and 4, and the LPSC closed the proceeding.

Retail Rates - Gas

2016 Rate Stabilization Plan Filing

In January 2017, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2016. The filing of the evaluation report for test year 2016 reflected an earned return on common equity of 6.37%. In April 2017 the LPSC approved a joint report of proceedings and Entergy Louisiana submitted a revised evaluation report reflecting a $1.2 million annual increase in revenue with rates implemented with the first billing cycle of May 2017.

2017 Rate Stabilization Plan Filing

In January 2018, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2017.  The filing of the evaluation report for the test year 2017 reflected an earned return on common equity of 9.06%.  This earned return is below the earnings sharing band of the rate stabilization plan and results in a rate increase of $0.1 million.  Due to the enactment in late-December 2017 of the Tax Cuts and Jobs Act, Entergy Louisiana did not have adequate time to reflect the effects of this tax legislation in the rate stabilization plan.  In April 2018, Entergy Louisiana filed a supplemental evaluation report for the test year ended September 2017, reflecting the effects of the Tax Act, including a proposal to use the unprotected excess accumulated deferred income taxes to offset approximately $1.4 million of storm restoration deferred operation and maintenance costs incurred by Entergy Louisiana in connection with the August 2016 flooding disaster in its gas service area. The supplemental filing reflects an earned return on common equity of 10.79%. As-filed rates from the supplemental filing were implemented, subject to refund, with customers receiving a cost reduction of approximately $0.7 million effective with bills rendered on and after the first billing cycle of May 2018, as well as a $0.2 million reduction in the gas infrastructure rider effective with bills rendered on and after the first billing cycle of July 2018. The proceeding is currently in its discovery phase. A procedural schedule has not been established.

2018 Rate Stabilization Plan Filing

In January 2019, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2018. The filing of the evaluation report for the test year 2018 reflected an earned return on common equity of 2.69%. This earned return is below the earning sharing band of the gas rate stabilization plan and results in a rate increase of $2.8 million. Entergy Louisiana will make a compliance filing in April 2019 and rates will be implemented during the first billing cycle of May 2019.

Filings with the MPSC (Entergy Mississippi)

Formula Rate Plan Filings

In March 2016, Entergy Mississippi submitted its formula rate plan 2016 test year filing showing Entergy Mississippi’s projected earned return for the 2016 calendar year to be below the formula rate plan bandwidth. The filing showed a $32.6 million rate increase was necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 9.96%, within the formula rate plan bandwidth. In June 2016 the MPSC approved Entergy Mississippi’s joint stipulation with the Mississippi Public Utilities Staff. The joint stipulation provided for a total revenue increase of $23.7 million. The revenue increase included a $19.4 million increase through the formula rate plan, resulting in a return on common equity point of adjustment of 10.07%. The revenue increase also included $4.3 million in incremental ad valorem tax expenses to be collected through an updated ad valorem tax adjustment rider. The revenue increase and ad valorem tax adjustment rider were effective with the July 2016 bills.

In March 2017, Entergy Mississippi submitted its formula rate plan 2017 test year filing and 2016 look-back filing showing Entergy Mississippi’s earned return for the historical 2016 calendar year and projected earned return for the 2017 calendar year to be within the formula rate plan bandwidth, resulting in no change in rates. In June 2017, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a stipulation that confirmed that Entergy Mississippi’s earned returns for both the 2016 look-back filing and 2017 test year were within the respective formula rate plan bandwidths. In June 2017 the MPSC approved the stipulation, which resulted in no change in rates.

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.

Entergy Mississippi’s formula rate plan includes a look-back evaluation report filing in March 2019 that will compare actual 2018 results to the performance-adjusted allowed return on rate base.  In fourth quarter 2018, Entergy Mississippi recorded a provision of $9.3 million that reflects the estimate of the difference between the 2018 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 October 2018, Entergy Mississippi proposed revisions to its formula rate plan that would provide for a mechanism, the interim capacity rate adjustment mechanism, in the formula rate plan 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 additions, such as the Sunflower Solar Facility, that are approved by the MPSC.

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

As a provision of the settlement agreement approved by the City Council in May 2015 providing for the transfer from Entergy Louisiana to Entergy New Orleans of certain assets that supported the provision of service to Entergy Louisiana’s customers in Algiers, it was agreed that, with limited exceptions, no action may be taken with respect to Entergy New Orleans’s base rates until rates are implemented from a base rate case that must be filed for its electric and gas operations in 2018. This provision eliminated the formula rate plan applicable to Algiers operations. The limited exceptions included continued implementation of the then-remaining two years of the four-year phased-in rate increase for the Algiers area and certain exceptional cost increases or decreases in the base revenue requirement. An additional provision of the settlement agreement allowed for continued recovery of the revenue requirement associated with the capacity and energy from Ninemile 6 received by Entergy New Orleans under a power purchase agreement with Entergy Louisiana (Algiers PPA). The settlement authorized Entergy New Orleans to recover the remaining revenue requirement related to the Algiers PPA through base rates charged to Algiers customers. The settlement also provided for continued implementation of the Algiers MISO recovery rider.

In addition to the Algiers PPA, Entergy New Orleans has a separate power purchase agreement with Entergy Louisiana for 20% of the capacity and energy from Ninemile 6 (Ninemile PPA), which commenced operation in December 2014. Initially, recovery of the non-fuel costs associated with the Ninemile PPA was authorized through a special Ninemile 6 rider billed only to Entergy New Orleans customers outside of Algiers.

In August 2015, Entergy New Orleans filed an application with the City Council seeking authorization to proceed with the purchase of Union Power Block 1, with an expected base purchase price of approximately $237 million, subject to adjustments, and seeking approval of the recovery of the associated costs. In November 2015 the City Council issued written resolutions and an order approving an agreement in principle between Entergy New Orleans and City Council advisors providing that the purchase of Union Power Block 1 and related assets by Entergy New Orleans is prudent and in the public interest. The City Council authorized expansion of the terms of the purchased power and capacity acquisition cost recovery rider to recover the non-fuel purchased power expense from Ninemile 6, the revenue requirement associated with the purchase of Power Block 1 of the Union Power Station, and a credit to customers of $400 thousand monthly beginning June 2016 in recognition of the decrease in other operation and maintenance expenses that would result with the deactivation of Michoud Units 2 and 3. In March 2016, Entergy New Orleans purchased Power Block 1 of the Union Power Station for approximately $237 million and initiated recovery of these costs with March 2016 bills. In July 2016, Entergy New Orleans and the City Council Utility Committee agreed to a temporary increase in the Michoud credit to customers to a total of $1.4 million monthly for August 2016 through December 2016.

A 2008 rate case settlement included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs.  The rate settlement provided an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provided a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs. In January 2015 the City Council approved funding for the Energy Smart program from April 2015 through March 2017 using the remainder of the approximately $12.8 million of 2014 rough production cost equalization funds, with any remaining costs being recovered through the fuel adjustment clause. This funding methodology was modified in November 2015 when the City Council directed Entergy New Orleans to use a combination of guaranteed customer savings related to a prior agreement with the City Council and rough production cost equalization funds to cover program costs prior to recovering any costs through the fuel adjustment clause. In April 2017 the City Council approved an implementation plan for the Energy Smart program from April 2017 through December 2019. The City Council directed that the $11.8 million balance reported for Energy Smart funds be used to continue funding the program for Entergy New Orleans’s legacy customers and that the Energy Smart Algiers program continue to be funded through the Algiers fuel adjustment clause, until additional customer funding is required for the legacy customers. In September 2017, Entergy New Orleans filed a supplemental plan and proposed several options for an interim cost recovery mechanism necessary to recover program costs during the period between when existing funds directed to Energy Smart programs are depleted and when new rates from the 2018 combined rate case, which includes a cost recovery mechanism for Energy Smart funding, take effect (estimated to be August 2019). In December 2017 the City Council approved an energy efficiency cost recovery rider as an interim funding mechanism for Energy Smart, subject to verification that no additional funding sources exist. In June 2018 the City Council also approved a resolution recommending that Entergy New Orleans allocate approximately $13.5 million of benefits resulting from the Tax Act to Energy Smart. Entergy New Orleans is seeking approval of a permanent and stable source of funding for Energy Smart as part of its base rate case filed in September 2018.

In September 2018, Entergy New Orleans filed an electric and gas base rate case with the City Council. The filing requests 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 requests 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 includes a proposed gas rate decrease of $142 thousand. Entergy New Orleans’s rates reflect 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 ending 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’s request for a change in rates is based on the projected twelve months ending December 31, 2018.

The filing’s major provisions include: (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 have recommended, among other things, overall rate reductions of approximately $33 million in electric rates and $3.8 million in gas rates. Certain intervenors have recommended overall rate reductions of up to approximately $49 million in electric rates and $5 million in gas rates. The procedural schedule calls for an evidentiary hearing to be held in June 2019.

Internal Restructuring

In July 2016, Entergy New Orleans filed an application with the City Council seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy New Orleans, Inc. to a new entity, which would ultimately be owned by an existing Entergy subsidiary holding company. In May 2017 the City Council adopted a resolution approving the proposed internal restructuring pursuant to an agreement in principle with the City Council advisors and certain intervenors. Pursuant to the agreement in principle, Entergy New Orleans would credit retail customers $10 million in 2017, $1.4 million in the first quarter of the year after the transaction closes, and $117,500 each month in the second year after the transaction closes until such time as new base rates go into effect as a result of the then-anticipated 2018 base rate case (which has subsequently been filed). Entergy New Orleans began crediting retail customers in June 2017. In June 2017 the FERC approved the transaction and, pursuant to the agreement in principle, Entergy New Orleans will provide additional credits to retail customers of $5 million in each of the years 2018, 2019, and 2020.

In November 2017, Entergy New Orleans undertook a multi-step restructuring, including the following:

• Entergy New Orleans, Inc. redeemed its outstanding preferred stock at a price of approximately $21 million, which included a call premium of approximately $819,000, plus any accumulated and unpaid dividends.

• Entergy New Orleans, Inc. converted from a Louisiana corporation to a Texas corporation.

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

• Entergy New Orleans, Inc. contributed the membership interests in Entergy New Orleans 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 New Orleans Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.

In December 2017, Entergy New Orleans, Inc. changed its name to Entergy Utility Group, Inc., and Entergy New Orleans Power then changed its name to Entergy New Orleans, LLC. Entergy New Orleans, LLC holds substantially all of the assets, and has assumed substantially all of the liabilities, of Entergy New Orleans, Inc. The restructuring was accounted for as a transaction between entities under common control.

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 electricity 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), 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 June 2017, Entergy Texas filed an application to amend its DCRF rider by increasing the total collection from $8.65 million to approximately $19 million. In July 2017, Entergy Texas, the PUCT staff, and the two other parties in the proceeding entered into an unopposed stipulation and settlement agreement resulting in an amended DCRF annual revenue requirement of $18.3 million. In September 2017 the PUCT issued its final order approving the unopposed stipulation and settlement agreement. The amended DCRF rider rates became effective for usage on and after September 1, 2017. DCRF rates were set to zero upon implementation of new base rates on October 17, 2018, as described above in the discussion of the 2018 base rate case.

Transmission Cost Recovery Factor (TCRF) Rider

In September 2015, Entergy Texas filed for a TCRF rider requesting a $13 million increase, incremental to base rates. Testimony was filed in November 2015, with the PUCT staff and other parties proposing various disallowances involving, among other things, MISO charges, vegetation management costs, and bad debt expenses that would reduce the requested increase by approximately $2 million. In addition to those recommended disallowances, a number of parties recommended that Entergy Texas’s request be reduced by an additional $3.4 million to account for load growth since base rates were last set. In February 2016 a State Office of Administrative Hearings ALJ issued a proposal for decision recommending that the PUCT disallow approximately $2 million from Entergy Texas’s $13 million request, but recommending that the PUCT not accept the load growth offset. In June 2016 the PUCT indicated that it would take up in a future rulemaking project the issue of whether a load growth adjustment should apply to a TCRF. In July 2016 the PUCT issued an order generally accepting the proposal for decision but declining to adjust the TCRF baseline in two instances as recommended by the ALJ, which resulted in a total annual allowance of approximately $10.5 million. The PUCT also ordered its staff and Entergy Texas to track all spare autotransformer transfers going forward so that it could address the appropriate accounting treatment and prudence of such transfers in Entergy Texas’s next base rate case. Entergy Texas implemented the TCRF rider beginning with September 2016 bills.

In September 2016, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The proposed amended TCRF rider was designed to collect approximately $29.5 million annually from Entergy Texas’s retail customers. This amount included the approximately $10.5 million annually that Entergy Texas was previously authorized to collect through the TCRF rider, as discussed above. In December 2016, concurrent with the 2016 fuel reconciliation stipulation and settlement agreement discussed above, Entergy Texas and the PUCT staff reached a settlement agreeing to the amended TCRF annual revenue requirement of $29.5 million. As discussed above, the terms of the two settlements are interdependent. The PUCT approved the settlement and issued a final order in March 2017. Entergy Texas implemented the amended TCRF rider beginning with bills covering usage on and after March 20, 2017. TCRF rates were set to zero upon implementation of new base rates on October 17, 2018, as described above in the 2018 base rate case discussion.

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. The proceeding is currently ongoing at the PUCT.

Advanced Metering Infrastructure (AMI) Filings

Entergy Arkansas

In September 2016, Entergy Arkansas filed an application seeking a finding from the APSC that Entergy Arkansas’s deployment of AMI is in the public interest. Entergy Arkansas proposed to replace existing meters with advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Arkansas’s modernized power grid. The filing included an estimate of implementation costs for AMI of $208 million. The filing identified a number of quantified and unquantified benefits, and Entergy Arkansas provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal net benefit to customers of $406 million. Entergy Arkansas also sought to continue to include in rate base the remaining book value of existing meters, which was approximately $57 million at December 31, 2015, that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Arkansas proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Deployment of the communications network began in 2018. Entergy Arkansas proposed to include the AMI deployment costs and the quantified benefits in future formula rate plan filings, and the 2018 costs were approved in the 2017 formula rate plan filing. In August 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement. In October 2017 the APSC issued an order finding that Entergy Arkansas’s AMI deployment is in the public interest and approving the settlement agreement subject to a minor modification. Entergy Arkansas expects to recover the undepreciated balance of its existing meters through a regulatory asset to be amortized over 15 years.

Entergy Louisiana

In November 2016, Entergy Louisiana filed an application seeking a finding from the LPSC that Entergy Louisiana’s deployment of advanced electric and gas metering infrastructure is in the public interest. Entergy Louisiana proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Louisiana’s modernized power grid. The filing included an estimate of implementation costs for AMI of $330 million. The filing identified a number of quantified and unquantified benefits, and Entergy Louisiana provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $607 million. Entergy Louisiana also sought to continue to include in rate base the remaining book value, approximately $92 million at December 31, 2015, of the existing electric meters and also to depreciate those assets using current depreciation rates. Entergy Louisiana proposed a 15-year useful life for the new advanced meters, the three-year deployment of which began in 2019. Deployment of the communications network began in 2018. Entergy Louisiana proposed to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022. The parties reached an uncontested stipulation permitting implementation of Entergy Louisiana’s proposed AMI system, with modifications to the proposed customer charge. In July 2017 the LPSC approved the stipulation. Entergy Louisiana expects to recover the undepreciated balance of its existing meters through a regulatory asset to be amortized at current depreciation rates.

Entergy Mississippi

In November 2016, Entergy Mississippi filed an application seeking an order from the MPSC granting a certificate of public convenience and necessity and finding that Entergy Mississippi’s deployment of AMI is in the public interest. Entergy Mississippi proposed to replace existing meters with advanced meters that enable two-way data communication; to design and build a secure and reliable network to support such communications; and to implement support systems. AMI is intended to serve as the foundation of Entergy Mississippi’s modernized power grid. The filing included an estimate of implementation costs for AMI of $132 million. The filing identified a number of quantified and unquantified benefits, and Entergy Mississippi provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal benefit to customers of $496 million over a 15-year period, which when netted against the costs of AMI results in $183 million of net customer benefits. Entergy Mississippi also sought to continue to include in rate base the remaining book value, approximately $56 million at December 31, 2015, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Mississippi proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019, subject to approval by the MPSC. Deployment of the communications network began in 2018. Entergy Mississippi proposed to include the AMI deployment costs and the quantified benefits in existing rate mechanisms, primarily through future formula rate plan filings and/or future energy cost recovery rider schedule re-determinations, as applicable. In May 2017 the Mississippi Public Utilities Staff and Entergy Mississippi entered into and filed a joint stipulation supporting Entergy Mississippi’s filing, and the MPSC issued an order approving the filing without material changes, finding that Entergy Mississippi’s deployment of AMI is in the public interest and granting a certificate of public convenience and necessity. The MPSC order also confirmed that Entergy Mississippi shall continue to include in rate base the remaining book value of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. In June 2018, as part of the order approving the joint stipulation between the Mississippi Public Utilities Staff and Entergy Mississippi addressing Entergy Mississippi’s 2018 formula rate plan evaluation report and the ratemaking effects of the Tax Act, the MPSC approved the acceleration of the recovery of substantially all of Entergy Mississippi’s existing customer meters in anticipation of AMI deployment.

Entergy New Orleans

In October 2016, Entergy New Orleans filed an application seeking a finding from the City Council that Entergy New Orleans’s deployment of advanced electric and gas metering infrastructure is in the public interest.  Entergy New Orleans proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems.  AMI is intended to serve as the foundation of Entergy New Orleans’s modernized power grid.  The filing included an estimate of implementation costs for AMI of $75 million. The filing identified a number of quantified and unquantified benefits, and Entergy New Orleans provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $101 million.  Entergy New Orleans also sought to continue to include in rate base the remaining book value, approximately $21 million at December 31, 2015, of the existing electric meters and also to depreciate those assets using current depreciation rates.  Entergy New Orleans proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which began in 2019.  Deployment of the information technology infrastructure began in 2017 and deployment of the communications network began in 2018.  Entergy New Orleans proposed to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022.  The City Council’s advisors filed testimony in May 2017 recommending the adoption of AMI subject to certain modifications, including the denial of Entergy New Orleans’s proposed customer charge as a cost recovery mechanism. In January 2018 a settlement was reached between the City Council’s advisors and Entergy New Orleans. In February 2018 the City Council approved the settlement, which deferred cost recovery to the 2018 Entergy New Orleans rate case, but also stated that an adjustment for 2018-2019 AMI costs can be filed in the rate case and that, for all subsequent AMI costs, the mechanism to be approved in the 2018 rate case will allow for the timely recovery of such costs. In April 2018 the City Council adopted a resolution directing Entergy New Orleans to explore the options for accelerating the deployment of AMI. In June 2018 the City Council approved a one-year acceleration of AMI in its service area for an incremental $4.4 million.

Entergy Texas

In April 2017 the Texas legislature enacted legislation that extends statutory support for AMI deployment to Entergy Texas and directs that if Entergy Texas elects to deploy AMI, it shall do so as rapidly as practicable. In July 2017, Entergy Texas filed an application seeking an order from the PUCT approving Entergy Texas’s deployment of AMI. Entergy Texas proposed to replace existing meters with advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Texas’s modernized power grid. The filing included an estimate of implementation costs for AMI of $132 million. The filing identified a number of quantified and unquantified benefits, with Entergy Texas showing that its AMI deployment is expected to produce nominal net operational cost savings to customers of $33 million. Entergy Texas also sought to continue to include in rate base the remaining book value, approximately $41 million at December 31, 2016, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Texas proposed a seven-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Entergy Texas also proposed a surcharge tariff to recover the reasonable and necessary costs it has and will incur under the deployment plan for the full deployment of advanced meters. Further, Entergy Texas sought approval of fees that would be charged to customers who choose to opt out of receiving service through an advanced meter and instead receive electric service with a non-standard meter. In October 2017, Entergy Texas and other parties entered into and filed an unopposed stipulation and settlement agreement, permitting deployment of AMI with limited modifications. The PUCT approved the stipulation and settlement agreement in December 2017. Entergy Texas implemented the AMI surcharge tariff beginning with January 2018 bills. As of December 31, 2018, Entergy Texas has a regulatory liability related to the collection of the surcharge from customers. Consistent with the approval, deployment of the communications network began in 2018 and deployment of the advanced meters will begin in March 2019. Entergy Texas expects to recover the remaining net book value of its existing meters through a regulatory asset to be amortized at current depreciation rates.

System Agreement Cost Equalization Proceedings

Prior to its final termination in 2016, the Utility operating companies historically engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement.  Entergy Arkansas terminated its participation in the System Agreement in December 2013. Entergy Mississippi terminated its participation in the System Agreement in November 2015. The System Agreement terminated with respect to its remaining participants in August 2016.

Although the System Agreement has terminated, certain of the Utility operating companies’ retail regulators continue to pursue litigation involving the System Agreement at the FERC and in federal courts.  The proceedings include challenges to the allocation of costs as defined by the System Agreement and other matters.

In June 2005 the FERC issued a decision in System Agreement litigation that had been commenced by the LPSC, and essentially affirmed its decision in a December 2005 order on rehearing.  The decision included, among other things:

• The FERC’s conclusion that the System Agreement no longer roughly equalized total production costs among the Utility operating companies.

• In order to reach rough production cost equalization, the FERC imposed a bandwidth remedy by which each company’s total annual production costs would have to be within +/- 11% of Entergy System average total annual production costs.

• In calculating the production costs for this purpose under the FERC’s order, output from the Vidalia hydroelectric power plant would not reflect the actual Vidalia price for the year but be priced at that year’s average price paid by Entergy Louisiana for the exchange of electric energy under Service Schedule MSS-3 of the System Agreement, thereby reducing the amount of Vidalia costs reflected in the comparison of the Utility operating companies’ total production costs.

• The remedy ordered by the FERC in 2005 required no refunds and became effective based on calendar year 2006 production costs with the first reallocation payments made in 2007.

The FERC’s decision reallocated total production costs of the Utility operating companies whose relative total production costs expressed as a percentage of Entergy System average production costs are outside an upper or lower bandwidth.  This was accomplished by payments from Utility operating companies whose production costs were more than 11% below Entergy System average production costs to Utility operating companies whose production costs were more than the Entergy System average production cost, with payments going first to those Utility operating companies whose total production costs were farthest above the Entergy System average.

The LPSC, APSC, MPSC, and the Arkansas Electric Energy Consumers appealed the FERC’s December 2005 decision to the United States Court of Appeals for the D.C. Circuit.  Entergy and the City of New Orleans intervened in the various appeals.  The D.C. Circuit issued its decision in April 2008.  The D.C. Circuit concluded that the FERC’s orders had failed to adequately explain both its conclusion that it was prohibited from ordering refunds for the 20-month period from September 13, 2001 - May 2, 2003 and its determination to implement the bandwidth remedy commencing on January 1, 2006, rather than June 1, 2005.  The D.C. Circuit remanded the case to the FERC for further proceedings on those two issues.

In October 2011 the FERC issued an order addressing the D.C. Circuit remand on the two issues.  On the first issue, the FERC concluded that it did have the authority to order refunds, but decided that it would exercise its equitable discretion and not require refunds for the 20-month period from September 13, 2001 - May 2, 2003.  Because the ruling on refunds relied on findings in the interruptible load proceeding, which is discussed in a separate section below, the FERC concluded that this refund ruling will be held in abeyance pending the outcome of the rehearing requests in the interruptible load proceeding.  On the second issue, the FERC reversed its prior decision and ordered that the prospective bandwidth remedy begin on June 1, 2005 (the date of its initial order in the proceeding) rather than January 1, 2006, as it had previously ordered.  Pursuant to the October 2011 order, Entergy was required to calculate bandwidth payments for the period June - December 2005 utilizing the bandwidth formula tariff prescribed by the FERC that was filed in a December 2006 compliance filing and accepted by the FERC in an April 2007 order.  

In March 2015, in light of a December 2014 decision by the D.C. Circuit in the interruptible load proceeding, Entergy filed with the FERC a motion to establish a briefing schedule on refund issues and an initial brief addressing refund issues. The initial brief argued that the FERC, in response to the D.C. Circuit decision, should clarify its policy on refunds and find that refunds are not required in this proceeding. In October 2015 the FERC issued three orders related to the commencement of the remedy on June 1, 2005 and the inclusion of interest for the period June 1, 2005 through December 31, 2005. Specifically, the FERC rejected Entergy’s request for rehearing of its decision to include interest for the seven-month period. The FERC also rejected Entergy’s request for rehearing of the order rejecting the compliance filing with regard to the issue of interest. Finally, the FERC set for hearing and settlement procedures the 2014 compliance filing that included the bandwidth calculation for the seven months June 1, 2005 through December 31, 2005. In setting the compliance filing for hearing, the FERC rejected the APSC’s protest that Entergy Arkansas should not be subject to the filing because Entergy Arkansas would be making the payments during a period following its exit from the System Agreement. In January 2018 the D.C. Circuit affirmed the FERC decision that Entergy Arkansas was subject to the filing.

In December 2011, Entergy filed with the FERC its compliance filing that provided the payments and receipts among the Utility operating companies pursuant to the FERC’s October 2011 order.  The APSC, the LPSC, the PUCT, and other parties intervened in the December 2011 compliance filing proceeding, and the APSC and the LPSC also filed protests. The filing showed the following payments/receipts among the Utility operating companies:

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$156
Entergy Louisiana	($75)
Entergy Mississippi	($33)
Entergy New Orleans	($5)
Entergy Texas	($43)

Entergy Arkansas made its payment in January 2012.  In February 2012, Entergy Arkansas filed for an interim adjustment to its production cost allocation rider requesting that the $156 million be collected from customers over the 22-month period from March 2012 through December 2013.  In March 2012 the APSC issued an order stating that the payment can be recovered from retail customers through the production cost allocation rider, subject to refund.  The LPSC and the APSC requested rehearing of the FERC’s October 2011 order.  

In February 2014 the FERC issued a rehearing order addressing its October 2011 order. The FERC denied the LPSC’s request for rehearing on the issues of whether the bandwidth remedy should be made effective earlier than June 1, 2005, and whether refunds should be ordered for the 20-month refund effective period. The FERC granted the LPSC’s rehearing request on the issue of interest on the bandwidth payments/receipts for the June - December 2005 period, requiring that interest be accrued from June 1, 2006 until the date those bandwidth payments/receipts are made. Also in February 2014 the FERC issued an order rejecting the December 2011 compliance filing that calculated the bandwidth payments/receipts for the June - December 2005 period. The FERC order required a new compliance filing that calculates the bandwidth payments/receipts for the June - December 2005 period based on monthly data for the seven individual months including interest pursuant to the February 2014 rehearing order. Entergy sought rehearing of the February 2014 order with respect to the FERC’s determinations regarding interest. In April 2014 the LPSC filed a petition for review of the FERC’s October 2011 and February 2014 orders with the U.S. Court of Appeals for the D.C. Circuit. In August 2017 the D.C. Circuit issued a decision denying the LPSC’s appeal of the FERC’s October 2011 and February 2014 orders. On the issue of the FERC’s implementation of the prospective remedy as of June 2005 and whether the bandwidth remedy should be extended for an additional 17 months in years 2004-2005, the D.C. Circuit affirmed the FERC’s implementation of the remedy and denied the LPSC’s appeal. On the issue of whether the operating companies should be required to issue refunds for the 20-month period from September 2001 to May 2003, the D.C. Circuit granted the FERC’s request for agency reconsideration and remanded that issue back to the FERC for further proceedings as requested by all parties to the appeal. In response to the D.C. Circuit’s remand, various parties filed briefs with the FERC addressing whether the FERC should require the Utility operating companies to issue refunds for the 20-month refund period from September 2001 to May 2003. The LPSC has argued in favor of such remands and Entergy has opposed the LPSC’s request. The briefing was completed in September 2018 and the matter is pending before the FERC.

In April and May 2014, Entergy filed with the FERC an updated compliance filing that provided the payments and receipts among the Utility operating companies pursuant to the FERC’s February 2014 orders.  The filing showed the following net payments and receipts, including interest, among the Utility operating companies:

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$68
Entergy Louisiana	($10)
Entergy Mississippi	($11)
Entergy New Orleans	$2
Entergy Texas	($49)

These payments were made in May 2014. The LPSC, City Council, and APSC filed protests.

The hearing on the bandwidth calculation for the seven months June 1, 2005 through December 31, 2005 occurred in July 2016. The presiding judge issued an initial decision in November 2016. In the initial decision, the presiding judge agreed with the Utility operating companies’ position that: (1) interest on the bandwidth payments for the 2005 test period should be accrued from June 1, 2006 until the date that the bandwidth payments for that calculation are paid, which is consistent with how the Utility operating companies performed the calculation; and (2) a portion of Entergy Louisiana’s 2001-vintage Louisiana state net operating loss accumulated deferred income tax that results from the Vidalia tax deduction should be excluded from the 2005 test period bandwidth calculation. Various participants filed briefs on exceptions and/or briefs opposing exceptions related to the initial decision, including the LPSC, the APSC, the FERC trial staff, and Entergy Services. In May 2018 the FERC issued an order affirming the initial decision and ordered a comprehensive recalculation of the bandwidth payments/receipts for the seven months June 1, 2005 through December 31, 2005 and a recalculation of the 2006 and 2007 test years as a result of limited revisions. Entergy filed the comprehensive recalculation of the bandwidth payments/receipts for the seven months June 1, 2005 through December 31, 2005 and the 2006 and 2007 test years in July 2018. The filing shows the additional following payments and receipts among the Utility operating companies:

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	($4)
Entergy Louisiana	($23)
Entergy Mississippi	$16
Entergy New Orleans	$5
Entergy Texas	$6

These payments were made in July 2018. In January 2019 the FERC denied the LPSC’s request for rehearing of the May 2018 order.

Rough Production Cost Equalization Rates

Each May from 2007 through 2016 Entergy filed with the FERC the rates to implement the FERC’s orders in the System Agreement proceeding.  These filings showed the following payments/receipts among the Utility operating companies were necessary to achieve rough production cost equalization as defined by the FERC’s orders:

	Payments (Receipts)
	2007			2008			2009			2010			2011			2012			2013			2014
	(In Millions)
Entergy Arkansas		$252			$252			$390			$41			$77			$41			$—			$—
Entergy Louisiana		($211	)		($160	)		($247	)		($22	)		($12	)		($41	)		$—			$—
Entergy Mississippi		($41	)		($20	)		($24	)		($19	)		($40	)		$—			$—			$—
Entergy New Orleans		$—			($7	)		$—			$—			($25	)		$—			($15	)		($15	)
Entergy Texas		($30	)		($65	)		($119	)		$—			$—			$—			$15			$15

The Utility operating companies recorded accounts payable or accounts receivable to reflect the rough production cost equalization payments and receipts required to implement the FERC’s remedy.  When accounts payable were recorded, a corresponding regulatory asset was recorded for the right to collect the payments from customers. When accounts receivable were recorded, a corresponding regulatory liability was recorded for the obligations to pass the receipts on to customers.  No payments were required in 2016 or 2015 to implement the FERC’s remedy based on calendar year 2015 production costs and 2014 production costs, respectively. The System Agreement terminated in August 2016.

The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas.  Entergy Texas recovered its 2013 rough production cost equalization payment over three years beginning April 2014. Entergy Texas included its 2014 rough production cost equalization payment as a component of an interim fuel refund made in 2014. Management believes that any changes in the allocation of production costs resulting from the FERC’s decision and related retail proceedings should result in similar rate changes for retail customers, subject to specific circumstances that have caused trapped costs.

The following rough production cost equalization rate proceedings are still ongoing or were ongoing during the period 2016-2018.

2010 Rate Filing Based on Calendar Year 2009 Production Costs

In May 2010, Entergy filed with the FERC the 2010 rates in accordance with the FERC’s orders in the System Agreement proceeding, and supplemented the filing in September 2010.  Several parties intervened in the proceeding at the FERC, including the LPSC and the City Council, which also filed protests.  In July 2010 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2010, subject to refund.  After an abeyance of the proceeding schedule, a hearing was held in March 2014 and in December 2015 the FERC issued an order. Among other things, the December 2015 order directed Entergy to submit a compliance filing. In January 2016 the LPSC, the APSC, and Entergy filed requests for rehearing of the FERC’s December 2015 order. In February 2016, Entergy submitted the compliance filing ordered in the December 2015 order.  The result of the true-up payments and receipts for the recalculation of production costs resulted in the following payments/receipts among the Utility operating companies:

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$2
Entergy Louisiana	$6
Entergy Mississippi	($4)
Entergy New Orleans	($1)
Entergy Texas	($3)

In September 2016 the FERC accepted the February 2016 compliance filing subject to a further compliance filing made in November 2016. The further compliance filing was required as a result of an order issued in September 2016 ruling on the January 2016 rehearing requests filed by the LPSC, the APSC, and Entergy. In the order addressing the rehearing requests, the FERC granted the LPSC’s rehearing request and directed that interest be calculated on the payment/receipt amounts. The FERC also granted the APSC’s and Entergy’s rehearing request and ordered the removal of both securitized asset accumulated deferred income taxes and contra-securitization accumulated deferred income taxes from the calculation. In November 2016, Entergy submitted its compliance filing in response to the FERC’s order on rehearing. The compliance filing included a revised calculation of the bandwidth true-up payments and receipts based on 2009 test year data and interest calculations. The LPSC protested the interest calculations. In November 2017 the FERC issued an order rejecting the November 2016 compliance filing. The FERC determined that the payments detailed in the November 2016 compliance filing did not include adequate interest for the payments from Entergy Arkansas to Entergy Louisiana because it did not include interest on the principal portion of the payment that was made in February 2016. In December 2017, Entergy recalculated the interest pursuant to the November 2017 order. As a result of the recalculations, Entergy Arkansas owed very minor payments to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.

2011 Rate Filing Based on Calendar Year 2010 Production Costs

In May 2011, Entergy filed with the FERC the 2011 rates in accordance with the FERC’s orders in the System Agreement proceeding.  Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest.  In July 2011 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2011, subject to refund. After an abeyance of the proceeding schedule, in December 2014 the FERC consolidated the 2011 rate filing with the 2012, 2013, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

2012 Rate Filing Based on Calendar Year 2011 Production Costs

In May 2012, Entergy filed with the FERC the 2012 rates in accordance with the FERC’s orders in the System Agreement proceeding.  Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest.  In August 2012 the FERC accepted Entergy’s proposed rates for filing, effective June 2012, subject to refund. After an abeyance of the proceeding schedule, in December 2014 the FERC consolidated the 2012 rate filing with the 2011, 2013, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

2013 Rate Filing Based on Calendar Year 2012 Production Costs

In May 2013, Entergy filed with the FERC the 2013 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest. The City Council intervened and filed comments related to including the outcome of a related FERC proceeding in the 2013 cost equalization calculation. In August 2013 the FERC issued an order accepting the 2013 rates, effective June 1, 2013, subject to refund. After an abeyance of the proceeding schedule, in December 2014 the FERC consolidated the 2013 rate filing with the 2011, 2012, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

2014 Rate Filing Based on Calendar Year 2013 Production Costs

In May 2014, Entergy filed with the FERC the 2014 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest. The City Council intervened and filed comments. In December 2014 the FERC issued an order accepting the 2014 rates, effective June 1, 2014, subject to refund, set the proceeding for hearing procedures, and consolidated the 2014 rate filing with the 2011, 2012, and 2013 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

Consolidated 2011, 2012, 2013, and 2014 Rate Filing Proceedings

As discussed above, in December 2014 the FERC consolidated the 2011, 2012, 2013, and 2014 rate filings for settlement and hearing procedures. In May 2015, Entergy filed direct testimony in the consolidated rate filings and the LPSC filed direct testimony concerning its complaint proceeding that is consolidated with the rate filings, challenging certain components of the pending bandwidth calculations for prior years. Hearings occurred in November 2015, and the ALJ issued an initial decision in July 2016. In the initial decision, the ALJ generally agreed with Entergy’s bandwidth calculations with one exception on the accounting related to the Waterford 3 sale/leaseback. In March 2018 the FERC issued an order affirming the initial decision. In April 2018 the LPSC requested rehearing of the FERC’s March 2018 order affirming the ALJ’s initial decision. Entergy filed in May 2018 the bandwidth true-up payments and receipts for the 2011-2014 rate filings (table does not net to zero due to rounding):

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$3
Entergy Louisiana	$3
Entergy Mississippi	($1)
Entergy New Orleans	$1
Entergy Texas	($5)

These payments were made in May 2018. The LPSC request for rehearing is pending.

Utility Operating Company Termination of System Agreement Participation

Entergy Arkansas and Entergy Mississippi ceased participating in the System Agreement effective December 18, 2013 and November 7, 2015, respectively. Entergy Louisiana, Entergy New Orleans, and Entergy Texas terminated participation in the System Agreement on August 31, 2016, which resulted in the termination of the System Agreement in its entirety pursuant to a settlement agreement approved by the FERC in December 2015.

In December 2013 the FERC set one issue for hearing involving whether and how the benefits associated with settlement with Union Pacific regarding certain coal delivery issues should be allocated among Entergy Arkansas and the other Utility operating companies post-termination of the System Agreement. In December 2014 a FERC ALJ issued an initial decision finding that Entergy Arkansas would realize benefits after December 18, 2013 from the 2008 settlement agreement between Entergy Services, Entergy Arkansas, and Union Pacific, related to certain coal delivery issues. In March 2016 the FERC issued an opinion affirming the December 2014 initial decision with regard to the determination that there were benefits related to the Union Pacific settlement, which were realized post-Entergy Arkansas’s December 2013 withdrawal from the System Agreement, that should be shared with the other Utility operating companies utilizing the methodology proposed by the MPSC and trued-up to actual coal volumes purchased. In May 2016, Entergy made a compliance filing that provided the calculation of Union Pacific settlement benefits utilizing the methodology adopted by the initial decision, trued-up for the actual volumes of coal purchased. The payments were made in May 2016. In August 2016 the FERC issued an order accepting Entergy’s compliance filing. Also in August 2016 the APSC filed a petition for review of the FERC’s March 2016 and August 2016 orders with the U.S. Court of Appeals for the D.C. Circuit. In June 2018 the D.C. Circuit denied the APSC’s petition.

Interruptible Load Proceeding

In April 2007 the U.S. Court of Appeals for the D.C. Circuit issued its opinion in the LPSC’s appeal of the FERC’s March 2004 and April 2005 orders related to the treatment under the System Agreement of the Utility operating companies’ interruptible loads.  In its opinion the D.C. Circuit concluded that the FERC: (1) acted arbitrarily and capriciously by allowing the Utility operating companies to phase-in the effects of the elimination of the interruptible load over a 12-month period of time; (2) failed to adequately explain why refunds could not be ordered under Section 206(c) of the Federal Power Act; and (3) exercised appropriately its discretion to defer addressing the cost of sulfur dioxide allowances until a later time.  The D.C. Circuit remanded the matter to the FERC for a more considered determination on the issue of refunds.  The FERC issued its order on remand in September 2007, in which it directed Entergy to make a compliance filing removing all interruptible load from the computation of peak load responsibility commencing April 1, 2004 and to issue any necessary refunds to reflect this change.  In addition, the order directed the Utility operating companies to make refunds for the period May 1995 through July 1996.  In November 2007 the Utility operating companies filed a refund report describing the refunds to be issued pursuant to the FERC’s orders.  The LPSC filed a protest to the refund report in December 2007.  The refunds were made in October 2008 by the Utility operating companies that owed refunds to the Utility operating companies that were due refunds under the decision.  The APSC and the Utility operating companies appealed the FERC decisions to the D.C. Circuit.

Following the filing of petitioners’ initial briefs, the FERC filed a motion requesting the D.C. Circuit hold the appeal of the FERC’s decisions ordering refunds in the interruptible load proceeding in abeyance and remand the record to the FERC.  The D.C. Circuit granted the FERC’s unopposed motion in June 2009.  In December 2009 the FERC established a paper hearing to determine whether the FERC had the authority and, if so, whether it would be appropriate to order refunds resulting from changes in the treatment of interruptible load in the allocation of capacity costs by the Utility operating companies.  In August 2010 the FERC issued an order stating that it has the authority and refunds are appropriate.  The APSC, the MPSC, and Entergy requested rehearing of the FERC’s decision.  In June 2011 the FERC issued an order granting rehearing in part and denying rehearing in part, in which the FERC determined to invoke its discretion to deny refunds.  The FERC held that in this case where “the Entergy system as a whole collected the proper level of revenue, but, as was later established, incorrectly allocated peak load responsibility among the various Entergy operating companies….the Commission will apply here our usual practice in such cases, invoking our equitable discretion to not order refunds, notwithstanding our authority to do so.”  The LPSC requested rehearing of the FERC’s June 2011 decision.  In July 2011 the refunds made in the fourth quarter 2008 described above were reversed. In October 2011 the FERC issued an “Order Establishing Paper Hearing” inviting parties that oppose refunds to file briefs within 30 days addressing the LPSC’s argument that FERC precedent supports refunds under the circumstances present in this proceeding.  Parties that favor refunds were then invited to file reply briefs within 21 days of the date that the initial briefs were due.  

In March 2013 the FERC issued an order denying the LPSC’s request for rehearing of the FERC’s June 2011 order wherein the FERC concluded it would exercise its discretion and not order refunds in the interruptible load proceeding. Based on its review of the LPSC’s request for rehearing and the briefs filed as part of the paper hearing established in October 2011, the FERC affirmed its earlier ruling and declined to order refunds under the circumstances of the case. In May 2013 the LPSC filed a petition for review with the U.S. Court of Appeals for the D.C. Circuit seeking review of FERC orders in the interruptible load proceeding that concluded that the FERC would exercise its discretion and not order refunds in the proceeding. Oral argument was held on the appeal in the D.C. Circuit in September 2014. In December 2014 the D.C. Circuit issued an order on the LPSC’s appeal and remanded the case back to the FERC. The D.C. Circuit rejected the LPSC’s argument that there is a presumption in favor of refunds, but it held that the FERC had not adequately explained its decision to deny refunds and directed the FERC “to consider the relevant factors and weigh them against one another.” In March 2015, Entergy filed with the FERC an initial brief on remand to address the December 2014 decision by the D.C. Circuit. The initial brief on remand argued that the FERC, in response to the D.C. Circuit decision, should clarify its policy on refunds and find that refunds are not required in the interruptible load proceeding.

In April 2016 the FERC issued an order on remand that addressed the December 2014 decision by the D.C. Circuit in the interruptible load proceeding. The order on remand affirmed the FERC’s denial of refunds for the 15-month refund effective period. The FERC explained and clarified its policies regarding refunds and concluded that the evidence in the record demonstrated that the relevant equitable factors favored not requiring refunds in this case. The FERC also noted that, under Section 206(c) of the Federal Power Act, in a Section 206 proceeding involving two or more electric utility companies of a registered holding company system, the FERC may order refunds only if it determines the refunds would not cause the registered holding company to experience any reduction in revenues resulting from an inability of an electric utility company in the system to recover the resulting increase in costs. The FERC stated it was not able to find that the Entergy system would not experience a reduction in revenues if refunds were awarded in this proceeding, which further supported the denial of refunds. In May 2016 the LPSC filed a request for rehearing of the FERC’s April 2016 order. In September 2016 the FERC issued an order denying the LPSC’s request for rehearing and reaffirming its denial of refunds for the 15-month refund effective period. The LPSC appealed the April and September 2016 orders to the U.S. Court of Appeals for the D.C. Circuit. In March 2018 the D.C. Circuit issued an order denying the LPSC’s appeal and affirming the FERC’s decision that it would be inequitable to award refunds in the proceeding. In April 2018 the LPSC sought rehearing en banc of the D.C. Circuit’s order denying the LPSC’s appeal. In May 2018 the D.C. Circuit denied the LPSC’s rehearing request. In August 2018 the LPSC filed with the Supreme Court of the United States a petition for a writ of certiorari to review the judgment of the D.C. Circuit. In November 2018 the Supreme Court of the United States denied the LPSC’s petition for a writ of certiorari to review the judgment of the D.C. Circuit, effectively terminating the interruptible load proceeding.

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’s 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’s appeal and held all of the appeals in abeyance pending final resolution of the related proceeding before the FERC.

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 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. 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.

Complaints Against System Energy

Return on Equity 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 the FERC to institute 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. System Energy is recording a provision against revenue for the potential outcome of this proceeding. In September 2017 the FERC established a refund effective date of January 23, 2017, consolidated the return on equity complaint with the proceeding described in Unit Power Sales Agreement below, 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 effective date 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 System Energy’s return on equity, with a refund effective date of April 2018. The portion of the LPSC’s complaint dealing with return on equity was subsequently consolidated with the APSC and MPSC complaint for hearing. The consolidated hearing has been scheduled for September 2019, and the parties are required to address 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 complaint, and System Energy submitted a response to the amended complaint in October 2018. In January 2019 the FERC set the amended complaint for settlement and hearing proceedings.

Grand Gulf Sale-leaseback Renewal Complaint

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 2018. The hearing has been scheduled for November 2019.

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 proposed amendments would result in lower charges to the Utility operating companies that buy capacity and energy from System Energy under the Unit Power Sales Agreement. The proposed changes are 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. System Energy requested that the FERC accept the amendments effective October 1, 2017.

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 propose 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. The FERC also consolidated the Unit Power Sales Agreement amendment proceeding with the proceeding described in“Return on Equity Complaints” above, and directed the parties to engage in settlement proceedings before an ALJ. 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.  The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages.  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.

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.  In February 2012, Entergy Louisiana sold 500,000 of its Class A preferred membership units in Entergy Holdings Company LLC, a wholly-owned Entergy subsidiary, to a third party in exchange for $51 million plus accrued but unpaid distributions on the units.  The 500,000 preferred membership units are mandatorily redeemable in January 2112.

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. As of April 30, 2016, Entergy Mississippi’s storm damage provision balance was less than $10 million, therefore Entergy Mississippi resumed billing the monthly storm damage provision effective with June 2016 bills. As of September 30, 2016, however, Entergy Mississippi’s storm damage provision balance exceeded $15 million. Accordingly the storm damage provision was reset to zero beginning with November 2016 bills. As of July 31, 2017, the balance in Entergy Mississippi’s accumulated storm damage provision was again less than $10 million, therefore Entergy Mississippi resumed billing the monthly storm damage provision effective with September 2017 bills. As of June 30, 2018, Entergy Mississippi’s storm damage provision balance exceeded $15 million. Accordingly the storm damage provision was reset to zero beginning with August 2018 bills.

Entergy New Orleans

In August 2012, Hurricane Isaac caused extensive damage to Entergy New Orleans’s service area. In January 2015 the City Council issued a resolution approving the terms of a joint agreement in principle filed by Entergy New Orleans, Entergy Louisiana, and the City Council Advisors determining, among other things, that Entergy New Orleans’s prudently-incurred storm recovery costs were $49.3 million, of which $31.7 million, net of reimbursements from the storm reserve escrow account, remained recoverable from Entergy New Orleans’s electric customers. The resolution also directed Entergy New Orleans to file an application to securitize the unrecovered City Council-approved storm recovery costs of $31.7 million pursuant to the Louisiana Electric Utility Storm Recovery Securitization Act (Louisiana Act 64). In addition, the resolution found that it was reasonable for Entergy New Orleans to include in the principal amount of its potential securitization the costs to fund and replenish Entergy New Orleans’s storm reserve in an amount that achieved the City Council-approved funding level of $75 million. In January 2015, in compliance with that directive, Entergy New Orleans filed with the City Council an application requesting that the City Council grant a financing order authorizing the financing of Entergy New Orleans’s storm costs, storm reserves, and issuance costs pursuant to Louisiana Act 64. In May 2015 the parties entered into an agreement in principle and the City Council issued a financing order authorizing Entergy New Orleans to issue storm recovery bonds in the aggregate amount of $98.7 million, including $31.8 million for recovery of Entergy New Orleans’s Hurricane Isaac storm recovery costs, including carrying costs, $63.9 million to fund and replenish Entergy New Orleans’s storm reserve, and approximately $3 million for estimated up-front financing costs associated with the securitization. See Note 5 to the financial statements for discussion of the issuance of the securitization bonds in July 2015.

New Nuclear Generation Development Costs

Entergy Louisiana

Entergy Louisiana and Entergy Gulf States Louisiana were developing a project option for new nuclear generation at River Bend.  In March 2010, Entergy Louisiana and Entergy Gulf States Louisiana filed with the LPSC seeking approval to continue the limited development activities necessary to preserve an option to construct a new unit at River Bend.  At its June 2012 meeting the LPSC voted to uphold an ALJ recommendation that the request of Entergy Louisiana and Entergy Gulf States Louisiana be declined on the basis that the LPSC’s rule on new nuclear development does not apply to activities to preserve an option to develop and on the further grounds that the companies improperly engaged in advanced preparation activities prior to certification.  The LPSC directed that Entergy Louisiana and Entergy Gulf States Louisiana be permitted to seek recovery of these costs in their upcoming rate case filings that were subsequently filed in February 2013. In the resolution of the rate case proceeding the LPSC provided for an eight-year amortization of costs incurred in connection with the potential development of new nuclear generation at River Bend, without carrying costs, beginning in December 2014, provided, however, that amortization of these costs shall not result in a future rate increase. As of December 31, 2018, Entergy Louisiana has a regulatory asset of $28.5 million on its balance sheet related to these new nuclear generation development costs.

Entergy Arkansas [Member]

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, 2018 and 2017:

Other Regulatory Assets

Entergy

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$2,611.5		$2,642.3
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	814.3		746.0
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 – Storm Cost Recovery Filings with Retail Regulators) (Note 5)	452.7		558.9
Removal costs - recovered through depreciation rates (Note 9)	375.8		436.5
Opportunity Sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding)	116.3		109.8
Unamortized loss on reacquired debt - recovered over term of debt	74.5		82.9
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy)	52.1		73.7
Retail rate deferrals - recovered through rate riders as rates are redetermined by retail regulators	39.0		86.4
New nuclear generation development costs (Note 2 - New Nuclear Generation Development Costs) (b)	29.0		36.4
Transition to competition costs - recovered over a 15-year period through February 2021	26.7		37.7
Other	154.6		125.1
Entergy Total		$4,746.5		$4,935.7

Entergy Arkansas

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$747.2		$757.0
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	381.7		345.2
Removal costs - recovered through depreciation rates (Note 9)	138.3		176.9
Opportunity sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding)	116.3		109.8
Storm damage costs - recovered either through securitization or retail rates (Note 5 - Entergy Arkansas Securitization Bonds)	60.7		76.2
Unamortized loss on reacquired debt - recovered over term of debt	21.2		24.3
Retail rate deferrals - recovered through rate riders as rates are redetermined annually	20.5		28.2
ANO Fukushima and Flood Barrier costs - recovered through retail rates through February 2026 (Note 2 - Retail Rate Proceedings) (b)	12.6		14.4
Other	36.5		35.4
Entergy Arkansas Total		$1,535.0		$1,567.4

Entergy Louisiana

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (a)		$711.8		$724.6
Asset Retirement Obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	232.9		218.6
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy)	49.8		71.4
New nuclear generation development costs - recovery through formula rate plan December 2014 through November 2022 (Note 2 - New Nuclear Generation Development Costs) (b)	28.5		35.8
Unamortized loss on reacquired debt - recovered over term of debt	22.5		24.7
Storm damage costs - recovered through retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)	17.9		14.3
Business combination external costs deferral - recovery through formula rate plan December 2015 through November 2025 (b)	12.4		14.1
River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC)	11.0		12.9
Other	18.3		29.4
Entergy Louisiana Total		$1,105.1		$1,145.8

Entergy Mississippi

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$215.9		$218.7
Removal costs - recovered through depreciation rates (Note 9)	63.5		91.6
Attorney General litigation costs (Note 2 - Mississippi Attorney General Complaint) (b)	23.6		9.3
Retail rate deferrals - recovered through rate riders as rates are redetermined annually	16.6		49.4
Unamortized loss on reacquired debt - recovered over term of debt	16.2		17.6
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a)	7.2		7.6
Other	—		3.7
Entergy Mississippi Total		$343.0		$397.9

Entergy New Orleans

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$96.2		$102.8
Storm damage costs, including hurricane costs - recovered through retail rates and securitization (Note 2 - Storm Cost Recovery Filings with Retail Regulators)	70.4		82.3
Removal costs - recovered through depreciation rates (Note 9)	49.3		44.8
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a)	4.5		4.3
Unamortized loss on reacquired debt - recovered over term of debt	2.6		3.0
Rate case costs - recovered over a 6-year period through September 2021 (Note 2 - Retail Rate Proceedings)	1.9		2.6
Retail rate deferrals - recovered through rate riders as rates are redetermined monthly or annually	—		4.4
Other	4.9		7.2
Entergy New Orleans Total		$229.8		$251.4

Entergy Texas

	2018		2017
	(In Millions)
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 5 - Entergy Texas Securitization Bonds)		$303.6		$386.1
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)	171.8		169.2
Removal costs - recovered through depreciation rates (Note 9)	50.9		55.2
Transition to competition costs - recovered over a 15-year period through February 2021	26.7		37.7
Neches and Sabine costs - recovered over a ten-year period through September 2028 (Note 2 - Retail Rate Proceedings) (b)	23.6		—
Unamortized loss on reacquired debt - recovered over term of debt	8.2		8.7
Other	13.2		4.5
Entergy Texas Total		$598.0		$661.4

System Energy

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Other Postretirement Benefits) (a)		$179.3		$202.7
Asset retirement obligation - recovery dependent upon timing of decommissioning (Note 9) (a)	186.9		169.1
Removal costs - recovered through depreciation rates (Note 9)	76.4		67.9
Unamortized loss on reacquired debt - recovered over term of debt	3.8		4.6
System Energy Total		$446.4		$444.3

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

(b) Does not earn a return on investment.

Other Regulatory Liabilities

Entergy

	2018		2017
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)		$815.9		$989.3
Vidalia purchased power agreement (Note 8) (b)	139.7		151.6
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) (b)	111.1		124.8
Income tax rate change - returned to electric and gas customers through retail rates (Note 2 - Retail Rate Proceedings)	74.7		—
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions)	67.9		67.9
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination)	50.8		65.8
Grand Gulf over-recovery - will be refunded through rate riders as rates are redetermined annually	48.6		—
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)	44.4		—
Internal restructuring guaranteed customer credits (Note 2 - Retail Rate Proceedings)	39.6		—
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)	39.1		36.7
Excess decommissioning recovery for Willow Glen - (Note 14 - Dispositions)	31.9		—
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement	25.0		32.1
Removal costs - returned to customers through depreciation rates (Note 9)	18.8		32.4
Other	68.4		43.5
Entergy Total		$1,620.3		$1,588.5

Entergy Arkansas

	2018		2017
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)		$297.2		$354.0
Internal restructuring guaranteed customer credits (Note 2 - Retail Rate Proceedings)	39.6		—
Future formula rate plan revenue reductions (Note 2 - Retail Rate Proceedings)	35.1		—
Grand Gulf over-recovery - will be refunded through rate riders as rates are redetermined annually	26.0		—
Other	4.8		9.6
Entergy Arkansas Total		$402.7		$363.6

Entergy Louisiana

	2018		2017
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)		$274.1		$323.7
Vidalia purchased power agreement (Note 8) (b)	139.7		151.6
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) (b)	111.1		124.8
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination)	50.8		65.8
Income tax rate change - returned to electric customers through retail rates September 2018 through August 2019 (Note 2 - Retail Rate Proceedings)	49.9		—
Asset Retirement Obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)	39.1		36.7
Excess decommissioning recovery for Willow Glen - (Note 14 - Dispositions)	31.9		—
Removal costs - returned to customers through depreciation rates (Note 9)	18.8		32.4
Other	33.4		26.1
Entergy Louisiana Total		$748.8		$761.1

Entergy Mississippi

	2018		2017
	(In Millions)
Grand Gulf Over-Recovery - returned to customers through rate riders when rates are redetermined annually		$22.6		$—
Future formula rate plan revenue reductions (Note 2 - Retail Rate Proceedings)	9.3		—
Other	1.7		0.9
Entergy Mississippi Total		$33.6		$0.9

Entergy Texas

	2018		2017
	(In Millions)
Income tax rate change - refunded through a rate rider (Note 2 - Retail Rate Proceedings)		$23.1		$—
Advanced metering system surcharge (Note 2 - Advanced Metering Infrastructure (AMI) Filings)	16.5		—
Transition to competition costs - returned to customers through rate riders when rates are redetermined periodically	4.2		4.8
Other	4.1		2.1
Entergy Texas Total		$47.9		$6.9

System Energy

	2018		2017
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 17) (a)		$244.6		$311.6
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions)	67.9		67.9
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
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement	25.0		32.1
System Energy Total		$381.9		$456.0

(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 $25.0 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 will be 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 to be 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 existing formula rate plan rider for its customers to realize the remaining benefits of the Tax Act. Entergy Arkansas’s formula rate plan rider includes a netting adjustment that compares 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.

Entergy Louisiana

In a 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 will be 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. Entergy Mississippi’s formula rate plan includes a look-back evaluation report filing in March 2019 that will compare actual 2018 results to the allowed return on rate base. The stipulation approved in June 2018 provides 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 any true-up to be 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. In November 2018, Entergy Mississippi’s annual redetermination of the annual factor to be applied under the power management rider included an insignificant true-up to the amount of unprotected excess accumulated deferred income taxes. In January 2019 the MPSC approved the proposed power management cost factor effective for February 2019 bills.

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. In both a memorandum issued prior to the open meeting when the order was discussed and during the discussions at the open meeting regarding the order, the PUCT indicated that it would consider utility earnings in determining the treatment of the liability and the effects of the Tax Act. 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. Entergy Texas also stated that it would be inappropriate for the PUCT to require a refund of the reduction in income tax expense in 2018 resulting from the Act on a retroactive basis and without a comprehensive review of Entergy Texas’s cost of service and earned return on equity.

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 will 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 will 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 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 larger customers and over a period of four years for other customers.

System Energy

In a filing made with the FERC in March 2018, Entergy proposed revisions to the Unit Power Sales Agreement, among other agreements, to reflect the effects of the Tax Act. In the filing System Energy proposed to return all of its 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 are ongoing.

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, 2018 and 2017 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.

	2018			2017
	(In Millions)
Entergy Arkansas (a)		$86.5			$130.4
Entergy Louisiana (b)		$136.7			$96.7
Entergy Mississippi		$8.0			$32.4
Entergy New Orleans (b)		$2.8			($3.7	)
Entergy Texas		($19.7	)		($67.3	)

(a) Includes $67.3 million in 2018 and $67.1 million in 2017 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

Production Cost Allocation Rider

The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings, which are discussed in the “System Agreement Cost Equalization Proceedings” section below.

In May 2016, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected recovery of the production cost allocation rider true-up adjustment of the 2014 and 2015 unrecovered retail balance in the amount of $1.9 million. Additionally, the redetermined rates reflected the recovery of a $1.9 million System Agreement bandwidth remedy payment resulting from a compliance filing pursuant to the FERC’s December 2015 order related to test year 2009 production costs. The rates for the 2016 production cost allocation rider update were effective July 2016 through June 2017.

In May 2017, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected a credit amount of $0.3 million resulting from a compliance filing pursuant to the FERC’s September 2016 order. Additionally, the redetermined rate reflected recovery of the production cost allocation rider true-up adjustment of the 2016 unrecovered retail balance in the amount of $0.3 million. Because of the small effect of the 2017 production cost allocation rider update, Entergy Arkansas proposed to reduce the effective period of the update to one month, July 2017. After the one month collection period, rates were set to zero for all rate classes for the period August 2017 through June 2018.

In May 2018, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected recovery of the 2017 under-recovered retail balance and a $2.8 million payment by Entergy Arkansas associated with a compliance filing pursuant to a March 2018 FERC order related to 2010 production costs. The rates for the 2018 production cost allocation rider update are effective July 2018 through June 2019.

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.

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 December 2011 the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates.  The audit included a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 2005 through 2009.  In March 2016 the LPSC staff consultant issued its audit report. In its report, the LPSC staff consultant recommended that Entergy Louisiana refund approximately $8.6 million, plus interest, to customers and realign the recovery of approximately $12.7 million from Entergy Gulf States Louisiana’s fuel adjustment clause to base rates. In September 2016 the LPSC staff filed testimony stating that it was no longer recommending a disallowance of $3.4 million of the $8.6 million discussed above, but otherwise maintained the positions from its report. Subsequently, the parties entered into a settlement, which was approved by the LPSC in November 2016. The settlement recognized the dry cask storage recovery method issue, which was addressed in the separate proceeding approved by the LPSC in October 2017, provided for a refund of $5 million, which was made to legacy Entergy Gulf States Louisiana customers in December 2016, and resolved all other issues raised in the audit.

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 is evaluating the staff’s recommended disallowance.

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 consultant issued its audit report. In its report, the LPSC staff consultant recommended 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 is evaluating the staff’s recommended disallowance.

In June 2016 the LPSC staff provided notice of audits of Entergy Louisiana’s fuel adjustment clause filings and purchased gas adjustment clause filings. In recognition of the business combination that occurred in 2015, the audit notice was issued to Entergy Louisiana and will also include a review of charges to legacy Entergy Gulf States Louisiana customers prior to the business combination. The audit includes 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. Discovery commenced in March 2017. No report of audit has been issued.

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.  Discovery commenced in September 2018.  No report of audit has been issued.

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 November 2015, 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 a projected over-recovery balance of $48 million projected through January 31, 2016. In January 2016 the MPSC approved the redetermined annual factor effective February 1, 2016. The MPSC further ordered, however, that due to the significant change in natural gas price forecasts since Entergy Mississippi’s filing in November 2015 Entergy Mississippi should file a revised fuel factor with the MPSC no later than February 1, 2016. Pursuant to that order, Entergy Mississippi submitted a revised fuel factor. Additionally, because Entergy Mississippi’s projected over-recovery balance for the period ending January 31, 2016 was $68 million, in February 2016, Entergy Mississippi filed for another interim adjustment to the energy cost factor effective April 2016 to flow through to customers the projected over-recovery balance over a six-month period. That interim adjustment was approved by the MPSC in February 2016 effective for April 2016 bills.

In November 2016, 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 less than $2 million as of September 30, 2016. In January 2017 the MPSC approved the annual factor effective with February 2017 bills. Also 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 its order, the MPSC expressly reserved the right to review and determine the recoverability of any and all purchased power expenditures made during fiscal year 2016. The MPSC hired independent auditors to conduct an annual operations audit and a financial audit. The independent auditors issued their audit reports in December 2017. The audit reports included several recommendations for action by Entergy Mississippi but did not recommend any cost disallowances. In January 2018 the MPSC certified the audit reports to the Mississippi Legislature. In November 2017 the Public Utilities Staff separately engaged a consultant to review the outage at the Grand Gulf Nuclear Station that began in 2016. The review is currently in progress.

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. Entergy Mississippi proposed a two-tiered energy cost factor designed to promote overall rate stability throughout 2018 particularly during the summer months. 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.

Mississippi Attorney General Complaint

The Mississippi Attorney General filed a complaint in state court in December 2008 against Entergy Corporation, Entergy Mississippi, Entergy Services, and Entergy Power alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution.  The complaint is wide ranging and relates to tariffs and procedures under which Entergy Mississippi purchases power not generated in Mississippi to meet electricity demand.  Entergy believes the complaint is unfounded.  In December 2008 the defendant Entergy companies removed the Attorney General’s lawsuit to U.S. District Court in Jackson, Mississippi. In June 2010 the MPSC authorized the deferral of certain legal expenses associated with this litigation until it is resolved. As of December 31, 2018, Entergy Mississippi has a regulatory asset of $23.6 million for these deferred legal expenses. Pre-trial and settlement conferences were held in October 2018. In October 2018 the District Court rescheduled the trial to April 2019.

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 July 2015 certain parties filed briefs in a PUCT proceeding asserting that Entergy Texas should refund to retail customers an additional $10.9 million in bandwidth remedy payments Entergy Texas received related to calendar year 2006 production costs.  In October 2015 an ALJ issued a proposal for decision recommending that the additional bandwidth remedy payments be refunded to retail customers. In January 2016 the PUCT issued its order affirming the ALJ’s recommendation, and Entergy Texas filed a motion for rehearing of the PUCT’s decision, which the PUCT denied. In March 2016, Entergy Texas filed a complaint in Federal District Court for the Western District of Texas and a petition in the Travis County (State) District Court appealing the PUCT’s decision. The pending appeals did not stay the PUCT’s decision. In April 2016, Entergy Texas filed with the PUCT an application to refund to customers approximately $56.2 million. The refund resulted from (i) $41.8 million of fuel cost recovery over-collections through February 2016, (ii) the $10.9 million in bandwidth remedy payments, discussed above, that Entergy Texas received related to calendar year 2006 production costs, and (iii) $3.5 million in bandwidth remedy payments that Entergy Texas received related to 2006-2008 production costs. In June 2016, Entergy Texas filed an unopposed settlement agreement that added additional over-recovered fuel costs for the months of March and April 2016. The settlement resulted in a $68 million refund. The ALJ approved the refund on an interim basis and it was made to most customers over a four-month period beginning with the first billing cycle of July 2016. In July 2016 the PUCT issued an order approving the interim refund. The federal appeal of the PUCT’s January 2016 decision was heard in December 2016, and the Federal District Court granted Entergy Texas’s requested relief. In January 2017 the PUCT and an intervenor filed petitions for appeal of the Federal District Court ruling to the U.S. Court of Appeals for the Fifth Circuit. Oral argument was held before the Fifth Circuit in February 2018. In April 2018 the Fifth Circuit reversed the decision of the Federal District Court, reinstating the original PUCT decision. In October 2018, Entergy Texas filed notice of nonsuit in its appeal to the Travis County District Court regarding the PUCT’s January 2016 decision.

In July 2016, Entergy Texas filed an application to reconcile its fuel and purchased power costs for the period April 1, 2013 through March 31, 2016. During the reconciliation period, Entergy Texas incurred approximately $1.77 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 over-recovery balance of approximately $19.3 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning April 2016. Entergy Texas also noted, however, that the estimated $19.3 million over collection was being refunded to customers as a portion of the interim fuel refund beginning with the first billing cycle of July 2016, discussed above. Entergy Texas also requested a prudence finding for each of the fuel-related contracts and arrangements entered into or modified during the reconciliation period that have not been reviewed by the PUCT in a prior proceeding. In December 2016, Entergy Texas entered into a stipulation and settlement agreement resulting in a $6 million disallowance not associated with any particular issue raised and a refund of the over-recovery balance of $21 million as of November 30, 2016, to most customers beginning April 2017 through June 2017. This settlement was developed concurrently with the stipulation and settlement agreement in the 2016 transmission cost recovery factor rider amendment discussed below, and the terms and conditions in both settlements are interdependent. The fuel reconciliation settlement was approved by the PUCT in March 2017 and the refunds were made.

In June 2017, Entergy Texas filed an application for a fuel refund of approximately $30.7 million for the months of December 2016 through April 2017. For most customers, the refunds flowed through bills for the months of July 2017 through September 2017. The fuel refund was approved by the PUCT in August 2017.

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.

Retail Rate Proceedings

Filings with the APSC (Entergy Arkansas)

Retail Rates

2015 Base Rate Filing

In April 2015, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. The filing notified the APSC of Entergy Arkansas’s intent to implement a forward test year formula rate plan pursuant to Arkansas legislation passed in 2015, and requested a retail rate increase of $268.4 million, with a net increase in revenue of $167 million. The filing requested a 10.2% return on common equity. In December 2015, Entergy Arkansas, the APSC staff, and certain of the intervenors in the rate case filed with the APSC a joint motion for approval of a settlement of the case that proposed a retail rate increase of approximately $225 million with a net increase in revenue of approximately $133 million; an authorized return on common equity of 9.75%; and a formula rate plan tariff that provides a +/- 50 basis point band around the 9.75% allowed return on common equity. A significant portion of the rate increase is related to Entergy Arkansas’s acquisition in March 2016 of Union Power Station Power Block 2 for a base purchase price of $237 million. The settlement agreement also provided for amortization over a 10-year period of $7.7 million of previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance. In February 2016 the APSC approved the settlement with one exception that reduced the retail rate increase proposed in the settlement by $5 million. The settling parties agreed to the APSC modifications in February 2016. The new rates were effective February 24, 2016 and began billing with the first billing cycle of April 2016. In March 2016, Entergy Arkansas made a compliance filing regarding the new rates that included an interim base rate adjustment surcharge, effective with the first billing cycle of April 2016, to recover the incremental revenue requirement for the period February 24, 2016 through March 31, 2016. The interim base rate adjustment surcharge was designed to recover a total of $21.1 million over the nine-month period from April 2016 through December 2016.

2016 Formula Rate Plan Filing

In July 2016, Entergy Arkansas filed with the APSC its 2016 formula rate plan filing showing Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2017 test period to be below the formula rate plan bandwidth. The filing requested a $67.7 million revenue requirement increase to achieve Entergy Arkansas’s target earned return on common equity of 9.75%. In October 2016, Entergy Arkansas filed with the APSC revised formula rate plan attachments with an updated request for a $54.4 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors, as well as three additional adjustments identified as appropriate by Entergy Arkansas. In November 2016 a hearing was held and the APSC issued an order directing the parties to brief certain issues. In December 2016 the APSC approved a settlement agreement and the $54.4 million revenue requirement increase with approximately $25 million of the $54.4 million revenue requirement subject to possible future adjustment and refund to customers with interest. The APSC requested supplemental information for some of Entergy Arkansas’s requested nuclear expenditures. In December 2016 the APSC approved Entergy Arkansas’s formula rate plan compliance tariff, and the rates became effective with the first billing cycle of January 2017. In April 2017, Entergy Arkansas filed a motion consented to by all parties requesting that it be permitted to submit the supplemental information requested by the APSC in conjunction with its 2017 formula rate plan filing, which was subsequently made in July 2017 and is discussed below. In May 2017 the APSC approved the joint motion and proposal to review Entergy Arkansas’s supplemental information on a concurrent schedule with the 2017 formula rate plan filing. In October 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement resolving all issues in the proceeding and providing for recovery of the 2017 and 2018 nuclear costs. In December 2017 the APSC approved the settlement agreement and recovery of the 2017 and 2018 nuclear costs.

2017 Formula Rate Plan Filing

In July 2017, Entergy Arkansas filed with the APSC its 2017 formula rate plan filing showing Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2018 test period to be below the formula rate plan bandwidth.  The filing projected a $129.7 million revenue requirement increase to achieve Entergy Arkansas’s target earned return on common equity of 9.75%.  Entergy Arkansas’s formula rate plan is subject to a four percent annual revenue constraint and the projected annual revenue requirement increase exceeded the four percent, resulting in a proposed increase for the 2017 formula rate plan of $70.9 million. In October 2017, Entergy Arkansas filed with the APSC revised formula rate plan attachments that projected a $126.2 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors. The revised formula rate plan filing included a proposed $71.1 million revenue requirement increase based on a revision to the four percent constraint calculation. In October 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement resolving all issues in the proceeding and providing for recovery of the 2017 and 2018 nuclear costs. In December 2017 the APSC approved the settlement agreement and the $71.1 million revenue requirement increase, as well as Entergy Arkansas’s formula rate plan compliance tariff, and the rates became effective with the first billing cycle of January 2018.

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 shows 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 includes 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 includes a projected $73.4 millionrevenue 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 exceeds the constraint, the resulting increase is 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, which included additional actual revenues for 2018. 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 certain 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. An additional schedule was issued by the APSC for briefing other contested issues, the outcome of which did not affect the 2018 filing but could affect future Entergy Arkansas formula rate plan filings. That briefing was completed in February 2019, and the APSC has not indicated when a decision on those issues can be expected.

Similar to the 2018 filing, the formula rate plan filing that will be made in 2019 to set the formula rates for the 2020 calendar year will include a netting adjustment that will compare projected costs and sales for 2018 that were approved in the 2017 formula rate plan filing to actual 2018 costs and sales data. In the fourth quarter 2018, Entergy Arkansas recorded a provision of $35.1 million that reflects the estimate of the historical year netting adjustment that will be included in the 2019 filing to reflect the change in formula rate plan revenues associated with actual 2018 results when compared to the allowed rate of return on equity. 

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. Entergy Arkansas also filed a notice with the Missouri Public Service Commission in December 2017 out of an abundance of caution, although Entergy Arkansas does not serve any retail customers in Missouri. In April 2018 the Missouri Public Service Commission approved Entergy Arkansas’s filing. 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

2015 Formula Rate Plan Filing

In May 2016, Entergy Louisiana filed its formula rate plan evaluation report for its 2015 calendar year operations. The evaluation report reflected an earned return on common equity of 9.07%. As such, no adjustment to base formula rate plan revenue was required. The following other adjustments, however, were required under the formula rate plan: an increase in the legacy Entergy Louisiana additional capacity mechanism of $14.2 million; a separate increase in legacy Entergy Louisiana revenue of $10 million primarily to reflect the effects of the termination of the System Agreement; an increase in the legacy Entergy Gulf States Louisiana additional capacity mechanism of $0.5 million; a decrease in legacy Entergy Gulf States Louisiana revenue of $58.7 million primarily to reflect the effects of the termination of the System Agreement; and an increase of $11 million to the MISO cost recovery mechanism. Rates were implemented with the first billing cycle of September 2016, subject to refund. Following implementation of the as-filed rates in September 2016, there were several interim updates to Entergy Louisiana’s formula rate plan, including the one submitted in December 2016, reflecting implementation of the settlement of the Waterford 3 replacement steam generator project prudence review described below. In June 2017 the LPSC staff and Entergy Louisiana filed a joint report of proceedings, which was accepted by the LPSC in June 2017, finalizing the results of the May 2016 evaluation report, interim updates, and corresponding proceedings with no changes to rates already implemented.

2016 Formula Rate Plan Filing

In May 2017, Entergy Louisiana filed its formula rate plan evaluation report for its 2016 calendar year operations. The evaluation report reflected an earned return on common equity of 9.84%. As such, no adjustment to base formula rate plan revenue was required. Adjustments, however, were required under the formula rate plan; the 2016 formula rate plan evaluation report showed a decrease in formula rate plan revenue of approximately $16.9 million, comprised of a decrease in legacy Entergy Louisiana formula rate plan revenue of $3.5 million, a decrease in legacy Entergy Gulf States Louisiana formula rate plan revenue of $9.7 million, and a decrease in incremental formula rate plan revenue of $3.7 million. Additionally, the formula rate plan evaluation report called for a decrease of $40.5 million in the MISO cost recovery revenue requirement from $46.8 million to $6.3 million. Rates reflecting these adjustments were implemented with the first billing cycle of September 2017, subject to refund. In September 2017 the LPSC issued its report indicating that no changes to Entergy Louisiana’s original formula rate plan evaluation report were required but reserved for several issues, including Entergy Louisiana’s September 2017 update to its formula rate plan evaluation report.  In July 2018, Entergy Louisiana and the LPSC staff filed an unopposed joint report setting forth a correction to the annualization calculation, the effect of which was a net $3.5 million revenue requirement reduction and indicating that there are no outstanding issues with the 2016 formula rate plan report, the supplemental report, or the interim updates.  In September 2018 the LPSC approved the unopposed joint report.

Formula Rate Plan Extension Through 2019 Test Year

In August 2017, Entergy Louisiana filed a request with the LPSC seeking to extend its formula rate plan for three years (2017-2019) with limited modifications of its terms.  Those modifications include: a one-time resetting of base rates to the midpoint of the band at Entergy Louisiana’s authorized return on equity of 9.95% for the 2017 test year; narrowing of the formula rate plan bandwidth from a total of 160 basis points to 80 basis points; and a forward-looking mechanism that would allow Entergy Louisiana to recover certain transmission-related costs contemporaneously with when those projects begin delivering benefits to customers.  In April 2018 the LPSC approved an unopposed joint motion filed by Entergy Louisiana and the LPSC staff that settled the matter. The settlement extended the formula rate plan for three years, providing for rates through at least August 2021. In addition to retaining the major features of the traditional formula rate plan, substantive features of the extended formula rate plan include:

• a mid-point reset of formula rate plan revenues to a 9.95% earned return on common equity for the 2017 test year and for the St. Charles Power Station when it enters commercial operation;

• a 9.8% target earned return on common equity for the 2018 and 2019 test years;

• narrowing of the common equity bandwidth to plus or minus 60 basis points around the target earned return on common equity;

• a cap on potential revenue increase of $35 million for the 2018 evaluation period, and $70 million for the cumulative 2018 and 2019 evaluation periods, on formula rate plan cost of service rate increases (the cap excludes rate changes associated with the transmission recovery mechanism described below and rate changes associated with additional capacity);

• a framework for the flow back of certain tax benefits created by the Tax Act to customers, as described in “Regulatory activity regarding the Tax Cuts and Jobs Act” above; and

• a transmission recovery mechanism providing for the opportunity to recover certain transmission-related expenditures in excess of $100 million annually for projects placed in service up to one month prior to rate change outside of sharing that is designed to operate in a fashion similar to the additional capacity mechanism.

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.

Waterford 3 Replacement Steam Generator Project

Following the completion of the Waterford 3 replacement steam generator project, the LPSC undertook a prudence review in connection with a filing made by Entergy Louisiana in April 2013 with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs. In July 2014 the LPSC staff filed testimony recommending potential project and replacement power cost disallowances of up to $71 million, citing a need for further explanation or documentation from Entergy Louisiana.  An intervenor filed testimony recommending disallowance of $141 million of incremental project costs, claiming the steam generator fabricator was imprudent.  Entergy Louisiana provided further documentation and explanation requested by the LPSC staff. An evidentiary hearing was held in December 2014. Entergy Louisiana believed that the replacement steam generator costs were prudently incurred and applicable legal principles supported their recovery in rates.  Nevertheless, Entergy Louisiana recorded a write-off of $16 million of Waterford 3’s plant balance in December 2014 because of the uncertainty at the time associated with the resolution of the prudence review. In December 2015 the ALJ issued a proposed recommendation, which was subsequently finalized, concluding that Entergy Louisiana prudently managed the Waterford 3 replacement steam generator project, including the selection, use, and oversight of contractors, and could not reasonably have anticipated the damage to the steam generators. Nevertheless, the ALJ concluded that Entergy Louisiana was liable for the conduct of its contractor and subcontractor and, therefore, recommended a disallowance of $67 million in capital costs. Additionally, the ALJ concluded that Entergy Louisiana did not sufficiently justify the incurrence of $2 million in replacement power costs during the replacement outage. Although the ALJ’s recommendation had not yet been considered by the LPSC, after considering the progress of the proceeding in light of the ALJ recommendation, Entergy Louisiana recorded in the fourth quarter 2015 approximately $77 million in charges, including a $45 million asset write-off and a $32 million regulatory charge, to reflect that a portion of the assets associated with the Waterford 3 replacement steam generator project was no longer probable of recovery. Entergy Louisiana maintained that the ALJ’s recommendation contained significant factual and legal errors.

In October 2016 the parties reached a settlement in this matter. The settlement was approved by the LPSC in December 2016. The settlement effectively provided for an agreed-upon disallowance of $67 million of plant, which had been previously written off by Entergy Louisiana, as discussed above. The refund to customers of approximately $71 million as a result of the settlement approved by the LPSC was made to customers in January 2017. Of the $71 million of refunds, $68 million was credited to customers through Entergy Louisiana’s formula rate plan, outside of sharing, and $3 million through its fuel adjustment clause. Entergy Louisiana had previously recorded a provision of $48 million for this refund. The previously-recorded provision included the cumulative revenues recorded through December 2016 related to the $67 million of disallowed plant. An additional regulatory charge of $23 million was recorded in fourth quarter 2016 to reflect the effects of the settlement. The settlement also provided that Entergy Louisiana could retain the value associated with potential service credits agreed to by the project contractor, to the extent they are realized in the future. Following a review by the parties, an unopposed joint report of proceedings was filed by the LPSC staff and Entergy Louisiana in May 2017 and the LPSC accepted the joint report of proceedings resolving the matter.

Union Power Station and Deactivation or Retirement Decisions for Entergy Louisiana Plants

In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC for approval of the acquisition and cost recovery of two power blocks of the Union Power Station for an expected base purchase price of approximately $237 million per power block, subject to adjustments. In September 2015, Entergy Gulf States Louisiana agreed to settlement terms with all parties for Entergy Gulf States Louisiana’s purchase of the two power blocks. In October 2015 the LPSC voted unanimously to approve the uncontested settlement which finds, among other things, that acquisition of Power Blocks 3 and 4 is in the public interest and, therefore, prudent. The business combination of Entergy Gulf States Louisiana and Entergy Louisiana received regulatory approval and closed in October 2015 making Entergy Louisiana the named purchaser of Power Blocks 3 and 4 of the Union Power Station. In March 2016, Entergy Louisiana acquired Power Blocks 3 and 4 of Union Power Station for an aggregate purchase price of approximately $475 million and implemented rates to collect the estimated first-year revenue requirement with the first billing cycle of March 2016.

As a term of the LPSC-approved settlement authorizing the purchase of Power Blocks 3 and 4 of the Union Power Station, Entergy Louisiana agreed to make a filing with the LPSC to review its decisions to deactivate Ninemile 3 and Willow Glen 2 and 4 and its decision to retire Little Gypsy 1.  In January 2016, Entergy Louisiana made its compliance filing with the LPSC. Entergy Louisiana, LPSC staff, and intervenors participated in a technical conference in March 2016 where Entergy Louisiana presented information on its deactivation/retirement decisions for these four units in addition to information on the current deactivation decisions for the ten-year planning horizon. Parties requested further proceedings on the prudence of the decision to deactivate Willow Glen 2 and 4.  No party contested the prudence of the decision to deactivate Willow Glen 2 and 4 or suggested reactivation of these units; however, issues were raised related to Entergy Louisiana’s decision to give up its transmission service rights in MISO for Willow Glen 2 and 4 rather than placing the units into suspended status for the three-year term permitted by MISO. In March 2018 the LPSC adopted the ALJ’s recommended order finding that Entergy Louisiana did not demonstrate that its decision to permanently surrender transmission rights for the mothballed (not retired) Willow Glen 2 and 4 units was reasonable and that Entergy Louisiana should hold customers harmless from increased transmission expenses should those units be reactivated. Because no party or the LPSC suggested that Willow Glen 2 and 4 should be reactivated and because the cost to return those units to service far exceeded the revenue the units were expected to generate in MISO, Entergy Louisiana retired Willow Glen 2 and 4 in March 2018. Entergy Louisiana submitted a compliance filing regarding retirement of Willow Glen 2 and 4, and the LPSC closed the proceeding.

Retail Rates - Gas

2016 Rate Stabilization Plan Filing

In January 2017, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2016. The filing of the evaluation report for test year 2016 reflected an earned return on common equity of 6.37%. In April 2017 the LPSC approved a joint report of proceedings and Entergy Louisiana submitted a revised evaluation report reflecting a $1.2 million annual increase in revenue with rates implemented with the first billing cycle of May 2017.

2017 Rate Stabilization Plan Filing

In January 2018, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2017.  The filing of the evaluation report for the test year 2017 reflected an earned return on common equity of 9.06%.  This earned return is below the earnings sharing band of the rate stabilization plan and results in a rate increase of $0.1 million.  Due to the enactment in late-December 2017 of the Tax Cuts and Jobs Act, Entergy Louisiana did not have adequate time to reflect the effects of this tax legislation in the rate stabilization plan.  In April 2018, Entergy Louisiana filed a supplemental evaluation report for the test year ended September 2017, reflecting the effects of the Tax Act, including a proposal to use the unprotected excess accumulated deferred income taxes to offset approximately $1.4 million of storm restoration deferred operation and maintenance costs incurred by Entergy Louisiana in connection with the August 2016 flooding disaster in its gas service area. The supplemental filing reflects an earned return on common equity of 10.79%. As-filed rates from the supplemental filing were implemented, subject to refund, with customers receiving a cost reduction of approximately $0.7 million effective with bills rendered on and after the first billing cycle of May 2018, as well as a $0.2 million reduction in the gas infrastructure rider effective with bills rendered on and after the first billing cycle of July 2018. The proceeding is currently in its discovery phase. A procedural schedule has not been established.

2018 Rate Stabilization Plan Filing

In January 2019, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2018. The filing of the evaluation report for the test year 2018 reflected an earned return on common equity of 2.69%. This earned return is below the earning sharing band of the gas rate stabilization plan and results in a rate increase of $2.8 million. Entergy Louisiana will make a compliance filing in April 2019 and rates will be implemented during the first billing cycle of May 2019.

Filings with the MPSC (Entergy Mississippi)

Formula Rate Plan Filings

In March 2016, Entergy Mississippi submitted its formula rate plan 2016 test year filing showing Entergy Mississippi’s projected earned return for the 2016 calendar year to be below the formula rate plan bandwidth. The filing showed a $32.6 million rate increase was necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 9.96%, within the formula rate plan bandwidth. In June 2016 the MPSC approved Entergy Mississippi’s joint stipulation with the Mississippi Public Utilities Staff. The joint stipulation provided for a total revenue increase of $23.7 million. The revenue increase included a $19.4 million increase through the formula rate plan, resulting in a return on common equity point of adjustment of 10.07%. The revenue increase also included $4.3 million in incremental ad valorem tax expenses to be collected through an updated ad valorem tax adjustment rider. The revenue increase and ad valorem tax adjustment rider were effective with the July 2016 bills.

In March 2017, Entergy Mississippi submitted its formula rate plan 2017 test year filing and 2016 look-back filing showing Entergy Mississippi’s earned return for the historical 2016 calendar year and projected earned return for the 2017 calendar year to be within the formula rate plan bandwidth, resulting in no change in rates. In June 2017, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a stipulation that confirmed that Entergy Mississippi’s earned returns for both the 2016 look-back filing and 2017 test year were within the respective formula rate plan bandwidths. In June 2017 the MPSC approved the stipulation, which resulted in no change in rates.

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.

Entergy Mississippi’s formula rate plan includes a look-back evaluation report filing in March 2019 that will compare actual 2018 results to the performance-adjusted allowed return on rate base.  In fourth quarter 2018, Entergy Mississippi recorded a provision of $9.3 million that reflects the estimate of the difference between the 2018 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 October 2018, Entergy Mississippi proposed revisions to its formula rate plan that would provide for a mechanism, the interim capacity rate adjustment mechanism, in the formula rate plan 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 additions, such as the Sunflower Solar Facility, that are approved by the MPSC.

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

As a provision of the settlement agreement approved by the City Council in May 2015 providing for the transfer from Entergy Louisiana to Entergy New Orleans of certain assets that supported the provision of service to Entergy Louisiana’s customers in Algiers, it was agreed that, with limited exceptions, no action may be taken with respect to Entergy New Orleans’s base rates until rates are implemented from a base rate case that must be filed for its electric and gas operations in 2018. This provision eliminated the formula rate plan applicable to Algiers operations. The limited exceptions included continued implementation of the then-remaining two years of the four-year phased-in rate increase for the Algiers area and certain exceptional cost increases or decreases in the base revenue requirement. An additional provision of the settlement agreement allowed for continued recovery of the revenue requirement associated with the capacity and energy from Ninemile 6 received by Entergy New Orleans under a power purchase agreement with Entergy Louisiana (Algiers PPA). The settlement authorized Entergy New Orleans to recover the remaining revenue requirement related to the Algiers PPA through base rates charged to Algiers customers. The settlement also provided for continued implementation of the Algiers MISO recovery rider.

In addition to the Algiers PPA, Entergy New Orleans has a separate power purchase agreement with Entergy Louisiana for 20% of the capacity and energy from Ninemile 6 (Ninemile PPA), which commenced operation in December 2014. Initially, recovery of the non-fuel costs associated with the Ninemile PPA was authorized through a special Ninemile 6 rider billed only to Entergy New Orleans customers outside of Algiers.

In August 2015, Entergy New Orleans filed an application with the City Council seeking authorization to proceed with the purchase of Union Power Block 1, with an expected base purchase price of approximately $237 million, subject to adjustments, and seeking approval of the recovery of the associated costs. In November 2015 the City Council issued written resolutions and an order approving an agreement in principle between Entergy New Orleans and City Council advisors providing that the purchase of Union Power Block 1 and related assets by Entergy New Orleans is prudent and in the public interest. The City Council authorized expansion of the terms of the purchased power and capacity acquisition cost recovery rider to recover the non-fuel purchased power expense from Ninemile 6, the revenue requirement associated with the purchase of Power Block 1 of the Union Power Station, and a credit to customers of $400 thousand monthly beginning June 2016 in recognition of the decrease in other operation and maintenance expenses that would result with the deactivation of Michoud Units 2 and 3. In March 2016, Entergy New Orleans purchased Power Block 1 of the Union Power Station for approximately $237 million and initiated recovery of these costs with March 2016 bills. In July 2016, Entergy New Orleans and the City Council Utility Committee agreed to a temporary increase in the Michoud credit to customers to a total of $1.4 million monthly for August 2016 through December 2016.

A 2008 rate case settlement included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs.  The rate settlement provided an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provided a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs. In January 2015 the City Council approved funding for the Energy Smart program from April 2015 through March 2017 using the remainder of the approximately $12.8 million of 2014 rough production cost equalization funds, with any remaining costs being recovered through the fuel adjustment clause. This funding methodology was modified in November 2015 when the City Council directed Entergy New Orleans to use a combination of guaranteed customer savings related to a prior agreement with the City Council and rough production cost equalization funds to cover program costs prior to recovering any costs through the fuel adjustment clause. In April 2017 the City Council approved an implementation plan for the Energy Smart program from April 2017 through December 2019. The City Council directed that the $11.8 million balance reported for Energy Smart funds be used to continue funding the program for Entergy New Orleans’s legacy customers and that the Energy Smart Algiers program continue to be funded through the Algiers fuel adjustment clause, until additional customer funding is required for the legacy customers. In September 2017, Entergy New Orleans filed a supplemental plan and proposed several options for an interim cost recovery mechanism necessary to recover program costs during the period between when existing funds directed to Energy Smart programs are depleted and when new rates from the 2018 combined rate case, which includes a cost recovery mechanism for Energy Smart funding, take effect (estimated to be August 2019). In December 2017 the City Council approved an energy efficiency cost recovery rider as an interim funding mechanism for Energy Smart, subject to verification that no additional funding sources exist. In June 2018 the City Council also approved a resolution recommending that Entergy New Orleans allocate approximately $13.5 million of benefits resulting from the Tax Act to Energy Smart. Entergy New Orleans is seeking approval of a permanent and stable source of funding for Energy Smart as part of its base rate case filed in September 2018.

In September 2018, Entergy New Orleans filed an electric and gas base rate case with the City Council. The filing requests 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 requests 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 includes a proposed gas rate decrease of $142 thousand. Entergy New Orleans’s rates reflect 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 ending 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’s request for a change in rates is based on the projected twelve months ending December 31, 2018.

The filing’s major provisions include: (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 have recommended, among other things, overall rate reductions of approximately $33 million in electric rates and $3.8 million in gas rates. Certain intervenors have recommended overall rate reductions of up to approximately $49 million in electric rates and $5 million in gas rates. The procedural schedule calls for an evidentiary hearing to be held in June 2019.

Internal Restructuring

In July 2016, Entergy New Orleans filed an application with the City Council seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy New Orleans, Inc. to a new entity, which would ultimately be owned by an existing Entergy subsidiary holding company. In May 2017 the City Council adopted a resolution approving the proposed internal restructuring pursuant to an agreement in principle with the City Council advisors and certain intervenors. Pursuant to the agreement in principle, Entergy New Orleans would credit retail customers $10 million in 2017, $1.4 million in the first quarter of the year after the transaction closes, and $117,500 each month in the second year after the transaction closes until such time as new base rates go into effect as a result of the then-anticipated 2018 base rate case (which has subsequently been filed). Entergy New Orleans began crediting retail customers in June 2017. In June 2017 the FERC approved the transaction and, pursuant to the agreement in principle, Entergy New Orleans will provide additional credits to retail customers of $5 million in each of the years 2018, 2019, and 2020.

In November 2017, Entergy New Orleans undertook a multi-step restructuring, including the following:

• Entergy New Orleans, Inc. redeemed its outstanding preferred stock at a price of approximately $21 million, which included a call premium of approximately $819,000, plus any accumulated and unpaid dividends.

• Entergy New Orleans, Inc. converted from a Louisiana corporation to a Texas corporation.

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

• Entergy New Orleans, Inc. contributed the membership interests in Entergy New Orleans 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 New Orleans Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.

In December 2017, Entergy New Orleans, Inc. changed its name to Entergy Utility Group, Inc., and Entergy New Orleans Power then changed its name to Entergy New Orleans, LLC. Entergy New Orleans, LLC holds substantially all of the assets, and has assumed substantially all of the liabilities, of Entergy New Orleans, Inc. The restructuring was accounted for as a transaction between entities under common control.

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 electricity 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), 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 June 2017, Entergy Texas filed an application to amend its DCRF rider by increasing the total collection from $8.65 million to approximately $19 million. In July 2017, Entergy Texas, the PUCT staff, and the two other parties in the proceeding entered into an unopposed stipulation and settlement agreement resulting in an amended DCRF annual revenue requirement of $18.3 million. In September 2017 the PUCT issued its final order approving the unopposed stipulation and settlement agreement. The amended DCRF rider rates became effective for usage on and after September 1, 2017. DCRF rates were set to zero upon implementation of new base rates on October 17, 2018, as described above in the discussion of the 2018 base rate case.

Transmission Cost Recovery Factor (TCRF) Rider

In September 2015, Entergy Texas filed for a TCRF rider requesting a $13 million increase, incremental to base rates. Testimony was filed in November 2015, with the PUCT staff and other parties proposing various disallowances involving, among other things, MISO charges, vegetation management costs, and bad debt expenses that would reduce the requested increase by approximately $2 million. In addition to those recommended disallowances, a number of parties recommended that Entergy Texas’s request be reduced by an additional $3.4 million to account for load growth since base rates were last set. In February 2016 a State Office of Administrative Hearings ALJ issued a proposal for decision recommending that the PUCT disallow approximately $2 million from Entergy Texas’s $13 million request, but recommending that the PUCT not accept the load growth offset. In June 2016 the PUCT indicated that it would take up in a future rulemaking project the issue of whether a load growth adjustment should apply to a TCRF. In July 2016 the PUCT issued an order generally accepting the proposal for decision but declining to adjust the TCRF baseline in two instances as recommended by the ALJ, which resulted in a total annual allowance of approximately $10.5 million. The PUCT also ordered its staff and Entergy Texas to track all spare autotransformer transfers going forward so that it could address the appropriate accounting treatment and prudence of such transfers in Entergy Texas’s next base rate case. Entergy Texas implemented the TCRF rider beginning with September 2016 bills.

In September 2016, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The proposed amended TCRF rider was designed to collect approximately $29.5 million annually from Entergy Texas’s retail customers. This amount included the approximately $10.5 million annually that Entergy Texas was previously authorized to collect through the TCRF rider, as discussed above. In December 2016, concurrent with the 2016 fuel reconciliation stipulation and settlement agreement discussed above, Entergy Texas and the PUCT staff reached a settlement agreeing to the amended TCRF annual revenue requirement of $29.5 million. As discussed above, the terms of the two settlements are interdependent. The PUCT approved the settlement and issued a final order in March 2017. Entergy Texas implemented the amended TCRF rider beginning with bills covering usage on and after March 20, 2017. TCRF rates were set to zero upon implementation of new base rates on October 17, 2018, as described above in the 2018 base rate case discussion.

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. The proceeding is currently ongoing at the PUCT.

Advanced Metering Infrastructure (AMI) Filings

Entergy Arkansas

In September 2016, Entergy Arkansas filed an application seeking a finding from the APSC that Entergy Arkansas’s deployment of AMI is in the public interest. Entergy Arkansas proposed to replace existing meters with advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Arkansas’s modernized power grid. The filing included an estimate of implementation costs for AMI of $208 million. The filing identified a number of quantified and unquantified benefits, and Entergy Arkansas provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal net benefit to customers of $406 million. Entergy Arkansas also sought to continue to include in rate base the remaining book value of existing meters, which was approximately $57 million at December 31, 2015, that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Arkansas proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Deployment of the communications network began in 2018. Entergy Arkansas proposed to include the AMI deployment costs and the quantified benefits in future formula rate plan filings, and the 2018 costs were approved in the 2017 formula rate plan filing. In August 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement. In October 2017 the APSC issued an order finding that Entergy Arkansas’s AMI deployment is in the public interest and approving the settlement agreement subject to a minor modification. Entergy Arkansas expects to recover the undepreciated balance of its existing meters through a regulatory asset to be amortized over 15 years.

Entergy Louisiana

In November 2016, Entergy Louisiana filed an application seeking a finding from the LPSC that Entergy Louisiana’s deployment of advanced electric and gas metering infrastructure is in the public interest. Entergy Louisiana proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Louisiana’s modernized power grid. The filing included an estimate of implementation costs for AMI of $330 million. The filing identified a number of quantified and unquantified benefits, and Entergy Louisiana provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $607 million. Entergy Louisiana also sought to continue to include in rate base the remaining book value, approximately $92 million at December 31, 2015, of the existing electric meters and also to depreciate those assets using current depreciation rates. Entergy Louisiana proposed a 15-year useful life for the new advanced meters, the three-year deployment of which began in 2019. Deployment of the communications network began in 2018. Entergy Louisiana proposed to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022. The parties reached an uncontested stipulation permitting implementation of Entergy Louisiana’s proposed AMI system, with modifications to the proposed customer charge. In July 2017 the LPSC approved the stipulation. Entergy Louisiana expects to recover the undepreciated balance of its existing meters through a regulatory asset to be amortized at current depreciation rates.

Entergy Mississippi

In November 2016, Entergy Mississippi filed an application seeking an order from the MPSC granting a certificate of public convenience and necessity and finding that Entergy Mississippi’s deployment of AMI is in the public interest. Entergy Mississippi proposed to replace existing meters with advanced meters that enable two-way data communication; to design and build a secure and reliable network to support such communications; and to implement support systems. AMI is intended to serve as the foundation of Entergy Mississippi’s modernized power grid. The filing included an estimate of implementation costs for AMI of $132 million. The filing identified a number of quantified and unquantified benefits, and Entergy Mississippi provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal benefit to customers of $496 million over a 15-year period, which when netted against the costs of AMI results in $183 million of net customer benefits. Entergy Mississippi also sought to continue to include in rate base the remaining book value, approximately $56 million at December 31, 2015, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Mississippi proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019, subject to approval by the MPSC. Deployment of the communications network began in 2018. Entergy Mississippi proposed to include the AMI deployment costs and the quantified benefits in existing rate mechanisms, primarily through future formula rate plan filings and/or future energy cost recovery rider schedule re-determinations, as applicable. In May 2017 the Mississippi Public Utilities Staff and Entergy Mississippi entered into and filed a joint stipulation supporting Entergy Mississippi’s filing, and the MPSC issued an order approving the filing without material changes, finding that Entergy Mississippi’s deployment of AMI is in the public interest and granting a certificate of public convenience and necessity. The MPSC order also confirmed that Entergy Mississippi shall continue to include in rate base the remaining book value of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. In June 2018, as part of the order approving the joint stipulation between the Mississippi Public Utilities Staff and Entergy Mississippi addressing Entergy Mississippi’s 2018 formula rate plan evaluation report and the ratemaking effects of the Tax Act, the MPSC approved the acceleration of the recovery of substantially all of Entergy Mississippi’s existing customer meters in anticipation of AMI deployment.

Entergy New Orleans

In October 2016, Entergy New Orleans filed an application seeking a finding from the City Council that Entergy New Orleans’s deployment of advanced electric and gas metering infrastructure is in the public interest.  Entergy New Orleans proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems.  AMI is intended to serve as the foundation of Entergy New Orleans’s modernized power grid.  The filing included an estimate of implementation costs for AMI of $75 million. The filing identified a number of quantified and unquantified benefits, and Entergy New Orleans provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $101 million.  Entergy New Orleans also sought to continue to include in rate base the remaining book value, approximately $21 million at December 31, 2015, of the existing electric meters and also to depreciate those assets using current depreciation rates.  Entergy New Orleans proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which began in 2019.  Deployment of the information technology infrastructure began in 2017 and deployment of the communications network began in 2018.  Entergy New Orleans proposed to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022.  The City Council’s advisors filed testimony in May 2017 recommending the adoption of AMI subject to certain modifications, including the denial of Entergy New Orleans’s proposed customer charge as a cost recovery mechanism. In January 2018 a settlement was reached between the City Council’s advisors and Entergy New Orleans. In February 2018 the City Council approved the settlement, which deferred cost recovery to the 2018 Entergy New Orleans rate case, but also stated that an adjustment for 2018-2019 AMI costs can be filed in the rate case and that, for all subsequent AMI costs, the mechanism to be approved in the 2018 rate case will allow for the timely recovery of such costs. In April 2018 the City Council adopted a resolution directing Entergy New Orleans to explore the options for accelerating the deployment of AMI. In June 2018 the City Council approved a one-year acceleration of AMI in its service area for an incremental $4.4 million.

Entergy Texas

In April 2017 the Texas legislature enacted legislation that extends statutory support for AMI deployment to Entergy Texas and directs that if Entergy Texas elects to deploy AMI, it shall do so as rapidly as practicable. In July 2017, Entergy Texas filed an application seeking an order from the PUCT approving Entergy Texas’s deployment of AMI. Entergy Texas proposed to replace existing meters with advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Texas’s modernized power grid. The filing included an estimate of implementation costs for AMI of $132 million. The filing identified a number of quantified and unquantified benefits, with Entergy Texas showing that its AMI deployment is expected to produce nominal net operational cost savings to customers of $33 million. Entergy Texas also sought to continue to include in rate base the remaining book value, approximately $41 million at December 31, 2016, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Texas proposed a seven-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Entergy Texas also proposed a surcharge tariff to recover the reasonable and necessary costs it has and will incur under the deployment plan for the full deployment of advanced meters. Further, Entergy Texas sought approval of fees that would be charged to customers who choose to opt out of receiving service through an advanced meter and instead receive electric service with a non-standard meter. In October 2017, Entergy Texas and other parties entered into and filed an unopposed stipulation and settlement agreement, permitting deployment of AMI with limited modifications. The PUCT approved the stipulation and settlement agreement in December 2017. Entergy Texas implemented the AMI surcharge tariff beginning with January 2018 bills. As of December 31, 2018, Entergy Texas has a regulatory liability related to the collection of the surcharge from customers. Consistent with the approval, deployment of the communications network began in 2018 and deployment of the advanced meters will begin in March 2019. Entergy Texas expects to recover the remaining net book value of its existing meters through a regulatory asset to be amortized at current depreciation rates.

System Agreement Cost Equalization Proceedings

Prior to its final termination in 2016, the Utility operating companies historically engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement.  Entergy Arkansas terminated its participation in the System Agreement in December 2013. Entergy Mississippi terminated its participation in the System Agreement in November 2015. The System Agreement terminated with respect to its remaining participants in August 2016.

Although the System Agreement has terminated, certain of the Utility operating companies’ retail regulators continue to pursue litigation involving the System Agreement at the FERC and in federal courts.  The proceedings include challenges to the allocation of costs as defined by the System Agreement and other matters.

In June 2005 the FERC issued a decision in System Agreement litigation that had been commenced by the LPSC, and essentially affirmed its decision in a December 2005 order on rehearing.  The decision included, among other things:

• The FERC’s conclusion that the System Agreement no longer roughly equalized total production costs among the Utility operating companies.

• In order to reach rough production cost equalization, the FERC imposed a bandwidth remedy by which each company’s total annual production costs would have to be within +/- 11% of Entergy System average total annual production costs.

• In calculating the production costs for this purpose under the FERC’s order, output from the Vidalia hydroelectric power plant would not reflect the actual Vidalia price for the year but be priced at that year’s average price paid by Entergy Louisiana for the exchange of electric energy under Service Schedule MSS-3 of the System Agreement, thereby reducing the amount of Vidalia costs reflected in the comparison of the Utility operating companies’ total production costs.

• The remedy ordered by the FERC in 2005 required no refunds and became effective based on calendar year 2006 production costs with the first reallocation payments made in 2007.

The FERC’s decision reallocated total production costs of the Utility operating companies whose relative total production costs expressed as a percentage of Entergy System average production costs are outside an upper or lower bandwidth.  This was accomplished by payments from Utility operating companies whose production costs were more than 11% below Entergy System average production costs to Utility operating companies whose production costs were more than the Entergy System average production cost, with payments going first to those Utility operating companies whose total production costs were farthest above the Entergy System average.

The LPSC, APSC, MPSC, and the Arkansas Electric Energy Consumers appealed the FERC’s December 2005 decision to the United States Court of Appeals for the D.C. Circuit.  Entergy and the City of New Orleans intervened in the various appeals.  The D.C. Circuit issued its decision in April 2008.  The D.C. Circuit concluded that the FERC’s orders had failed to adequately explain both its conclusion that it was prohibited from ordering refunds for the 20-month period from September 13, 2001 - May 2, 2003 and its determination to implement the bandwidth remedy commencing on January 1, 2006, rather than June 1, 2005.  The D.C. Circuit remanded the case to the FERC for further proceedings on those two issues.

In October 2011 the FERC issued an order addressing the D.C. Circuit remand on the two issues.  On the first issue, the FERC concluded that it did have the authority to order refunds, but decided that it would exercise its equitable discretion and not require refunds for the 20-month period from September 13, 2001 - May 2, 2003.  Because the ruling on refunds relied on findings in the interruptible load proceeding, which is discussed in a separate section below, the FERC concluded that this refund ruling will be held in abeyance pending the outcome of the rehearing requests in the interruptible load proceeding.  On the second issue, the FERC reversed its prior decision and ordered that the prospective bandwidth remedy begin on June 1, 2005 (the date of its initial order in the proceeding) rather than January 1, 2006, as it had previously ordered.  Pursuant to the October 2011 order, Entergy was required to calculate bandwidth payments for the period June - December 2005 utilizing the bandwidth formula tariff prescribed by the FERC that was filed in a December 2006 compliance filing and accepted by the FERC in an April 2007 order.  

In March 2015, in light of a December 2014 decision by the D.C. Circuit in the interruptible load proceeding, Entergy filed with the FERC a motion to establish a briefing schedule on refund issues and an initial brief addressing refund issues. The initial brief argued that the FERC, in response to the D.C. Circuit decision, should clarify its policy on refunds and find that refunds are not required in this proceeding. In October 2015 the FERC issued three orders related to the commencement of the remedy on June 1, 2005 and the inclusion of interest for the period June 1, 2005 through December 31, 2005. Specifically, the FERC rejected Entergy’s request for rehearing of its decision to include interest for the seven-month period. The FERC also rejected Entergy’s request for rehearing of the order rejecting the compliance filing with regard to the issue of interest. Finally, the FERC set for hearing and settlement procedures the 2014 compliance filing that included the bandwidth calculation for the seven months June 1, 2005 through December 31, 2005. In setting the compliance filing for hearing, the FERC rejected the APSC’s protest that Entergy Arkansas should not be subject to the filing because Entergy Arkansas would be making the payments during a period following its exit from the System Agreement. In January 2018 the D.C. Circuit affirmed the FERC decision that Entergy Arkansas was subject to the filing.

In December 2011, Entergy filed with the FERC its compliance filing that provided the payments and receipts among the Utility operating companies pursuant to the FERC’s October 2011 order.  The APSC, the LPSC, the PUCT, and other parties intervened in the December 2011 compliance filing proceeding, and the APSC and the LPSC also filed protests. The filing showed the following payments/receipts among the Utility operating companies:

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$156
Entergy Louisiana	($75)
Entergy Mississippi	($33)
Entergy New Orleans	($5)
Entergy Texas	($43)

Entergy Arkansas made its payment in January 2012.  In February 2012, Entergy Arkansas filed for an interim adjustment to its production cost allocation rider requesting that the $156 million be collected from customers over the 22-month period from March 2012 through December 2013.  In March 2012 the APSC issued an order stating that the payment can be recovered from retail customers through the production cost allocation rider, subject to refund.  The LPSC and the APSC requested rehearing of the FERC’s October 2011 order.  

In February 2014 the FERC issued a rehearing order addressing its October 2011 order. The FERC denied the LPSC’s request for rehearing on the issues of whether the bandwidth remedy should be made effective earlier than June 1, 2005, and whether refunds should be ordered for the 20-month refund effective period. The FERC granted the LPSC’s rehearing request on the issue of interest on the bandwidth payments/receipts for the June - December 2005 period, requiring that interest be accrued from June 1, 2006 until the date those bandwidth payments/receipts are made. Also in February 2014 the FERC issued an order rejecting the December 2011 compliance filing that calculated the bandwidth payments/receipts for the June - December 2005 period. The FERC order required a new compliance filing that calculates the bandwidth payments/receipts for the June - December 2005 period based on monthly data for the seven individual months including interest pursuant to the February 2014 rehearing order. Entergy sought rehearing of the February 2014 order with respect to the FERC’s determinations regarding interest. In April 2014 the LPSC filed a petition for review of the FERC’s October 2011 and February 2014 orders with the U.S. Court of Appeals for the D.C. Circuit. In August 2017 the D.C. Circuit issued a decision denying the LPSC’s appeal of the FERC’s October 2011 and February 2014 orders. On the issue of the FERC’s implementation of the prospective remedy as of June 2005 and whether the bandwidth remedy should be extended for an additional 17 months in years 2004-2005, the D.C. Circuit affirmed the FERC’s implementation of the remedy and denied the LPSC’s appeal. On the issue of whether the operating companies should be required to issue refunds for the 20-month period from September 2001 to May 2003, the D.C. Circuit granted the FERC’s request for agency reconsideration and remanded that issue back to the FERC for further proceedings as requested by all parties to the appeal. In response to the D.C. Circuit’s remand, various parties filed briefs with the FERC addressing whether the FERC should require the Utility operating companies to issue refunds for the 20-month refund period from September 2001 to May 2003. The LPSC has argued in favor of such remands and Entergy has opposed the LPSC’s request. The briefing was completed in September 2018 and the matter is pending before the FERC.

In April and May 2014, Entergy filed with the FERC an updated compliance filing that provided the payments and receipts among the Utility operating companies pursuant to the FERC’s February 2014 orders.  The filing showed the following net payments and receipts, including interest, among the Utility operating companies:

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$68
Entergy Louisiana	($10)
Entergy Mississippi	($11)
Entergy New Orleans	$2
Entergy Texas	($49)

These payments were made in May 2014. The LPSC, City Council, and APSC filed protests.

The hearing on the bandwidth calculation for the seven months June 1, 2005 through December 31, 2005 occurred in July 2016. The presiding judge issued an initial decision in November 2016. In the initial decision, the presiding judge agreed with the Utility operating companies’ position that: (1) interest on the bandwidth payments for the 2005 test period should be accrued from June 1, 2006 until the date that the bandwidth payments for that calculation are paid, which is consistent with how the Utility operating companies performed the calculation; and (2) a portion of Entergy Louisiana’s 2001-vintage Louisiana state net operating loss accumulated deferred income tax that results from the Vidalia tax deduction should be excluded from the 2005 test period bandwidth calculation. Various participants filed briefs on exceptions and/or briefs opposing exceptions related to the initial decision, including the LPSC, the APSC, the FERC trial staff, and Entergy Services. In May 2018 the FERC issued an order affirming the initial decision and ordered a comprehensive recalculation of the bandwidth payments/receipts for the seven months June 1, 2005 through December 31, 2005 and a recalculation of the 2006 and 2007 test years as a result of limited revisions. Entergy filed the comprehensive recalculation of the bandwidth payments/receipts for the seven months June 1, 2005 through December 31, 2005 and the 2006 and 2007 test years in July 2018. The filing shows the additional following payments and receipts among the Utility operating companies:

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	($4)
Entergy Louisiana	($23)
Entergy Mississippi	$16
Entergy New Orleans	$5
Entergy Texas	$6

These payments were made in July 2018. In January 2019 the FERC denied the LPSC’s request for rehearing of the May 2018 order.

Rough Production Cost Equalization Rates

Each May from 2007 through 2016 Entergy filed with the FERC the rates to implement the FERC’s orders in the System Agreement proceeding.  These filings showed the following payments/receipts among the Utility operating companies were necessary to achieve rough production cost equalization as defined by the FERC’s orders:

	Payments (Receipts)
	2007			2008			2009			2010			2011			2012			2013			2014
	(In Millions)
Entergy Arkansas		$252			$252			$390			$41			$77			$41			$—			$—
Entergy Louisiana		($211	)		($160	)		($247	)		($22	)		($12	)		($41	)		$—			$—
Entergy Mississippi		($41	)		($20	)		($24	)		($19	)		($40	)		$—			$—			$—
Entergy New Orleans		$—			($7	)		$—			$—			($25	)		$—			($15	)		($15	)
Entergy Texas		($30	)		($65	)		($119	)		$—			$—			$—			$15			$15

The Utility operating companies recorded accounts payable or accounts receivable to reflect the rough production cost equalization payments and receipts required to implement the FERC’s remedy.  When accounts payable were recorded, a corresponding regulatory asset was recorded for the right to collect the payments from customers. When accounts receivable were recorded, a corresponding regulatory liability was recorded for the obligations to pass the receipts on to customers.  No payments were required in 2016 or 2015 to implement the FERC’s remedy based on calendar year 2015 production costs and 2014 production costs, respectively. The System Agreement terminated in August 2016.

The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas.  Entergy Texas recovered its 2013 rough production cost equalization payment over three years beginning April 2014. Entergy Texas included its 2014 rough production cost equalization payment as a component of an interim fuel refund made in 2014. Management believes that any changes in the allocation of production costs resulting from the FERC’s decision and related retail proceedings should result in similar rate changes for retail customers, subject to specific circumstances that have caused trapped costs.

The following rough production cost equalization rate proceedings are still ongoing or were ongoing during the period 2016-2018.

2010 Rate Filing Based on Calendar Year 2009 Production Costs

In May 2010, Entergy filed with the FERC the 2010 rates in accordance with the FERC’s orders in the System Agreement proceeding, and supplemented the filing in September 2010.  Several parties intervened in the proceeding at the FERC, including the LPSC and the City Council, which also filed protests.  In July 2010 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2010, subject to refund.  After an abeyance of the proceeding schedule, a hearing was held in March 2014 and in December 2015 the FERC issued an order. Among other things, the December 2015 order directed Entergy to submit a compliance filing. In January 2016 the LPSC, the APSC, and Entergy filed requests for rehearing of the FERC’s December 2015 order. In February 2016, Entergy submitted the compliance filing ordered in the December 2015 order.  The result of the true-up payments and receipts for the recalculation of production costs resulted in the following payments/receipts among the Utility operating companies:

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$2
Entergy Louisiana	$6
Entergy Mississippi	($4)
Entergy New Orleans	($1)
Entergy Texas	($3)

In September 2016 the FERC accepted the February 2016 compliance filing subject to a further compliance filing made in November 2016. The further compliance filing was required as a result of an order issued in September 2016 ruling on the January 2016 rehearing requests filed by the LPSC, the APSC, and Entergy. In the order addressing the rehearing requests, the FERC granted the LPSC’s rehearing request and directed that interest be calculated on the payment/receipt amounts. The FERC also granted the APSC’s and Entergy’s rehearing request and ordered the removal of both securitized asset accumulated deferred income taxes and contra-securitization accumulated deferred income taxes from the calculation. In November 2016, Entergy submitted its compliance filing in response to the FERC’s order on rehearing. The compliance filing included a revised calculation of the bandwidth true-up payments and receipts based on 2009 test year data and interest calculations. The LPSC protested the interest calculations. In November 2017 the FERC issued an order rejecting the November 2016 compliance filing. The FERC determined that the payments detailed in the November 2016 compliance filing did not include adequate interest for the payments from Entergy Arkansas to Entergy Louisiana because it did not include interest on the principal portion of the payment that was made in February 2016. In December 2017, Entergy recalculated the interest pursuant to the November 2017 order. As a result of the recalculations, Entergy Arkansas owed very minor payments to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.

2011 Rate Filing Based on Calendar Year 2010 Production Costs

In May 2011, Entergy filed with the FERC the 2011 rates in accordance with the FERC’s orders in the System Agreement proceeding.  Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest.  In July 2011 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2011, subject to refund. After an abeyance of the proceeding schedule, in December 2014 the FERC consolidated the 2011 rate filing with the 2012, 2013, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

2012 Rate Filing Based on Calendar Year 2011 Production Costs

In May 2012, Entergy filed with the FERC the 2012 rates in accordance with the FERC’s orders in the System Agreement proceeding.  Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest.  In August 2012 the FERC accepted Entergy’s proposed rates for filing, effective June 2012, subject to refund. After an abeyance of the proceeding schedule, in December 2014 the FERC consolidated the 2012 rate filing with the 2011, 2013, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

2013 Rate Filing Based on Calendar Year 2012 Production Costs

In May 2013, Entergy filed with the FERC the 2013 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest. The City Council intervened and filed comments related to including the outcome of a related FERC proceeding in the 2013 cost equalization calculation. In August 2013 the FERC issued an order accepting the 2013 rates, effective June 1, 2013, subject to refund. After an abeyance of the proceeding schedule, in December 2014 the FERC consolidated the 2013 rate filing with the 2011, 2012, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

2014 Rate Filing Based on Calendar Year 2013 Production Costs

In May 2014, Entergy filed with the FERC the 2014 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest. The City Council intervened and filed comments. In December 2014 the FERC issued an order accepting the 2014 rates, effective June 1, 2014, subject to refund, set the proceeding for hearing procedures, and consolidated the 2014 rate filing with the 2011, 2012, and 2013 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

Consolidated 2011, 2012, 2013, and 2014 Rate Filing Proceedings

As discussed above, in December 2014 the FERC consolidated the 2011, 2012, 2013, and 2014 rate filings for settlement and hearing procedures. In May 2015, Entergy filed direct testimony in the consolidated rate filings and the LPSC filed direct testimony concerning its complaint proceeding that is consolidated with the rate filings, challenging certain components of the pending bandwidth calculations for prior years. Hearings occurred in November 2015, and the ALJ issued an initial decision in July 2016. In the initial decision, the ALJ generally agreed with Entergy’s bandwidth calculations with one exception on the accounting related to the Waterford 3 sale/leaseback. In March 2018 the FERC issued an order affirming the initial decision. In April 2018 the LPSC requested rehearing of the FERC’s March 2018 order affirming the ALJ’s initial decision. Entergy filed in May 2018 the bandwidth true-up payments and receipts for the 2011-2014 rate filings (table does not net to zero due to rounding):

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$3
Entergy Louisiana	$3
Entergy Mississippi	($1)
Entergy New Orleans	$1
Entergy Texas	($5)

These payments were made in May 2018. The LPSC request for rehearing is pending.

Utility Operating Company Termination of System Agreement Participation

Entergy Arkansas and Entergy Mississippi ceased participating in the System Agreement effective December 18, 2013 and November 7, 2015, respectively. Entergy Louisiana, Entergy New Orleans, and Entergy Texas terminated participation in the System Agreement on August 31, 2016, which resulted in the termination of the System Agreement in its entirety pursuant to a settlement agreement approved by the FERC in December 2015.

In December 2013 the FERC set one issue for hearing involving whether and how the benefits associated with settlement with Union Pacific regarding certain coal delivery issues should be allocated among Entergy Arkansas and the other Utility operating companies post-termination of the System Agreement. In December 2014 a FERC ALJ issued an initial decision finding that Entergy Arkansas would realize benefits after December 18, 2013 from the 2008 settlement agreement between Entergy Services, Entergy Arkansas, and Union Pacific, related to certain coal delivery issues. In March 2016 the FERC issued an opinion affirming the December 2014 initial decision with regard to the determination that there were benefits related to the Union Pacific settlement, which were realized post-Entergy Arkansas’s December 2013 withdrawal from the System Agreement, that should be shared with the other Utility operating companies utilizing the methodology proposed by the MPSC and trued-up to actual coal volumes purchased. In May 2016, Entergy made a compliance filing that provided the calculation of Union Pacific settlement benefits utilizing the methodology adopted by the initial decision, trued-up for the actual volumes of coal purchased. The payments were made in May 2016. In August 2016 the FERC issued an order accepting Entergy’s compliance filing. Also in August 2016 the APSC filed a petition for review of the FERC’s March 2016 and August 2016 orders with the U.S. Court of Appeals for the D.C. Circuit. In June 2018 the D.C. Circuit denied the APSC’s petition.

Interruptible Load Proceeding

In April 2007 the U.S. Court of Appeals for the D.C. Circuit issued its opinion in the LPSC’s appeal of the FERC’s March 2004 and April 2005 orders related to the treatment under the System Agreement of the Utility operating companies’ interruptible loads.  In its opinion the D.C. Circuit concluded that the FERC: (1) acted arbitrarily and capriciously by allowing the Utility operating companies to phase-in the effects of the elimination of the interruptible load over a 12-month period of time; (2) failed to adequately explain why refunds could not be ordered under Section 206(c) of the Federal Power Act; and (3) exercised appropriately its discretion to defer addressing the cost of sulfur dioxide allowances until a later time.  The D.C. Circuit remanded the matter to the FERC for a more considered determination on the issue of refunds.  The FERC issued its order on remand in September 2007, in which it directed Entergy to make a compliance filing removing all interruptible load from the computation of peak load responsibility commencing April 1, 2004 and to issue any necessary refunds to reflect this change.  In addition, the order directed the Utility operating companies to make refunds for the period May 1995 through July 1996.  In November 2007 the Utility operating companies filed a refund report describing the refunds to be issued pursuant to the FERC’s orders.  The LPSC filed a protest to the refund report in December 2007.  The refunds were made in October 2008 by the Utility operating companies that owed refunds to the Utility operating companies that were due refunds under the decision.  The APSC and the Utility operating companies appealed the FERC decisions to the D.C. Circuit.

Following the filing of petitioners’ initial briefs, the FERC filed a motion requesting the D.C. Circuit hold the appeal of the FERC’s decisions ordering refunds in the interruptible load proceeding in abeyance and remand the record to the FERC.  The D.C. Circuit granted the FERC’s unopposed motion in June 2009.  In December 2009 the FERC established a paper hearing to determine whether the FERC had the authority and, if so, whether it would be appropriate to order refunds resulting from changes in the treatment of interruptible load in the allocation of capacity costs by the Utility operating companies.  In August 2010 the FERC issued an order stating that it has the authority and refunds are appropriate.  The APSC, the MPSC, and Entergy requested rehearing of the FERC’s decision.  In June 2011 the FERC issued an order granting rehearing in part and denying rehearing in part, in which the FERC determined to invoke its discretion to deny refunds.  The FERC held that in this case where “the Entergy system as a whole collected the proper level of revenue, but, as was later established, incorrectly allocated peak load responsibility among the various Entergy operating companies….the Commission will apply here our usual practice in such cases, invoking our equitable discretion to not order refunds, notwithstanding our authority to do so.”  The LPSC requested rehearing of the FERC’s June 2011 decision.  In July 2011 the refunds made in the fourth quarter 2008 described above were reversed. In October 2011 the FERC issued an “Order Establishing Paper Hearing” inviting parties that oppose refunds to file briefs within 30 days addressing the LPSC’s argument that FERC precedent supports refunds under the circumstances present in this proceeding.  Parties that favor refunds were then invited to file reply briefs within 21 days of the date that the initial briefs were due.  

In March 2013 the FERC issued an order denying the LPSC’s request for rehearing of the FERC’s June 2011 order wherein the FERC concluded it would exercise its discretion and not order refunds in the interruptible load proceeding. Based on its review of the LPSC’s request for rehearing and the briefs filed as part of the paper hearing established in October 2011, the FERC affirmed its earlier ruling and declined to order refunds under the circumstances of the case. In May 2013 the LPSC filed a petition for review with the U.S. Court of Appeals for the D.C. Circuit seeking review of FERC orders in the interruptible load proceeding that concluded that the FERC would exercise its discretion and not order refunds in the proceeding. Oral argument was held on the appeal in the D.C. Circuit in September 2014. In December 2014 the D.C. Circuit issued an order on the LPSC’s appeal and remanded the case back to the FERC. The D.C. Circuit rejected the LPSC’s argument that there is a presumption in favor of refunds, but it held that the FERC had not adequately explained its decision to deny refunds and directed the FERC “to consider the relevant factors and weigh them against one another.” In March 2015, Entergy filed with the FERC an initial brief on remand to address the December 2014 decision by the D.C. Circuit. The initial brief on remand argued that the FERC, in response to the D.C. Circuit decision, should clarify its policy on refunds and find that refunds are not required in the interruptible load proceeding.

In April 2016 the FERC issued an order on remand that addressed the December 2014 decision by the D.C. Circuit in the interruptible load proceeding. The order on remand affirmed the FERC’s denial of refunds for the 15-month refund effective period. The FERC explained and clarified its policies regarding refunds and concluded that the evidence in the record demonstrated that the relevant equitable factors favored not requiring refunds in this case. The FERC also noted that, under Section 206(c) of the Federal Power Act, in a Section 206 proceeding involving two or more electric utility companies of a registered holding company system, the FERC may order refunds only if it determines the refunds would not cause the registered holding company to experience any reduction in revenues resulting from an inability of an electric utility company in the system to recover the resulting increase in costs. The FERC stated it was not able to find that the Entergy system would not experience a reduction in revenues if refunds were awarded in this proceeding, which further supported the denial of refunds. In May 2016 the LPSC filed a request for rehearing of the FERC’s April 2016 order. In September 2016 the FERC issued an order denying the LPSC’s request for rehearing and reaffirming its denial of refunds for the 15-month refund effective period. The LPSC appealed the April and September 2016 orders to the U.S. Court of Appeals for the D.C. Circuit. In March 2018 the D.C. Circuit issued an order denying the LPSC’s appeal and affirming the FERC’s decision that it would be inequitable to award refunds in the proceeding. In April 2018 the LPSC sought rehearing en banc of the D.C. Circuit’s order denying the LPSC’s appeal. In May 2018 the D.C. Circuit denied the LPSC’s rehearing request. In August 2018 the LPSC filed with the Supreme Court of the United States a petition for a writ of certiorari to review the judgment of the D.C. Circuit. In November 2018 the Supreme Court of the United States denied the LPSC’s petition for a writ of certiorari to review the judgment of the D.C. Circuit, effectively terminating the interruptible load proceeding.

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’s 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’s appeal and held all of the appeals in abeyance pending final resolution of the related proceeding before the FERC.

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 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. 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.

Complaints Against System Energy

Return on Equity 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 the FERC to institute 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. System Energy is recording a provision against revenue for the potential outcome of this proceeding. In September 2017 the FERC established a refund effective date of January 23, 2017, consolidated the return on equity complaint with the proceeding described in Unit Power Sales Agreement below, 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 effective date 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 System Energy’s return on equity, with a refund effective date of April 2018. The portion of the LPSC’s complaint dealing with return on equity was subsequently consolidated with the APSC and MPSC complaint for hearing. The consolidated hearing has been scheduled for September 2019, and the parties are required to address 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 complaint, and System Energy submitted a response to the amended complaint in October 2018. In January 2019 the FERC set the amended complaint for settlement and hearing proceedings.

Grand Gulf Sale-leaseback Renewal Complaint

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 2018. The hearing has been scheduled for November 2019.

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 proposed amendments would result in lower charges to the Utility operating companies that buy capacity and energy from System Energy under the Unit Power Sales Agreement. The proposed changes are 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. System Energy requested that the FERC accept the amendments effective October 1, 2017.

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 propose 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. The FERC also consolidated the Unit Power Sales Agreement amendment proceeding with the proceeding described in“Return on Equity Complaints” above, and directed the parties to engage in settlement proceedings before an ALJ. 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.  The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages.  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.

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.  In February 2012, Entergy Louisiana sold 500,000 of its Class A preferred membership units in Entergy Holdings Company LLC, a wholly-owned Entergy subsidiary, to a third party in exchange for $51 million plus accrued but unpaid distributions on the units.  The 500,000 preferred membership units are mandatorily redeemable in January 2112.

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. As of April 30, 2016, Entergy Mississippi’s storm damage provision balance was less than $10 million, therefore Entergy Mississippi resumed billing the monthly storm damage provision effective with June 2016 bills. As of September 30, 2016, however, Entergy Mississippi’s storm damage provision balance exceeded $15 million. Accordingly the storm damage provision was reset to zero beginning with November 2016 bills. As of July 31, 2017, the balance in Entergy Mississippi’s accumulated storm damage provision was again less than $10 million, therefore Entergy Mississippi resumed billing the monthly storm damage provision effective with September 2017 bills. As of June 30, 2018, Entergy Mississippi’s storm damage provision balance exceeded $15 million. Accordingly the storm damage provision was reset to zero beginning with August 2018 bills.

Entergy New Orleans

In August 2012, Hurricane Isaac caused extensive damage to Entergy New Orleans’s service area. In January 2015 the City Council issued a resolution approving the terms of a joint agreement in principle filed by Entergy New Orleans, Entergy Louisiana, and the City Council Advisors determining, among other things, that Entergy New Orleans’s prudently-incurred storm recovery costs were $49.3 million, of which $31.7 million, net of reimbursements from the storm reserve escrow account, remained recoverable from Entergy New Orleans’s electric customers. The resolution also directed Entergy New Orleans to file an application to securitize the unrecovered City Council-approved storm recovery costs of $31.7 million pursuant to the Louisiana Electric Utility Storm Recovery Securitization Act (Louisiana Act 64). In addition, the resolution found that it was reasonable for Entergy New Orleans to include in the principal amount of its potential securitization the costs to fund and replenish Entergy New Orleans’s storm reserve in an amount that achieved the City Council-approved funding level of $75 million. In January 2015, in compliance with that directive, Entergy New Orleans filed with the City Council an application requesting that the City Council grant a financing order authorizing the financing of Entergy New Orleans’s storm costs, storm reserves, and issuance costs pursuant to Louisiana Act 64. In May 2015 the parties entered into an agreement in principle and the City Council issued a financing order authorizing Entergy New Orleans to issue storm recovery bonds in the aggregate amount of $98.7 million, including $31.8 million for recovery of Entergy New Orleans’s Hurricane Isaac storm recovery costs, including carrying costs, $63.9 million to fund and replenish Entergy New Orleans’s storm reserve, and approximately $3 million for estimated up-front financing costs associated with the securitization. See Note 5 to the financial statements for discussion of the issuance of the securitization bonds in July 2015.

New Nuclear Generation Development Costs

Entergy Louisiana

Entergy Louisiana and Entergy Gulf States Louisiana were developing a project option for new nuclear generation at River Bend.  In March 2010, Entergy Louisiana and Entergy Gulf States Louisiana filed with the LPSC seeking approval to continue the limited development activities necessary to preserve an option to construct a new unit at River Bend.  At its June 2012 meeting the LPSC voted to uphold an ALJ recommendation that the request of Entergy Louisiana and Entergy Gulf States Louisiana be declined on the basis that the LPSC’s rule on new nuclear development does not apply to activities to preserve an option to develop and on the further grounds that the companies improperly engaged in advanced preparation activities prior to certification.  The LPSC directed that Entergy Louisiana and Entergy Gulf States Louisiana be permitted to seek recovery of these costs in their upcoming rate case filings that were subsequently filed in February 2013. In the resolution of the rate case proceeding the LPSC provided for an eight-year amortization of costs incurred in connection with the potential development of new nuclear generation at River Bend, without carrying costs, beginning in December 2014, provided, however, that amortization of these costs shall not result in a future rate increase. As of December 31, 2018, Entergy Louisiana has a regulatory asset of $28.5 million on its balance sheet related to these new nuclear generation development costs.

Entergy Louisiana [Member]

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, 2018 and 2017:

Other Regulatory Assets

Entergy

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$2,611.5		$2,642.3
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	814.3		746.0
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 – Storm Cost Recovery Filings with Retail Regulators) (Note 5)	452.7		558.9
Removal costs - recovered through depreciation rates (Note 9)	375.8		436.5
Opportunity Sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding)	116.3		109.8
Unamortized loss on reacquired debt - recovered over term of debt	74.5		82.9
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy)	52.1		73.7
Retail rate deferrals - recovered through rate riders as rates are redetermined by retail regulators	39.0		86.4
New nuclear generation development costs (Note 2 - New Nuclear Generation Development Costs) (b)	29.0		36.4
Transition to competition costs - recovered over a 15-year period through February 2021	26.7		37.7
Other	154.6		125.1
Entergy Total		$4,746.5		$4,935.7

Entergy Arkansas

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$747.2		$757.0
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	381.7		345.2
Removal costs - recovered through depreciation rates (Note 9)	138.3		176.9
Opportunity sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding)	116.3		109.8
Storm damage costs - recovered either through securitization or retail rates (Note 5 - Entergy Arkansas Securitization Bonds)	60.7		76.2
Unamortized loss on reacquired debt - recovered over term of debt	21.2		24.3
Retail rate deferrals - recovered through rate riders as rates are redetermined annually	20.5		28.2
ANO Fukushima and Flood Barrier costs - recovered through retail rates through February 2026 (Note 2 - Retail Rate Proceedings) (b)	12.6		14.4
Other	36.5		35.4
Entergy Arkansas Total		$1,535.0		$1,567.4

Entergy Louisiana

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (a)		$711.8		$724.6
Asset Retirement Obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	232.9		218.6
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy)	49.8		71.4
New nuclear generation development costs - recovery through formula rate plan December 2014 through November 2022 (Note 2 - New Nuclear Generation Development Costs) (b)	28.5		35.8
Unamortized loss on reacquired debt - recovered over term of debt	22.5		24.7
Storm damage costs - recovered through retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)	17.9		14.3
Business combination external costs deferral - recovery through formula rate plan December 2015 through November 2025 (b)	12.4		14.1
River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC)	11.0		12.9
Other	18.3		29.4
Entergy Louisiana Total		$1,105.1		$1,145.8

Entergy Mississippi

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$215.9		$218.7
Removal costs - recovered through depreciation rates (Note 9)	63.5		91.6
Attorney General litigation costs (Note 2 - Mississippi Attorney General Complaint) (b)	23.6		9.3
Retail rate deferrals - recovered through rate riders as rates are redetermined annually	16.6		49.4
Unamortized loss on reacquired debt - recovered over term of debt	16.2		17.6
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a)	7.2		7.6
Other	—		3.7
Entergy Mississippi Total		$343.0		$397.9

Entergy New Orleans

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$96.2		$102.8
Storm damage costs, including hurricane costs - recovered through retail rates and securitization (Note 2 - Storm Cost Recovery Filings with Retail Regulators)	70.4		82.3
Removal costs - recovered through depreciation rates (Note 9)	49.3		44.8
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a)	4.5		4.3
Unamortized loss on reacquired debt - recovered over term of debt	2.6		3.0
Rate case costs - recovered over a 6-year period through September 2021 (Note 2 - Retail Rate Proceedings)	1.9		2.6
Retail rate deferrals - recovered through rate riders as rates are redetermined monthly or annually	—		4.4
Other	4.9		7.2
Entergy New Orleans Total		$229.8		$251.4

Entergy Texas

	2018		2017
	(In Millions)
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 5 - Entergy Texas Securitization Bonds)		$303.6		$386.1
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)	171.8		169.2
Removal costs - recovered through depreciation rates (Note 9)	50.9		55.2
Transition to competition costs - recovered over a 15-year period through February 2021	26.7		37.7
Neches and Sabine costs - recovered over a ten-year period through September 2028 (Note 2 - Retail Rate Proceedings) (b)	23.6		—
Unamortized loss on reacquired debt - recovered over term of debt	8.2		8.7
Other	13.2		4.5
Entergy Texas Total		$598.0		$661.4

System Energy

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Other Postretirement Benefits) (a)		$179.3		$202.7
Asset retirement obligation - recovery dependent upon timing of decommissioning (Note 9) (a)	186.9		169.1
Removal costs - recovered through depreciation rates (Note 9)	76.4		67.9
Unamortized loss on reacquired debt - recovered over term of debt	3.8		4.6
System Energy Total		$446.4		$444.3

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

(b) Does not earn a return on investment.

Other Regulatory Liabilities

Entergy

	2018		2017
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)		$815.9		$989.3
Vidalia purchased power agreement (Note 8) (b)	139.7		151.6
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) (b)	111.1		124.8
Income tax rate change - returned to electric and gas customers through retail rates (Note 2 - Retail Rate Proceedings)	74.7		—
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions)	67.9		67.9
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination)	50.8		65.8
Grand Gulf over-recovery - will be refunded through rate riders as rates are redetermined annually	48.6		—
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)	44.4		—
Internal restructuring guaranteed customer credits (Note 2 - Retail Rate Proceedings)	39.6		—
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)	39.1		36.7
Excess decommissioning recovery for Willow Glen - (Note 14 - Dispositions)	31.9		—
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement	25.0		32.1
Removal costs - returned to customers through depreciation rates (Note 9)	18.8		32.4
Other	68.4		43.5
Entergy Total		$1,620.3		$1,588.5

Entergy Arkansas

	2018		2017
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)		$297.2		$354.0
Internal restructuring guaranteed customer credits (Note 2 - Retail Rate Proceedings)	39.6		—
Future formula rate plan revenue reductions (Note 2 - Retail Rate Proceedings)	35.1		—
Grand Gulf over-recovery - will be refunded through rate riders as rates are redetermined annually	26.0		—
Other	4.8		9.6
Entergy Arkansas Total		$402.7		$363.6

Entergy Louisiana

	2018		2017
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)		$274.1		$323.7
Vidalia purchased power agreement (Note 8) (b)	139.7		151.6
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) (b)	111.1		124.8
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination)	50.8		65.8
Income tax rate change - returned to electric customers through retail rates September 2018 through August 2019 (Note 2 - Retail Rate Proceedings)	49.9		—
Asset Retirement Obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)	39.1		36.7
Excess decommissioning recovery for Willow Glen - (Note 14 - Dispositions)	31.9		—
Removal costs - returned to customers through depreciation rates (Note 9)	18.8		32.4
Other	33.4		26.1
Entergy Louisiana Total		$748.8		$761.1

Entergy Mississippi

	2018		2017
	(In Millions)
Grand Gulf Over-Recovery - returned to customers through rate riders when rates are redetermined annually		$22.6		$—
Future formula rate plan revenue reductions (Note 2 - Retail Rate Proceedings)	9.3		—
Other	1.7		0.9
Entergy Mississippi Total		$33.6		$0.9

Entergy Texas

	2018		2017
	(In Millions)
Income tax rate change - refunded through a rate rider (Note 2 - Retail Rate Proceedings)		$23.1		$—
Advanced metering system surcharge (Note 2 - Advanced Metering Infrastructure (AMI) Filings)	16.5		—
Transition to competition costs - returned to customers through rate riders when rates are redetermined periodically	4.2		4.8
Other	4.1		2.1
Entergy Texas Total		$47.9		$6.9

System Energy

	2018		2017
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 17) (a)		$244.6		$311.6
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions)	67.9		67.9
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
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement	25.0		32.1
System Energy Total		$381.9		$456.0

(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 $25.0 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 will be 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 to be 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 existing formula rate plan rider for its customers to realize the remaining benefits of the Tax Act. Entergy Arkansas’s formula rate plan rider includes a netting adjustment that compares 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.

Entergy Louisiana

In a 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 will be 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. Entergy Mississippi’s formula rate plan includes a look-back evaluation report filing in March 2019 that will compare actual 2018 results to the allowed return on rate base. The stipulation approved in June 2018 provides 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 any true-up to be 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. In November 2018, Entergy Mississippi’s annual redetermination of the annual factor to be applied under the power management rider included an insignificant true-up to the amount of unprotected excess accumulated deferred income taxes. In January 2019 the MPSC approved the proposed power management cost factor effective for February 2019 bills.

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. In both a memorandum issued prior to the open meeting when the order was discussed and during the discussions at the open meeting regarding the order, the PUCT indicated that it would consider utility earnings in determining the treatment of the liability and the effects of the Tax Act. 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. Entergy Texas also stated that it would be inappropriate for the PUCT to require a refund of the reduction in income tax expense in 2018 resulting from the Act on a retroactive basis and without a comprehensive review of Entergy Texas’s cost of service and earned return on equity.

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 will 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 will 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 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 larger customers and over a period of four years for other customers.

System Energy

In a filing made with the FERC in March 2018, Entergy proposed revisions to the Unit Power Sales Agreement, among other agreements, to reflect the effects of the Tax Act. In the filing System Energy proposed to return all of its 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 are ongoing.

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, 2018 and 2017 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.

	2018			2017
	(In Millions)
Entergy Arkansas (a)		$86.5			$130.4
Entergy Louisiana (b)		$136.7			$96.7
Entergy Mississippi		$8.0			$32.4
Entergy New Orleans (b)		$2.8			($3.7	)
Entergy Texas		($19.7	)		($67.3	)

(a) Includes $67.3 million in 2018 and $67.1 million in 2017 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

Production Cost Allocation Rider

The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings, which are discussed in the “System Agreement Cost Equalization Proceedings” section below.

In May 2016, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected recovery of the production cost allocation rider true-up adjustment of the 2014 and 2015 unrecovered retail balance in the amount of $1.9 million. Additionally, the redetermined rates reflected the recovery of a $1.9 million System Agreement bandwidth remedy payment resulting from a compliance filing pursuant to the FERC’s December 2015 order related to test year 2009 production costs. The rates for the 2016 production cost allocation rider update were effective July 2016 through June 2017.

In May 2017, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected a credit amount of $0.3 million resulting from a compliance filing pursuant to the FERC’s September 2016 order. Additionally, the redetermined rate reflected recovery of the production cost allocation rider true-up adjustment of the 2016 unrecovered retail balance in the amount of $0.3 million. Because of the small effect of the 2017 production cost allocation rider update, Entergy Arkansas proposed to reduce the effective period of the update to one month, July 2017. After the one month collection period, rates were set to zero for all rate classes for the period August 2017 through June 2018.

In May 2018, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected recovery of the 2017 under-recovered retail balance and a $2.8 million payment by Entergy Arkansas associated with a compliance filing pursuant to a March 2018 FERC order related to 2010 production costs. The rates for the 2018 production cost allocation rider update are effective July 2018 through June 2019.

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.

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 December 2011 the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates.  The audit included a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 2005 through 2009.  In March 2016 the LPSC staff consultant issued its audit report. In its report, the LPSC staff consultant recommended that Entergy Louisiana refund approximately $8.6 million, plus interest, to customers and realign the recovery of approximately $12.7 million from Entergy Gulf States Louisiana’s fuel adjustment clause to base rates. In September 2016 the LPSC staff filed testimony stating that it was no longer recommending a disallowance of $3.4 million of the $8.6 million discussed above, but otherwise maintained the positions from its report. Subsequently, the parties entered into a settlement, which was approved by the LPSC in November 2016. The settlement recognized the dry cask storage recovery method issue, which was addressed in the separate proceeding approved by the LPSC in October 2017, provided for a refund of $5 million, which was made to legacy Entergy Gulf States Louisiana customers in December 2016, and resolved all other issues raised in the audit.

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 is evaluating the staff’s recommended disallowance.

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 consultant issued its audit report. In its report, the LPSC staff consultant recommended 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 is evaluating the staff’s recommended disallowance.

In June 2016 the LPSC staff provided notice of audits of Entergy Louisiana’s fuel adjustment clause filings and purchased gas adjustment clause filings. In recognition of the business combination that occurred in 2015, the audit notice was issued to Entergy Louisiana and will also include a review of charges to legacy Entergy Gulf States Louisiana customers prior to the business combination. The audit includes 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. Discovery commenced in March 2017. No report of audit has been issued.

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.  Discovery commenced in September 2018.  No report of audit has been issued.

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 November 2015, 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 a projected over-recovery balance of $48 million projected through January 31, 2016. In January 2016 the MPSC approved the redetermined annual factor effective February 1, 2016. The MPSC further ordered, however, that due to the significant change in natural gas price forecasts since Entergy Mississippi’s filing in November 2015 Entergy Mississippi should file a revised fuel factor with the MPSC no later than February 1, 2016. Pursuant to that order, Entergy Mississippi submitted a revised fuel factor. Additionally, because Entergy Mississippi’s projected over-recovery balance for the period ending January 31, 2016 was $68 million, in February 2016, Entergy Mississippi filed for another interim adjustment to the energy cost factor effective April 2016 to flow through to customers the projected over-recovery balance over a six-month period. That interim adjustment was approved by the MPSC in February 2016 effective for April 2016 bills.

In November 2016, 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 less than $2 million as of September 30, 2016. In January 2017 the MPSC approved the annual factor effective with February 2017 bills. Also 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 its order, the MPSC expressly reserved the right to review and determine the recoverability of any and all purchased power expenditures made during fiscal year 2016. The MPSC hired independent auditors to conduct an annual operations audit and a financial audit. The independent auditors issued their audit reports in December 2017. The audit reports included several recommendations for action by Entergy Mississippi but did not recommend any cost disallowances. In January 2018 the MPSC certified the audit reports to the Mississippi Legislature. In November 2017 the Public Utilities Staff separately engaged a consultant to review the outage at the Grand Gulf Nuclear Station that began in 2016. The review is currently in progress.

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. Entergy Mississippi proposed a two-tiered energy cost factor designed to promote overall rate stability throughout 2018 particularly during the summer months. 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.

Mississippi Attorney General Complaint

The Mississippi Attorney General filed a complaint in state court in December 2008 against Entergy Corporation, Entergy Mississippi, Entergy Services, and Entergy Power alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution.  The complaint is wide ranging and relates to tariffs and procedures under which Entergy Mississippi purchases power not generated in Mississippi to meet electricity demand.  Entergy believes the complaint is unfounded.  In December 2008 the defendant Entergy companies removed the Attorney General’s lawsuit to U.S. District Court in Jackson, Mississippi. In June 2010 the MPSC authorized the deferral of certain legal expenses associated with this litigation until it is resolved. As of December 31, 2018, Entergy Mississippi has a regulatory asset of $23.6 million for these deferred legal expenses. Pre-trial and settlement conferences were held in October 2018. In October 2018 the District Court rescheduled the trial to April 2019.

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 July 2015 certain parties filed briefs in a PUCT proceeding asserting that Entergy Texas should refund to retail customers an additional $10.9 million in bandwidth remedy payments Entergy Texas received related to calendar year 2006 production costs.  In October 2015 an ALJ issued a proposal for decision recommending that the additional bandwidth remedy payments be refunded to retail customers. In January 2016 the PUCT issued its order affirming the ALJ’s recommendation, and Entergy Texas filed a motion for rehearing of the PUCT’s decision, which the PUCT denied. In March 2016, Entergy Texas filed a complaint in Federal District Court for the Western District of Texas and a petition in the Travis County (State) District Court appealing the PUCT’s decision. The pending appeals did not stay the PUCT’s decision. In April 2016, Entergy Texas filed with the PUCT an application to refund to customers approximately $56.2 million. The refund resulted from (i) $41.8 million of fuel cost recovery over-collections through February 2016, (ii) the $10.9 million in bandwidth remedy payments, discussed above, that Entergy Texas received related to calendar year 2006 production costs, and (iii) $3.5 million in bandwidth remedy payments that Entergy Texas received related to 2006-2008 production costs. In June 2016, Entergy Texas filed an unopposed settlement agreement that added additional over-recovered fuel costs for the months of March and April 2016. The settlement resulted in a $68 million refund. The ALJ approved the refund on an interim basis and it was made to most customers over a four-month period beginning with the first billing cycle of July 2016. In July 2016 the PUCT issued an order approving the interim refund. The federal appeal of the PUCT’s January 2016 decision was heard in December 2016, and the Federal District Court granted Entergy Texas’s requested relief. In January 2017 the PUCT and an intervenor filed petitions for appeal of the Federal District Court ruling to the U.S. Court of Appeals for the Fifth Circuit. Oral argument was held before the Fifth Circuit in February 2018. In April 2018 the Fifth Circuit reversed the decision of the Federal District Court, reinstating the original PUCT decision. In October 2018, Entergy Texas filed notice of nonsuit in its appeal to the Travis County District Court regarding the PUCT’s January 2016 decision.

In July 2016, Entergy Texas filed an application to reconcile its fuel and purchased power costs for the period April 1, 2013 through March 31, 2016. During the reconciliation period, Entergy Texas incurred approximately $1.77 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 over-recovery balance of approximately $19.3 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning April 2016. Entergy Texas also noted, however, that the estimated $19.3 million over collection was being refunded to customers as a portion of the interim fuel refund beginning with the first billing cycle of July 2016, discussed above. Entergy Texas also requested a prudence finding for each of the fuel-related contracts and arrangements entered into or modified during the reconciliation period that have not been reviewed by the PUCT in a prior proceeding. In December 2016, Entergy Texas entered into a stipulation and settlement agreement resulting in a $6 million disallowance not associated with any particular issue raised and a refund of the over-recovery balance of $21 million as of November 30, 2016, to most customers beginning April 2017 through June 2017. This settlement was developed concurrently with the stipulation and settlement agreement in the 2016 transmission cost recovery factor rider amendment discussed below, and the terms and conditions in both settlements are interdependent. The fuel reconciliation settlement was approved by the PUCT in March 2017 and the refunds were made.

In June 2017, Entergy Texas filed an application for a fuel refund of approximately $30.7 million for the months of December 2016 through April 2017. For most customers, the refunds flowed through bills for the months of July 2017 through September 2017. The fuel refund was approved by the PUCT in August 2017.

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.

Retail Rate Proceedings

Filings with the APSC (Entergy Arkansas)

Retail Rates

2015 Base Rate Filing

In April 2015, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. The filing notified the APSC of Entergy Arkansas’s intent to implement a forward test year formula rate plan pursuant to Arkansas legislation passed in 2015, and requested a retail rate increase of $268.4 million, with a net increase in revenue of $167 million. The filing requested a 10.2% return on common equity. In December 2015, Entergy Arkansas, the APSC staff, and certain of the intervenors in the rate case filed with the APSC a joint motion for approval of a settlement of the case that proposed a retail rate increase of approximately $225 million with a net increase in revenue of approximately $133 million; an authorized return on common equity of 9.75%; and a formula rate plan tariff that provides a +/- 50 basis point band around the 9.75% allowed return on common equity. A significant portion of the rate increase is related to Entergy Arkansas’s acquisition in March 2016 of Union Power Station Power Block 2 for a base purchase price of $237 million. The settlement agreement also provided for amortization over a 10-year period of $7.7 million of previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance. In February 2016 the APSC approved the settlement with one exception that reduced the retail rate increase proposed in the settlement by $5 million. The settling parties agreed to the APSC modifications in February 2016. The new rates were effective February 24, 2016 and began billing with the first billing cycle of April 2016. In March 2016, Entergy Arkansas made a compliance filing regarding the new rates that included an interim base rate adjustment surcharge, effective with the first billing cycle of April 2016, to recover the incremental revenue requirement for the period February 24, 2016 through March 31, 2016. The interim base rate adjustment surcharge was designed to recover a total of $21.1 million over the nine-month period from April 2016 through December 2016.

2016 Formula Rate Plan Filing

In July 2016, Entergy Arkansas filed with the APSC its 2016 formula rate plan filing showing Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2017 test period to be below the formula rate plan bandwidth. The filing requested a $67.7 million revenue requirement increase to achieve Entergy Arkansas’s target earned return on common equity of 9.75%. In October 2016, Entergy Arkansas filed with the APSC revised formula rate plan attachments with an updated request for a $54.4 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors, as well as three additional adjustments identified as appropriate by Entergy Arkansas. In November 2016 a hearing was held and the APSC issued an order directing the parties to brief certain issues. In December 2016 the APSC approved a settlement agreement and the $54.4 million revenue requirement increase with approximately $25 million of the $54.4 million revenue requirement subject to possible future adjustment and refund to customers with interest. The APSC requested supplemental information for some of Entergy Arkansas’s requested nuclear expenditures. In December 2016 the APSC approved Entergy Arkansas’s formula rate plan compliance tariff, and the rates became effective with the first billing cycle of January 2017. In April 2017, Entergy Arkansas filed a motion consented to by all parties requesting that it be permitted to submit the supplemental information requested by the APSC in conjunction with its 2017 formula rate plan filing, which was subsequently made in July 2017 and is discussed below. In May 2017 the APSC approved the joint motion and proposal to review Entergy Arkansas’s supplemental information on a concurrent schedule with the 2017 formula rate plan filing. In October 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement resolving all issues in the proceeding and providing for recovery of the 2017 and 2018 nuclear costs. In December 2017 the APSC approved the settlement agreement and recovery of the 2017 and 2018 nuclear costs.

2017 Formula Rate Plan Filing

In July 2017, Entergy Arkansas filed with the APSC its 2017 formula rate plan filing showing Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2018 test period to be below the formula rate plan bandwidth.  The filing projected a $129.7 million revenue requirement increase to achieve Entergy Arkansas’s target earned return on common equity of 9.75%.  Entergy Arkansas’s formula rate plan is subject to a four percent annual revenue constraint and the projected annual revenue requirement increase exceeded the four percent, resulting in a proposed increase for the 2017 formula rate plan of $70.9 million. In October 2017, Entergy Arkansas filed with the APSC revised formula rate plan attachments that projected a $126.2 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors. The revised formula rate plan filing included a proposed $71.1 million revenue requirement increase based on a revision to the four percent constraint calculation. In October 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement resolving all issues in the proceeding and providing for recovery of the 2017 and 2018 nuclear costs. In December 2017 the APSC approved the settlement agreement and the $71.1 million revenue requirement increase, as well as Entergy Arkansas’s formula rate plan compliance tariff, and the rates became effective with the first billing cycle of January 2018.

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 shows 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 includes 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 includes a projected $73.4 millionrevenue 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 exceeds the constraint, the resulting increase is 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, which included additional actual revenues for 2018. 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 certain 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. An additional schedule was issued by the APSC for briefing other contested issues, the outcome of which did not affect the 2018 filing but could affect future Entergy Arkansas formula rate plan filings. That briefing was completed in February 2019, and the APSC has not indicated when a decision on those issues can be expected.

Similar to the 2018 filing, the formula rate plan filing that will be made in 2019 to set the formula rates for the 2020 calendar year will include a netting adjustment that will compare projected costs and sales for 2018 that were approved in the 2017 formula rate plan filing to actual 2018 costs and sales data. In the fourth quarter 2018, Entergy Arkansas recorded a provision of $35.1 million that reflects the estimate of the historical year netting adjustment that will be included in the 2019 filing to reflect the change in formula rate plan revenues associated with actual 2018 results when compared to the allowed rate of return on equity. 

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. Entergy Arkansas also filed a notice with the Missouri Public Service Commission in December 2017 out of an abundance of caution, although Entergy Arkansas does not serve any retail customers in Missouri. In April 2018 the Missouri Public Service Commission approved Entergy Arkansas’s filing. 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

2015 Formula Rate Plan Filing

In May 2016, Entergy Louisiana filed its formula rate plan evaluation report for its 2015 calendar year operations. The evaluation report reflected an earned return on common equity of 9.07%. As such, no adjustment to base formula rate plan revenue was required. The following other adjustments, however, were required under the formula rate plan: an increase in the legacy Entergy Louisiana additional capacity mechanism of $14.2 million; a separate increase in legacy Entergy Louisiana revenue of $10 million primarily to reflect the effects of the termination of the System Agreement; an increase in the legacy Entergy Gulf States Louisiana additional capacity mechanism of $0.5 million; a decrease in legacy Entergy Gulf States Louisiana revenue of $58.7 million primarily to reflect the effects of the termination of the System Agreement; and an increase of $11 million to the MISO cost recovery mechanism. Rates were implemented with the first billing cycle of September 2016, subject to refund. Following implementation of the as-filed rates in September 2016, there were several interim updates to Entergy Louisiana’s formula rate plan, including the one submitted in December 2016, reflecting implementation of the settlement of the Waterford 3 replacement steam generator project prudence review described below. In June 2017 the LPSC staff and Entergy Louisiana filed a joint report of proceedings, which was accepted by the LPSC in June 2017, finalizing the results of the May 2016 evaluation report, interim updates, and corresponding proceedings with no changes to rates already implemented.

2016 Formula Rate Plan Filing

In May 2017, Entergy Louisiana filed its formula rate plan evaluation report for its 2016 calendar year operations. The evaluation report reflected an earned return on common equity of 9.84%. As such, no adjustment to base formula rate plan revenue was required. Adjustments, however, were required under the formula rate plan; the 2016 formula rate plan evaluation report showed a decrease in formula rate plan revenue of approximately $16.9 million, comprised of a decrease in legacy Entergy Louisiana formula rate plan revenue of $3.5 million, a decrease in legacy Entergy Gulf States Louisiana formula rate plan revenue of $9.7 million, and a decrease in incremental formula rate plan revenue of $3.7 million. Additionally, the formula rate plan evaluation report called for a decrease of $40.5 million in the MISO cost recovery revenue requirement from $46.8 million to $6.3 million. Rates reflecting these adjustments were implemented with the first billing cycle of September 2017, subject to refund. In September 2017 the LPSC issued its report indicating that no changes to Entergy Louisiana’s original formula rate plan evaluation report were required but reserved for several issues, including Entergy Louisiana’s September 2017 update to its formula rate plan evaluation report.  In July 2018, Entergy Louisiana and the LPSC staff filed an unopposed joint report setting forth a correction to the annualization calculation, the effect of which was a net $3.5 million revenue requirement reduction and indicating that there are no outstanding issues with the 2016 formula rate plan report, the supplemental report, or the interim updates.  In September 2018 the LPSC approved the unopposed joint report.

Formula Rate Plan Extension Through 2019 Test Year

In August 2017, Entergy Louisiana filed a request with the LPSC seeking to extend its formula rate plan for three years (2017-2019) with limited modifications of its terms.  Those modifications include: a one-time resetting of base rates to the midpoint of the band at Entergy Louisiana’s authorized return on equity of 9.95% for the 2017 test year; narrowing of the formula rate plan bandwidth from a total of 160 basis points to 80 basis points; and a forward-looking mechanism that would allow Entergy Louisiana to recover certain transmission-related costs contemporaneously with when those projects begin delivering benefits to customers.  In April 2018 the LPSC approved an unopposed joint motion filed by Entergy Louisiana and the LPSC staff that settled the matter. The settlement extended the formula rate plan for three years, providing for rates through at least August 2021. In addition to retaining the major features of the traditional formula rate plan, substantive features of the extended formula rate plan include:

• a mid-point reset of formula rate plan revenues to a 9.95% earned return on common equity for the 2017 test year and for the St. Charles Power Station when it enters commercial operation;

• a 9.8% target earned return on common equity for the 2018 and 2019 test years;

• narrowing of the common equity bandwidth to plus or minus 60 basis points around the target earned return on common equity;

• a cap on potential revenue increase of $35 million for the 2018 evaluation period, and $70 million for the cumulative 2018 and 2019 evaluation periods, on formula rate plan cost of service rate increases (the cap excludes rate changes associated with the transmission recovery mechanism described below and rate changes associated with additional capacity);

• a framework for the flow back of certain tax benefits created by the Tax Act to customers, as described in “Regulatory activity regarding the Tax Cuts and Jobs Act” above; and

• a transmission recovery mechanism providing for the opportunity to recover certain transmission-related expenditures in excess of $100 million annually for projects placed in service up to one month prior to rate change outside of sharing that is designed to operate in a fashion similar to the additional capacity mechanism.

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.

Waterford 3 Replacement Steam Generator Project

Following the completion of the Waterford 3 replacement steam generator project, the LPSC undertook a prudence review in connection with a filing made by Entergy Louisiana in April 2013 with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs. In July 2014 the LPSC staff filed testimony recommending potential project and replacement power cost disallowances of up to $71 million, citing a need for further explanation or documentation from Entergy Louisiana.  An intervenor filed testimony recommending disallowance of $141 million of incremental project costs, claiming the steam generator fabricator was imprudent.  Entergy Louisiana provided further documentation and explanation requested by the LPSC staff. An evidentiary hearing was held in December 2014. Entergy Louisiana believed that the replacement steam generator costs were prudently incurred and applicable legal principles supported their recovery in rates.  Nevertheless, Entergy Louisiana recorded a write-off of $16 million of Waterford 3’s plant balance in December 2014 because of the uncertainty at the time associated with the resolution of the prudence review. In December 2015 the ALJ issued a proposed recommendation, which was subsequently finalized, concluding that Entergy Louisiana prudently managed the Waterford 3 replacement steam generator project, including the selection, use, and oversight of contractors, and could not reasonably have anticipated the damage to the steam generators. Nevertheless, the ALJ concluded that Entergy Louisiana was liable for the conduct of its contractor and subcontractor and, therefore, recommended a disallowance of $67 million in capital costs. Additionally, the ALJ concluded that Entergy Louisiana did not sufficiently justify the incurrence of $2 million in replacement power costs during the replacement outage. Although the ALJ’s recommendation had not yet been considered by the LPSC, after considering the progress of the proceeding in light of the ALJ recommendation, Entergy Louisiana recorded in the fourth quarter 2015 approximately $77 million in charges, including a $45 million asset write-off and a $32 million regulatory charge, to reflect that a portion of the assets associated with the Waterford 3 replacement steam generator project was no longer probable of recovery. Entergy Louisiana maintained that the ALJ’s recommendation contained significant factual and legal errors.

In October 2016 the parties reached a settlement in this matter. The settlement was approved by the LPSC in December 2016. The settlement effectively provided for an agreed-upon disallowance of $67 million of plant, which had been previously written off by Entergy Louisiana, as discussed above. The refund to customers of approximately $71 million as a result of the settlement approved by the LPSC was made to customers in January 2017. Of the $71 million of refunds, $68 million was credited to customers through Entergy Louisiana’s formula rate plan, outside of sharing, and $3 million through its fuel adjustment clause. Entergy Louisiana had previously recorded a provision of $48 million for this refund. The previously-recorded provision included the cumulative revenues recorded through December 2016 related to the $67 million of disallowed plant. An additional regulatory charge of $23 million was recorded in fourth quarter 2016 to reflect the effects of the settlement. The settlement also provided that Entergy Louisiana could retain the value associated with potential service credits agreed to by the project contractor, to the extent they are realized in the future. Following a review by the parties, an unopposed joint report of proceedings was filed by the LPSC staff and Entergy Louisiana in May 2017 and the LPSC accepted the joint report of proceedings resolving the matter.

Union Power Station and Deactivation or Retirement Decisions for Entergy Louisiana Plants

In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC for approval of the acquisition and cost recovery of two power blocks of the Union Power Station for an expected base purchase price of approximately $237 million per power block, subject to adjustments. In September 2015, Entergy Gulf States Louisiana agreed to settlement terms with all parties for Entergy Gulf States Louisiana’s purchase of the two power blocks. In October 2015 the LPSC voted unanimously to approve the uncontested settlement which finds, among other things, that acquisition of Power Blocks 3 and 4 is in the public interest and, therefore, prudent. The business combination of Entergy Gulf States Louisiana and Entergy Louisiana received regulatory approval and closed in October 2015 making Entergy Louisiana the named purchaser of Power Blocks 3 and 4 of the Union Power Station. In March 2016, Entergy Louisiana acquired Power Blocks 3 and 4 of Union Power Station for an aggregate purchase price of approximately $475 million and implemented rates to collect the estimated first-year revenue requirement with the first billing cycle of March 2016.

As a term of the LPSC-approved settlement authorizing the purchase of Power Blocks 3 and 4 of the Union Power Station, Entergy Louisiana agreed to make a filing with the LPSC to review its decisions to deactivate Ninemile 3 and Willow Glen 2 and 4 and its decision to retire Little Gypsy 1.  In January 2016, Entergy Louisiana made its compliance filing with the LPSC. Entergy Louisiana, LPSC staff, and intervenors participated in a technical conference in March 2016 where Entergy Louisiana presented information on its deactivation/retirement decisions for these four units in addition to information on the current deactivation decisions for the ten-year planning horizon. Parties requested further proceedings on the prudence of the decision to deactivate Willow Glen 2 and 4.  No party contested the prudence of the decision to deactivate Willow Glen 2 and 4 or suggested reactivation of these units; however, issues were raised related to Entergy Louisiana’s decision to give up its transmission service rights in MISO for Willow Glen 2 and 4 rather than placing the units into suspended status for the three-year term permitted by MISO. In March 2018 the LPSC adopted the ALJ’s recommended order finding that Entergy Louisiana did not demonstrate that its decision to permanently surrender transmission rights for the mothballed (not retired) Willow Glen 2 and 4 units was reasonable and that Entergy Louisiana should hold customers harmless from increased transmission expenses should those units be reactivated. Because no party or the LPSC suggested that Willow Glen 2 and 4 should be reactivated and because the cost to return those units to service far exceeded the revenue the units were expected to generate in MISO, Entergy Louisiana retired Willow Glen 2 and 4 in March 2018. Entergy Louisiana submitted a compliance filing regarding retirement of Willow Glen 2 and 4, and the LPSC closed the proceeding.

Retail Rates - Gas

2016 Rate Stabilization Plan Filing

In January 2017, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2016. The filing of the evaluation report for test year 2016 reflected an earned return on common equity of 6.37%. In April 2017 the LPSC approved a joint report of proceedings and Entergy Louisiana submitted a revised evaluation report reflecting a $1.2 million annual increase in revenue with rates implemented with the first billing cycle of May 2017.

2017 Rate Stabilization Plan Filing

In January 2018, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2017.  The filing of the evaluation report for the test year 2017 reflected an earned return on common equity of 9.06%.  This earned return is below the earnings sharing band of the rate stabilization plan and results in a rate increase of $0.1 million.  Due to the enactment in late-December 2017 of the Tax Cuts and Jobs Act, Entergy Louisiana did not have adequate time to reflect the effects of this tax legislation in the rate stabilization plan.  In April 2018, Entergy Louisiana filed a supplemental evaluation report for the test year ended September 2017, reflecting the effects of the Tax Act, including a proposal to use the unprotected excess accumulated deferred income taxes to offset approximately $1.4 million of storm restoration deferred operation and maintenance costs incurred by Entergy Louisiana in connection with the August 2016 flooding disaster in its gas service area. The supplemental filing reflects an earned return on common equity of 10.79%. As-filed rates from the supplemental filing were implemented, subject to refund, with customers receiving a cost reduction of approximately $0.7 million effective with bills rendered on and after the first billing cycle of May 2018, as well as a $0.2 million reduction in the gas infrastructure rider effective with bills rendered on and after the first billing cycle of July 2018. The proceeding is currently in its discovery phase. A procedural schedule has not been established.

2018 Rate Stabilization Plan Filing

In January 2019, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2018. The filing of the evaluation report for the test year 2018 reflected an earned return on common equity of 2.69%. This earned return is below the earning sharing band of the gas rate stabilization plan and results in a rate increase of $2.8 million. Entergy Louisiana will make a compliance filing in April 2019 and rates will be implemented during the first billing cycle of May 2019.

Filings with the MPSC (Entergy Mississippi)

Formula Rate Plan Filings

In March 2016, Entergy Mississippi submitted its formula rate plan 2016 test year filing showing Entergy Mississippi’s projected earned return for the 2016 calendar year to be below the formula rate plan bandwidth. The filing showed a $32.6 million rate increase was necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 9.96%, within the formula rate plan bandwidth. In June 2016 the MPSC approved Entergy Mississippi’s joint stipulation with the Mississippi Public Utilities Staff. The joint stipulation provided for a total revenue increase of $23.7 million. The revenue increase included a $19.4 million increase through the formula rate plan, resulting in a return on common equity point of adjustment of 10.07%. The revenue increase also included $4.3 million in incremental ad valorem tax expenses to be collected through an updated ad valorem tax adjustment rider. The revenue increase and ad valorem tax adjustment rider were effective with the July 2016 bills.

In March 2017, Entergy Mississippi submitted its formula rate plan 2017 test year filing and 2016 look-back filing showing Entergy Mississippi’s earned return for the historical 2016 calendar year and projected earned return for the 2017 calendar year to be within the formula rate plan bandwidth, resulting in no change in rates. In June 2017, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a stipulation that confirmed that Entergy Mississippi’s earned returns for both the 2016 look-back filing and 2017 test year were within the respective formula rate plan bandwidths. In June 2017 the MPSC approved the stipulation, which resulted in no change in rates.

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.

Entergy Mississippi’s formula rate plan includes a look-back evaluation report filing in March 2019 that will compare actual 2018 results to the performance-adjusted allowed return on rate base.  In fourth quarter 2018, Entergy Mississippi recorded a provision of $9.3 million that reflects the estimate of the difference between the 2018 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 October 2018, Entergy Mississippi proposed revisions to its formula rate plan that would provide for a mechanism, the interim capacity rate adjustment mechanism, in the formula rate plan 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 additions, such as the Sunflower Solar Facility, that are approved by the MPSC.

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

As a provision of the settlement agreement approved by the City Council in May 2015 providing for the transfer from Entergy Louisiana to Entergy New Orleans of certain assets that supported the provision of service to Entergy Louisiana’s customers in Algiers, it was agreed that, with limited exceptions, no action may be taken with respect to Entergy New Orleans’s base rates until rates are implemented from a base rate case that must be filed for its electric and gas operations in 2018. This provision eliminated the formula rate plan applicable to Algiers operations. The limited exceptions included continued implementation of the then-remaining two years of the four-year phased-in rate increase for the Algiers area and certain exceptional cost increases or decreases in the base revenue requirement. An additional provision of the settlement agreement allowed for continued recovery of the revenue requirement associated with the capacity and energy from Ninemile 6 received by Entergy New Orleans under a power purchase agreement with Entergy Louisiana (Algiers PPA). The settlement authorized Entergy New Orleans to recover the remaining revenue requirement related to the Algiers PPA through base rates charged to Algiers customers. The settlement also provided for continued implementation of the Algiers MISO recovery rider.

In addition to the Algiers PPA, Entergy New Orleans has a separate power purchase agreement with Entergy Louisiana for 20% of the capacity and energy from Ninemile 6 (Ninemile PPA), which commenced operation in December 2014. Initially, recovery of the non-fuel costs associated with the Ninemile PPA was authorized through a special Ninemile 6 rider billed only to Entergy New Orleans customers outside of Algiers.

In August 2015, Entergy New Orleans filed an application with the City Council seeking authorization to proceed with the purchase of Union Power Block 1, with an expected base purchase price of approximately $237 million, subject to adjustments, and seeking approval of the recovery of the associated costs. In November 2015 the City Council issued written resolutions and an order approving an agreement in principle between Entergy New Orleans and City Council advisors providing that the purchase of Union Power Block 1 and related assets by Entergy New Orleans is prudent and in the public interest. The City Council authorized expansion of the terms of the purchased power and capacity acquisition cost recovery rider to recover the non-fuel purchased power expense from Ninemile 6, the revenue requirement associated with the purchase of Power Block 1 of the Union Power Station, and a credit to customers of $400 thousand monthly beginning June 2016 in recognition of the decrease in other operation and maintenance expenses that would result with the deactivation of Michoud Units 2 and 3. In March 2016, Entergy New Orleans purchased Power Block 1 of the Union Power Station for approximately $237 million and initiated recovery of these costs with March 2016 bills. In July 2016, Entergy New Orleans and the City Council Utility Committee agreed to a temporary increase in the Michoud credit to customers to a total of $1.4 million monthly for August 2016 through December 2016.

A 2008 rate case settlement included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs.  The rate settlement provided an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provided a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs. In January 2015 the City Council approved funding for the Energy Smart program from April 2015 through March 2017 using the remainder of the approximately $12.8 million of 2014 rough production cost equalization funds, with any remaining costs being recovered through the fuel adjustment clause. This funding methodology was modified in November 2015 when the City Council directed Entergy New Orleans to use a combination of guaranteed customer savings related to a prior agreement with the City Council and rough production cost equalization funds to cover program costs prior to recovering any costs through the fuel adjustment clause. In April 2017 the City Council approved an implementation plan for the Energy Smart program from April 2017 through December 2019. The City Council directed that the $11.8 million balance reported for Energy Smart funds be used to continue funding the program for Entergy New Orleans’s legacy customers and that the Energy Smart Algiers program continue to be funded through the Algiers fuel adjustment clause, until additional customer funding is required for the legacy customers. In September 2017, Entergy New Orleans filed a supplemental plan and proposed several options for an interim cost recovery mechanism necessary to recover program costs during the period between when existing funds directed to Energy Smart programs are depleted and when new rates from the 2018 combined rate case, which includes a cost recovery mechanism for Energy Smart funding, take effect (estimated to be August 2019). In December 2017 the City Council approved an energy efficiency cost recovery rider as an interim funding mechanism for Energy Smart, subject to verification that no additional funding sources exist. In June 2018 the City Council also approved a resolution recommending that Entergy New Orleans allocate approximately $13.5 million of benefits resulting from the Tax Act to Energy Smart. Entergy New Orleans is seeking approval of a permanent and stable source of funding for Energy Smart as part of its base rate case filed in September 2018.

In September 2018, Entergy New Orleans filed an electric and gas base rate case with the City Council. The filing requests 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 requests 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 includes a proposed gas rate decrease of $142 thousand. Entergy New Orleans’s rates reflect 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 ending 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’s request for a change in rates is based on the projected twelve months ending December 31, 2018.

The filing’s major provisions include: (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 have recommended, among other things, overall rate reductions of approximately $33 million in electric rates and $3.8 million in gas rates. Certain intervenors have recommended overall rate reductions of up to approximately $49 million in electric rates and $5 million in gas rates. The procedural schedule calls for an evidentiary hearing to be held in June 2019.

Internal Restructuring

In July 2016, Entergy New Orleans filed an application with the City Council seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy New Orleans, Inc. to a new entity, which would ultimately be owned by an existing Entergy subsidiary holding company. In May 2017 the City Council adopted a resolution approving the proposed internal restructuring pursuant to an agreement in principle with the City Council advisors and certain intervenors. Pursuant to the agreement in principle, Entergy New Orleans would credit retail customers $10 million in 2017, $1.4 million in the first quarter of the year after the transaction closes, and $117,500 each month in the second year after the transaction closes until such time as new base rates go into effect as a result of the then-anticipated 2018 base rate case (which has subsequently been filed). Entergy New Orleans began crediting retail customers in June 2017. In June 2017 the FERC approved the transaction and, pursuant to the agreement in principle, Entergy New Orleans will provide additional credits to retail customers of $5 million in each of the years 2018, 2019, and 2020.

In November 2017, Entergy New Orleans undertook a multi-step restructuring, including the following:

• Entergy New Orleans, Inc. redeemed its outstanding preferred stock at a price of approximately $21 million, which included a call premium of approximately $819,000, plus any accumulated and unpaid dividends.

• Entergy New Orleans, Inc. converted from a Louisiana corporation to a Texas corporation.

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

• Entergy New Orleans, Inc. contributed the membership interests in Entergy New Orleans 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 New Orleans Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.

In December 2017, Entergy New Orleans, Inc. changed its name to Entergy Utility Group, Inc., and Entergy New Orleans Power then changed its name to Entergy New Orleans, LLC. Entergy New Orleans, LLC holds substantially all of the assets, and has assumed substantially all of the liabilities, of Entergy New Orleans, Inc. The restructuring was accounted for as a transaction between entities under common control.

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 electricity 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), 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 June 2017, Entergy Texas filed an application to amend its DCRF rider by increasing the total collection from $8.65 million to approximately $19 million. In July 2017, Entergy Texas, the PUCT staff, and the two other parties in the proceeding entered into an unopposed stipulation and settlement agreement resulting in an amended DCRF annual revenue requirement of $18.3 million. In September 2017 the PUCT issued its final order approving the unopposed stipulation and settlement agreement. The amended DCRF rider rates became effective for usage on and after September 1, 2017. DCRF rates were set to zero upon implementation of new base rates on October 17, 2018, as described above in the discussion of the 2018 base rate case.

Transmission Cost Recovery Factor (TCRF) Rider

In September 2015, Entergy Texas filed for a TCRF rider requesting a $13 million increase, incremental to base rates. Testimony was filed in November 2015, with the PUCT staff and other parties proposing various disallowances involving, among other things, MISO charges, vegetation management costs, and bad debt expenses that would reduce the requested increase by approximately $2 million. In addition to those recommended disallowances, a number of parties recommended that Entergy Texas’s request be reduced by an additional $3.4 million to account for load growth since base rates were last set. In February 2016 a State Office of Administrative Hearings ALJ issued a proposal for decision recommending that the PUCT disallow approximately $2 million from Entergy Texas’s $13 million request, but recommending that the PUCT not accept the load growth offset. In June 2016 the PUCT indicated that it would take up in a future rulemaking project the issue of whether a load growth adjustment should apply to a TCRF. In July 2016 the PUCT issued an order generally accepting the proposal for decision but declining to adjust the TCRF baseline in two instances as recommended by the ALJ, which resulted in a total annual allowance of approximately $10.5 million. The PUCT also ordered its staff and Entergy Texas to track all spare autotransformer transfers going forward so that it could address the appropriate accounting treatment and prudence of such transfers in Entergy Texas’s next base rate case. Entergy Texas implemented the TCRF rider beginning with September 2016 bills.

In September 2016, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The proposed amended TCRF rider was designed to collect approximately $29.5 million annually from Entergy Texas’s retail customers. This amount included the approximately $10.5 million annually that Entergy Texas was previously authorized to collect through the TCRF rider, as discussed above. In December 2016, concurrent with the 2016 fuel reconciliation stipulation and settlement agreement discussed above, Entergy Texas and the PUCT staff reached a settlement agreeing to the amended TCRF annual revenue requirement of $29.5 million. As discussed above, the terms of the two settlements are interdependent. The PUCT approved the settlement and issued a final order in March 2017. Entergy Texas implemented the amended TCRF rider beginning with bills covering usage on and after March 20, 2017. TCRF rates were set to zero upon implementation of new base rates on October 17, 2018, as described above in the 2018 base rate case discussion.

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. The proceeding is currently ongoing at the PUCT.

Advanced Metering Infrastructure (AMI) Filings

Entergy Arkansas

In September 2016, Entergy Arkansas filed an application seeking a finding from the APSC that Entergy Arkansas’s deployment of AMI is in the public interest. Entergy Arkansas proposed to replace existing meters with advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Arkansas’s modernized power grid. The filing included an estimate of implementation costs for AMI of $208 million. The filing identified a number of quantified and unquantified benefits, and Entergy Arkansas provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal net benefit to customers of $406 million. Entergy Arkansas also sought to continue to include in rate base the remaining book value of existing meters, which was approximately $57 million at December 31, 2015, that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Arkansas proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Deployment of the communications network began in 2018. Entergy Arkansas proposed to include the AMI deployment costs and the quantified benefits in future formula rate plan filings, and the 2018 costs were approved in the 2017 formula rate plan filing. In August 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement. In October 2017 the APSC issued an order finding that Entergy Arkansas’s AMI deployment is in the public interest and approving the settlement agreement subject to a minor modification. Entergy Arkansas expects to recover the undepreciated balance of its existing meters through a regulatory asset to be amortized over 15 years.

Entergy Louisiana

In November 2016, Entergy Louisiana filed an application seeking a finding from the LPSC that Entergy Louisiana’s deployment of advanced electric and gas metering infrastructure is in the public interest. Entergy Louisiana proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Louisiana’s modernized power grid. The filing included an estimate of implementation costs for AMI of $330 million. The filing identified a number of quantified and unquantified benefits, and Entergy Louisiana provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $607 million. Entergy Louisiana also sought to continue to include in rate base the remaining book value, approximately $92 million at December 31, 2015, of the existing electric meters and also to depreciate those assets using current depreciation rates. Entergy Louisiana proposed a 15-year useful life for the new advanced meters, the three-year deployment of which began in 2019. Deployment of the communications network began in 2018. Entergy Louisiana proposed to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022. The parties reached an uncontested stipulation permitting implementation of Entergy Louisiana’s proposed AMI system, with modifications to the proposed customer charge. In July 2017 the LPSC approved the stipulation. Entergy Louisiana expects to recover the undepreciated balance of its existing meters through a regulatory asset to be amortized at current depreciation rates.

Entergy Mississippi

In November 2016, Entergy Mississippi filed an application seeking an order from the MPSC granting a certificate of public convenience and necessity and finding that Entergy Mississippi’s deployment of AMI is in the public interest. Entergy Mississippi proposed to replace existing meters with advanced meters that enable two-way data communication; to design and build a secure and reliable network to support such communications; and to implement support systems. AMI is intended to serve as the foundation of Entergy Mississippi’s modernized power grid. The filing included an estimate of implementation costs for AMI of $132 million. The filing identified a number of quantified and unquantified benefits, and Entergy Mississippi provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal benefit to customers of $496 million over a 15-year period, which when netted against the costs of AMI results in $183 million of net customer benefits. Entergy Mississippi also sought to continue to include in rate base the remaining book value, approximately $56 million at December 31, 2015, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Mississippi proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019, subject to approval by the MPSC. Deployment of the communications network began in 2018. Entergy Mississippi proposed to include the AMI deployment costs and the quantified benefits in existing rate mechanisms, primarily through future formula rate plan filings and/or future energy cost recovery rider schedule re-determinations, as applicable. In May 2017 the Mississippi Public Utilities Staff and Entergy Mississippi entered into and filed a joint stipulation supporting Entergy Mississippi’s filing, and the MPSC issued an order approving the filing without material changes, finding that Entergy Mississippi’s deployment of AMI is in the public interest and granting a certificate of public convenience and necessity. The MPSC order also confirmed that Entergy Mississippi shall continue to include in rate base the remaining book value of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. In June 2018, as part of the order approving the joint stipulation between the Mississippi Public Utilities Staff and Entergy Mississippi addressing Entergy Mississippi’s 2018 formula rate plan evaluation report and the ratemaking effects of the Tax Act, the MPSC approved the acceleration of the recovery of substantially all of Entergy Mississippi’s existing customer meters in anticipation of AMI deployment.

Entergy New Orleans

In October 2016, Entergy New Orleans filed an application seeking a finding from the City Council that Entergy New Orleans’s deployment of advanced electric and gas metering infrastructure is in the public interest.  Entergy New Orleans proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems.  AMI is intended to serve as the foundation of Entergy New Orleans’s modernized power grid.  The filing included an estimate of implementation costs for AMI of $75 million. The filing identified a number of quantified and unquantified benefits, and Entergy New Orleans provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $101 million.  Entergy New Orleans also sought to continue to include in rate base the remaining book value, approximately $21 million at December 31, 2015, of the existing electric meters and also to depreciate those assets using current depreciation rates.  Entergy New Orleans proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which began in 2019.  Deployment of the information technology infrastructure began in 2017 and deployment of the communications network began in 2018.  Entergy New Orleans proposed to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022.  The City Council’s advisors filed testimony in May 2017 recommending the adoption of AMI subject to certain modifications, including the denial of Entergy New Orleans’s proposed customer charge as a cost recovery mechanism. In January 2018 a settlement was reached between the City Council’s advisors and Entergy New Orleans. In February 2018 the City Council approved the settlement, which deferred cost recovery to the 2018 Entergy New Orleans rate case, but also stated that an adjustment for 2018-2019 AMI costs can be filed in the rate case and that, for all subsequent AMI costs, the mechanism to be approved in the 2018 rate case will allow for the timely recovery of such costs. In April 2018 the City Council adopted a resolution directing Entergy New Orleans to explore the options for accelerating the deployment of AMI. In June 2018 the City Council approved a one-year acceleration of AMI in its service area for an incremental $4.4 million.

Entergy Texas

In April 2017 the Texas legislature enacted legislation that extends statutory support for AMI deployment to Entergy Texas and directs that if Entergy Texas elects to deploy AMI, it shall do so as rapidly as practicable. In July 2017, Entergy Texas filed an application seeking an order from the PUCT approving Entergy Texas’s deployment of AMI. Entergy Texas proposed to replace existing meters with advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Texas’s modernized power grid. The filing included an estimate of implementation costs for AMI of $132 million. The filing identified a number of quantified and unquantified benefits, with Entergy Texas showing that its AMI deployment is expected to produce nominal net operational cost savings to customers of $33 million. Entergy Texas also sought to continue to include in rate base the remaining book value, approximately $41 million at December 31, 2016, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Texas proposed a seven-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Entergy Texas also proposed a surcharge tariff to recover the reasonable and necessary costs it has and will incur under the deployment plan for the full deployment of advanced meters. Further, Entergy Texas sought approval of fees that would be charged to customers who choose to opt out of receiving service through an advanced meter and instead receive electric service with a non-standard meter. In October 2017, Entergy Texas and other parties entered into and filed an unopposed stipulation and settlement agreement, permitting deployment of AMI with limited modifications. The PUCT approved the stipulation and settlement agreement in December 2017. Entergy Texas implemented the AMI surcharge tariff beginning with January 2018 bills. As of December 31, 2018, Entergy Texas has a regulatory liability related to the collection of the surcharge from customers. Consistent with the approval, deployment of the communications network began in 2018 and deployment of the advanced meters will begin in March 2019. Entergy Texas expects to recover the remaining net book value of its existing meters through a regulatory asset to be amortized at current depreciation rates.

System Agreement Cost Equalization Proceedings

Prior to its final termination in 2016, the Utility operating companies historically engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement.  Entergy Arkansas terminated its participation in the System Agreement in December 2013. Entergy Mississippi terminated its participation in the System Agreement in November 2015. The System Agreement terminated with respect to its remaining participants in August 2016.

Although the System Agreement has terminated, certain of the Utility operating companies’ retail regulators continue to pursue litigation involving the System Agreement at the FERC and in federal courts.  The proceedings include challenges to the allocation of costs as defined by the System Agreement and other matters.

In June 2005 the FERC issued a decision in System Agreement litigation that had been commenced by the LPSC, and essentially affirmed its decision in a December 2005 order on rehearing.  The decision included, among other things:

• The FERC’s conclusion that the System Agreement no longer roughly equalized total production costs among the Utility operating companies.

• In order to reach rough production cost equalization, the FERC imposed a bandwidth remedy by which each company’s total annual production costs would have to be within +/- 11% of Entergy System average total annual production costs.

• In calculating the production costs for this purpose under the FERC’s order, output from the Vidalia hydroelectric power plant would not reflect the actual Vidalia price for the year but be priced at that year’s average price paid by Entergy Louisiana for the exchange of electric energy under Service Schedule MSS-3 of the System Agreement, thereby reducing the amount of Vidalia costs reflected in the comparison of the Utility operating companies’ total production costs.

• The remedy ordered by the FERC in 2005 required no refunds and became effective based on calendar year 2006 production costs with the first reallocation payments made in 2007.

The FERC’s decision reallocated total production costs of the Utility operating companies whose relative total production costs expressed as a percentage of Entergy System average production costs are outside an upper or lower bandwidth.  This was accomplished by payments from Utility operating companies whose production costs were more than 11% below Entergy System average production costs to Utility operating companies whose production costs were more than the Entergy System average production cost, with payments going first to those Utility operating companies whose total production costs were farthest above the Entergy System average.

The LPSC, APSC, MPSC, and the Arkansas Electric Energy Consumers appealed the FERC’s December 2005 decision to the United States Court of Appeals for the D.C. Circuit.  Entergy and the City of New Orleans intervened in the various appeals.  The D.C. Circuit issued its decision in April 2008.  The D.C. Circuit concluded that the FERC’s orders had failed to adequately explain both its conclusion that it was prohibited from ordering refunds for the 20-month period from September 13, 2001 - May 2, 2003 and its determination to implement the bandwidth remedy commencing on January 1, 2006, rather than June 1, 2005.  The D.C. Circuit remanded the case to the FERC for further proceedings on those two issues.

In October 2011 the FERC issued an order addressing the D.C. Circuit remand on the two issues.  On the first issue, the FERC concluded that it did have the authority to order refunds, but decided that it would exercise its equitable discretion and not require refunds for the 20-month period from September 13, 2001 - May 2, 2003.  Because the ruling on refunds relied on findings in the interruptible load proceeding, which is discussed in a separate section below, the FERC concluded that this refund ruling will be held in abeyance pending the outcome of the rehearing requests in the interruptible load proceeding.  On the second issue, the FERC reversed its prior decision and ordered that the prospective bandwidth remedy begin on June 1, 2005 (the date of its initial order in the proceeding) rather than January 1, 2006, as it had previously ordered.  Pursuant to the October 2011 order, Entergy was required to calculate bandwidth payments for the period June - December 2005 utilizing the bandwidth formula tariff prescribed by the FERC that was filed in a December 2006 compliance filing and accepted by the FERC in an April 2007 order.  

In March 2015, in light of a December 2014 decision by the D.C. Circuit in the interruptible load proceeding, Entergy filed with the FERC a motion to establish a briefing schedule on refund issues and an initial brief addressing refund issues. The initial brief argued that the FERC, in response to the D.C. Circuit decision, should clarify its policy on refunds and find that refunds are not required in this proceeding. In October 2015 the FERC issued three orders related to the commencement of the remedy on June 1, 2005 and the inclusion of interest for the period June 1, 2005 through December 31, 2005. Specifically, the FERC rejected Entergy’s request for rehearing of its decision to include interest for the seven-month period. The FERC also rejected Entergy’s request for rehearing of the order rejecting the compliance filing with regard to the issue of interest. Finally, the FERC set for hearing and settlement procedures the 2014 compliance filing that included the bandwidth calculation for the seven months June 1, 2005 through December 31, 2005. In setting the compliance filing for hearing, the FERC rejected the APSC’s protest that Entergy Arkansas should not be subject to the filing because Entergy Arkansas would be making the payments during a period following its exit from the System Agreement. In January 2018 the D.C. Circuit affirmed the FERC decision that Entergy Arkansas was subject to the filing.

In December 2011, Entergy filed with the FERC its compliance filing that provided the payments and receipts among the Utility operating companies pursuant to the FERC’s October 2011 order.  The APSC, the LPSC, the PUCT, and other parties intervened in the December 2011 compliance filing proceeding, and the APSC and the LPSC also filed protests. The filing showed the following payments/receipts among the Utility operating companies:

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$156
Entergy Louisiana	($75)
Entergy Mississippi	($33)
Entergy New Orleans	($5)
Entergy Texas	($43)

Entergy Arkansas made its payment in January 2012.  In February 2012, Entergy Arkansas filed for an interim adjustment to its production cost allocation rider requesting that the $156 million be collected from customers over the 22-month period from March 2012 through December 2013.  In March 2012 the APSC issued an order stating that the payment can be recovered from retail customers through the production cost allocation rider, subject to refund.  The LPSC and the APSC requested rehearing of the FERC’s October 2011 order.  

In February 2014 the FERC issued a rehearing order addressing its October 2011 order. The FERC denied the LPSC’s request for rehearing on the issues of whether the bandwidth remedy should be made effective earlier than June 1, 2005, and whether refunds should be ordered for the 20-month refund effective period. The FERC granted the LPSC’s rehearing request on the issue of interest on the bandwidth payments/receipts for the June - December 2005 period, requiring that interest be accrued from June 1, 2006 until the date those bandwidth payments/receipts are made. Also in February 2014 the FERC issued an order rejecting the December 2011 compliance filing that calculated the bandwidth payments/receipts for the June - December 2005 period. The FERC order required a new compliance filing that calculates the bandwidth payments/receipts for the June - December 2005 period based on monthly data for the seven individual months including interest pursuant to the February 2014 rehearing order. Entergy sought rehearing of the February 2014 order with respect to the FERC’s determinations regarding interest. In April 2014 the LPSC filed a petition for review of the FERC’s October 2011 and February 2014 orders with the U.S. Court of Appeals for the D.C. Circuit. In August 2017 the D.C. Circuit issued a decision denying the LPSC’s appeal of the FERC’s October 2011 and February 2014 orders. On the issue of the FERC’s implementation of the prospective remedy as of June 2005 and whether the bandwidth remedy should be extended for an additional 17 months in years 2004-2005, the D.C. Circuit affirmed the FERC’s implementation of the remedy and denied the LPSC’s appeal. On the issue of whether the operating companies should be required to issue refunds for the 20-month period from September 2001 to May 2003, the D.C. Circuit granted the FERC’s request for agency reconsideration and remanded that issue back to the FERC for further proceedings as requested by all parties to the appeal. In response to the D.C. Circuit’s remand, various parties filed briefs with the FERC addressing whether the FERC should require the Utility operating companies to issue refunds for the 20-month refund period from September 2001 to May 2003. The LPSC has argued in favor of such remands and Entergy has opposed the LPSC’s request. The briefing was completed in September 2018 and the matter is pending before the FERC.

In April and May 2014, Entergy filed with the FERC an updated compliance filing that provided the payments and receipts among the Utility operating companies pursuant to the FERC’s February 2014 orders.  The filing showed the following net payments and receipts, including interest, among the Utility operating companies:

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$68
Entergy Louisiana	($10)
Entergy Mississippi	($11)
Entergy New Orleans	$2
Entergy Texas	($49)

These payments were made in May 2014. The LPSC, City Council, and APSC filed protests.

The hearing on the bandwidth calculation for the seven months June 1, 2005 through December 31, 2005 occurred in July 2016. The presiding judge issued an initial decision in November 2016. In the initial decision, the presiding judge agreed with the Utility operating companies’ position that: (1) interest on the bandwidth payments for the 2005 test period should be accrued from June 1, 2006 until the date that the bandwidth payments for that calculation are paid, which is consistent with how the Utility operating companies performed the calculation; and (2) a portion of Entergy Louisiana’s 2001-vintage Louisiana state net operating loss accumulated deferred income tax that results from the Vidalia tax deduction should be excluded from the 2005 test period bandwidth calculation. Various participants filed briefs on exceptions and/or briefs opposing exceptions related to the initial decision, including the LPSC, the APSC, the FERC trial staff, and Entergy Services. In May 2018 the FERC issued an order affirming the initial decision and ordered a comprehensive recalculation of the bandwidth payments/receipts for the seven months June 1, 2005 through December 31, 2005 and a recalculation of the 2006 and 2007 test years as a result of limited revisions. Entergy filed the comprehensive recalculation of the bandwidth payments/receipts for the seven months June 1, 2005 through December 31, 2005 and the 2006 and 2007 test years in July 2018. The filing shows the additional following payments and receipts among the Utility operating companies:

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	($4)
Entergy Louisiana	($23)
Entergy Mississippi	$16
Entergy New Orleans	$5
Entergy Texas	$6

These payments were made in July 2018. In January 2019 the FERC denied the LPSC’s request for rehearing of the May 2018 order.

Rough Production Cost Equalization Rates

Each May from 2007 through 2016 Entergy filed with the FERC the rates to implement the FERC’s orders in the System Agreement proceeding.  These filings showed the following payments/receipts among the Utility operating companies were necessary to achieve rough production cost equalization as defined by the FERC’s orders:

	Payments (Receipts)
	2007			2008			2009			2010			2011			2012			2013			2014
	(In Millions)
Entergy Arkansas		$252			$252			$390			$41			$77			$41			$—			$—
Entergy Louisiana		($211	)		($160	)		($247	)		($22	)		($12	)		($41	)		$—			$—
Entergy Mississippi		($41	)		($20	)		($24	)		($19	)		($40	)		$—			$—			$—
Entergy New Orleans		$—			($7	)		$—			$—			($25	)		$—			($15	)		($15	)
Entergy Texas		($30	)		($65	)		($119	)		$—			$—			$—			$15			$15

The Utility operating companies recorded accounts payable or accounts receivable to reflect the rough production cost equalization payments and receipts required to implement the FERC’s remedy.  When accounts payable were recorded, a corresponding regulatory asset was recorded for the right to collect the payments from customers. When accounts receivable were recorded, a corresponding regulatory liability was recorded for the obligations to pass the receipts on to customers.  No payments were required in 2016 or 2015 to implement the FERC’s remedy based on calendar year 2015 production costs and 2014 production costs, respectively. The System Agreement terminated in August 2016.

The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas.  Entergy Texas recovered its 2013 rough production cost equalization payment over three years beginning April 2014. Entergy Texas included its 2014 rough production cost equalization payment as a component of an interim fuel refund made in 2014. Management believes that any changes in the allocation of production costs resulting from the FERC’s decision and related retail proceedings should result in similar rate changes for retail customers, subject to specific circumstances that have caused trapped costs.

The following rough production cost equalization rate proceedings are still ongoing or were ongoing during the period 2016-2018.

2010 Rate Filing Based on Calendar Year 2009 Production Costs

In May 2010, Entergy filed with the FERC the 2010 rates in accordance with the FERC’s orders in the System Agreement proceeding, and supplemented the filing in September 2010.  Several parties intervened in the proceeding at the FERC, including the LPSC and the City Council, which also filed protests.  In July 2010 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2010, subject to refund.  After an abeyance of the proceeding schedule, a hearing was held in March 2014 and in December 2015 the FERC issued an order. Among other things, the December 2015 order directed Entergy to submit a compliance filing. In January 2016 the LPSC, the APSC, and Entergy filed requests for rehearing of the FERC’s December 2015 order. In February 2016, Entergy submitted the compliance filing ordered in the December 2015 order.  The result of the true-up payments and receipts for the recalculation of production costs resulted in the following payments/receipts among the Utility operating companies:

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$2
Entergy Louisiana	$6
Entergy Mississippi	($4)
Entergy New Orleans	($1)
Entergy Texas	($3)

In September 2016 the FERC accepted the February 2016 compliance filing subject to a further compliance filing made in November 2016. The further compliance filing was required as a result of an order issued in September 2016 ruling on the January 2016 rehearing requests filed by the LPSC, the APSC, and Entergy. In the order addressing the rehearing requests, the FERC granted the LPSC’s rehearing request and directed that interest be calculated on the payment/receipt amounts. The FERC also granted the APSC’s and Entergy’s rehearing request and ordered the removal of both securitized asset accumulated deferred income taxes and contra-securitization accumulated deferred income taxes from the calculation. In November 2016, Entergy submitted its compliance filing in response to the FERC’s order on rehearing. The compliance filing included a revised calculation of the bandwidth true-up payments and receipts based on 2009 test year data and interest calculations. The LPSC protested the interest calculations. In November 2017 the FERC issued an order rejecting the November 2016 compliance filing. The FERC determined that the payments detailed in the November 2016 compliance filing did not include adequate interest for the payments from Entergy Arkansas to Entergy Louisiana because it did not include interest on the principal portion of the payment that was made in February 2016. In December 2017, Entergy recalculated the interest pursuant to the November 2017 order. As a result of the recalculations, Entergy Arkansas owed very minor payments to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.

2011 Rate Filing Based on Calendar Year 2010 Production Costs

In May 2011, Entergy filed with the FERC the 2011 rates in accordance with the FERC’s orders in the System Agreement proceeding.  Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest.  In July 2011 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2011, subject to refund. After an abeyance of the proceeding schedule, in December 2014 the FERC consolidated the 2011 rate filing with the 2012, 2013, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

2012 Rate Filing Based on Calendar Year 2011 Production Costs

In May 2012, Entergy filed with the FERC the 2012 rates in accordance with the FERC’s orders in the System Agreement proceeding.  Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest.  In August 2012 the FERC accepted Entergy’s proposed rates for filing, effective June 2012, subject to refund. After an abeyance of the proceeding schedule, in December 2014 the FERC consolidated the 2012 rate filing with the 2011, 2013, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

2013 Rate Filing Based on Calendar Year 2012 Production Costs

In May 2013, Entergy filed with the FERC the 2013 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest. The City Council intervened and filed comments related to including the outcome of a related FERC proceeding in the 2013 cost equalization calculation. In August 2013 the FERC issued an order accepting the 2013 rates, effective June 1, 2013, subject to refund. After an abeyance of the proceeding schedule, in December 2014 the FERC consolidated the 2013 rate filing with the 2011, 2012, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

2014 Rate Filing Based on Calendar Year 2013 Production Costs

In May 2014, Entergy filed with the FERC the 2014 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest. The City Council intervened and filed comments. In December 2014 the FERC issued an order accepting the 2014 rates, effective June 1, 2014, subject to refund, set the proceeding for hearing procedures, and consolidated the 2014 rate filing with the 2011, 2012, and 2013 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

Consolidated 2011, 2012, 2013, and 2014 Rate Filing Proceedings

As discussed above, in December 2014 the FERC consolidated the 2011, 2012, 2013, and 2014 rate filings for settlement and hearing procedures. In May 2015, Entergy filed direct testimony in the consolidated rate filings and the LPSC filed direct testimony concerning its complaint proceeding that is consolidated with the rate filings, challenging certain components of the pending bandwidth calculations for prior years. Hearings occurred in November 2015, and the ALJ issued an initial decision in July 2016. In the initial decision, the ALJ generally agreed with Entergy’s bandwidth calculations with one exception on the accounting related to the Waterford 3 sale/leaseback. In March 2018 the FERC issued an order affirming the initial decision. In April 2018 the LPSC requested rehearing of the FERC’s March 2018 order affirming the ALJ’s initial decision. Entergy filed in May 2018 the bandwidth true-up payments and receipts for the 2011-2014 rate filings (table does not net to zero due to rounding):

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$3
Entergy Louisiana	$3
Entergy Mississippi	($1)
Entergy New Orleans	$1
Entergy Texas	($5)

These payments were made in May 2018. The LPSC request for rehearing is pending.

Utility Operating Company Termination of System Agreement Participation

Entergy Arkansas and Entergy Mississippi ceased participating in the System Agreement effective December 18, 2013 and November 7, 2015, respectively. Entergy Louisiana, Entergy New Orleans, and Entergy Texas terminated participation in the System Agreement on August 31, 2016, which resulted in the termination of the System Agreement in its entirety pursuant to a settlement agreement approved by the FERC in December 2015.

In December 2013 the FERC set one issue for hearing involving whether and how the benefits associated with settlement with Union Pacific regarding certain coal delivery issues should be allocated among Entergy Arkansas and the other Utility operating companies post-termination of the System Agreement. In December 2014 a FERC ALJ issued an initial decision finding that Entergy Arkansas would realize benefits after December 18, 2013 from the 2008 settlement agreement between Entergy Services, Entergy Arkansas, and Union Pacific, related to certain coal delivery issues. In March 2016 the FERC issued an opinion affirming the December 2014 initial decision with regard to the determination that there were benefits related to the Union Pacific settlement, which were realized post-Entergy Arkansas’s December 2013 withdrawal from the System Agreement, that should be shared with the other Utility operating companies utilizing the methodology proposed by the MPSC and trued-up to actual coal volumes purchased. In May 2016, Entergy made a compliance filing that provided the calculation of Union Pacific settlement benefits utilizing the methodology adopted by the initial decision, trued-up for the actual volumes of coal purchased. The payments were made in May 2016. In August 2016 the FERC issued an order accepting Entergy’s compliance filing. Also in August 2016 the APSC filed a petition for review of the FERC’s March 2016 and August 2016 orders with the U.S. Court of Appeals for the D.C. Circuit. In June 2018 the D.C. Circuit denied the APSC’s petition.

Interruptible Load Proceeding

In April 2007 the U.S. Court of Appeals for the D.C. Circuit issued its opinion in the LPSC’s appeal of the FERC’s March 2004 and April 2005 orders related to the treatment under the System Agreement of the Utility operating companies’ interruptible loads.  In its opinion the D.C. Circuit concluded that the FERC: (1) acted arbitrarily and capriciously by allowing the Utility operating companies to phase-in the effects of the elimination of the interruptible load over a 12-month period of time; (2) failed to adequately explain why refunds could not be ordered under Section 206(c) of the Federal Power Act; and (3) exercised appropriately its discretion to defer addressing the cost of sulfur dioxide allowances until a later time.  The D.C. Circuit remanded the matter to the FERC for a more considered determination on the issue of refunds.  The FERC issued its order on remand in September 2007, in which it directed Entergy to make a compliance filing removing all interruptible load from the computation of peak load responsibility commencing April 1, 2004 and to issue any necessary refunds to reflect this change.  In addition, the order directed the Utility operating companies to make refunds for the period May 1995 through July 1996.  In November 2007 the Utility operating companies filed a refund report describing the refunds to be issued pursuant to the FERC’s orders.  The LPSC filed a protest to the refund report in December 2007.  The refunds were made in October 2008 by the Utility operating companies that owed refunds to the Utility operating companies that were due refunds under the decision.  The APSC and the Utility operating companies appealed the FERC decisions to the D.C. Circuit.

Following the filing of petitioners’ initial briefs, the FERC filed a motion requesting the D.C. Circuit hold the appeal of the FERC’s decisions ordering refunds in the interruptible load proceeding in abeyance and remand the record to the FERC.  The D.C. Circuit granted the FERC’s unopposed motion in June 2009.  In December 2009 the FERC established a paper hearing to determine whether the FERC had the authority and, if so, whether it would be appropriate to order refunds resulting from changes in the treatment of interruptible load in the allocation of capacity costs by the Utility operating companies.  In August 2010 the FERC issued an order stating that it has the authority and refunds are appropriate.  The APSC, the MPSC, and Entergy requested rehearing of the FERC’s decision.  In June 2011 the FERC issued an order granting rehearing in part and denying rehearing in part, in which the FERC determined to invoke its discretion to deny refunds.  The FERC held that in this case where “the Entergy system as a whole collected the proper level of revenue, but, as was later established, incorrectly allocated peak load responsibility among the various Entergy operating companies….the Commission will apply here our usual practice in such cases, invoking our equitable discretion to not order refunds, notwithstanding our authority to do so.”  The LPSC requested rehearing of the FERC’s June 2011 decision.  In July 2011 the refunds made in the fourth quarter 2008 described above were reversed. In October 2011 the FERC issued an “Order Establishing Paper Hearing” inviting parties that oppose refunds to file briefs within 30 days addressing the LPSC’s argument that FERC precedent supports refunds under the circumstances present in this proceeding.  Parties that favor refunds were then invited to file reply briefs within 21 days of the date that the initial briefs were due.  

In March 2013 the FERC issued an order denying the LPSC’s request for rehearing of the FERC’s June 2011 order wherein the FERC concluded it would exercise its discretion and not order refunds in the interruptible load proceeding. Based on its review of the LPSC’s request for rehearing and the briefs filed as part of the paper hearing established in October 2011, the FERC affirmed its earlier ruling and declined to order refunds under the circumstances of the case. In May 2013 the LPSC filed a petition for review with the U.S. Court of Appeals for the D.C. Circuit seeking review of FERC orders in the interruptible load proceeding that concluded that the FERC would exercise its discretion and not order refunds in the proceeding. Oral argument was held on the appeal in the D.C. Circuit in September 2014. In December 2014 the D.C. Circuit issued an order on the LPSC’s appeal and remanded the case back to the FERC. The D.C. Circuit rejected the LPSC’s argument that there is a presumption in favor of refunds, but it held that the FERC had not adequately explained its decision to deny refunds and directed the FERC “to consider the relevant factors and weigh them against one another.” In March 2015, Entergy filed with the FERC an initial brief on remand to address the December 2014 decision by the D.C. Circuit. The initial brief on remand argued that the FERC, in response to the D.C. Circuit decision, should clarify its policy on refunds and find that refunds are not required in the interruptible load proceeding.

In April 2016 the FERC issued an order on remand that addressed the December 2014 decision by the D.C. Circuit in the interruptible load proceeding. The order on remand affirmed the FERC’s denial of refunds for the 15-month refund effective period. The FERC explained and clarified its policies regarding refunds and concluded that the evidence in the record demonstrated that the relevant equitable factors favored not requiring refunds in this case. The FERC also noted that, under Section 206(c) of the Federal Power Act, in a Section 206 proceeding involving two or more electric utility companies of a registered holding company system, the FERC may order refunds only if it determines the refunds would not cause the registered holding company to experience any reduction in revenues resulting from an inability of an electric utility company in the system to recover the resulting increase in costs. The FERC stated it was not able to find that the Entergy system would not experience a reduction in revenues if refunds were awarded in this proceeding, which further supported the denial of refunds. In May 2016 the LPSC filed a request for rehearing of the FERC’s April 2016 order. In September 2016 the FERC issued an order denying the LPSC’s request for rehearing and reaffirming its denial of refunds for the 15-month refund effective period. The LPSC appealed the April and September 2016 orders to the U.S. Court of Appeals for the D.C. Circuit. In March 2018 the D.C. Circuit issued an order denying the LPSC’s appeal and affirming the FERC’s decision that it would be inequitable to award refunds in the proceeding. In April 2018 the LPSC sought rehearing en banc of the D.C. Circuit’s order denying the LPSC’s appeal. In May 2018 the D.C. Circuit denied the LPSC’s rehearing request. In August 2018 the LPSC filed with the Supreme Court of the United States a petition for a writ of certiorari to review the judgment of the D.C. Circuit. In November 2018 the Supreme Court of the United States denied the LPSC’s petition for a writ of certiorari to review the judgment of the D.C. Circuit, effectively terminating the interruptible load proceeding.

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’s 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’s appeal and held all of the appeals in abeyance pending final resolution of the related proceeding before the FERC.

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 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. 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.

Complaints Against System Energy

Return on Equity 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 the FERC to institute 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. System Energy is recording a provision against revenue for the potential outcome of this proceeding. In September 2017 the FERC established a refund effective date of January 23, 2017, consolidated the return on equity complaint with the proceeding described in Unit Power Sales Agreement below, 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 effective date 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 System Energy’s return on equity, with a refund effective date of April 2018. The portion of the LPSC’s complaint dealing with return on equity was subsequently consolidated with the APSC and MPSC complaint for hearing. The consolidated hearing has been scheduled for September 2019, and the parties are required to address 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 complaint, and System Energy submitted a response to the amended complaint in October 2018. In January 2019 the FERC set the amended complaint for settlement and hearing proceedings.

Grand Gulf Sale-leaseback Renewal Complaint

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 2018. The hearing has been scheduled for November 2019.

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 proposed amendments would result in lower charges to the Utility operating companies that buy capacity and energy from System Energy under the Unit Power Sales Agreement. The proposed changes are 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. System Energy requested that the FERC accept the amendments effective October 1, 2017.

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 propose 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. The FERC also consolidated the Unit Power Sales Agreement amendment proceeding with the proceeding described in“Return on Equity Complaints” above, and directed the parties to engage in settlement proceedings before an ALJ. 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.  The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages.  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.

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.  In February 2012, Entergy Louisiana sold 500,000 of its Class A preferred membership units in Entergy Holdings Company LLC, a wholly-owned Entergy subsidiary, to a third party in exchange for $51 million plus accrued but unpaid distributions on the units.  The 500,000 preferred membership units are mandatorily redeemable in January 2112.

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. As of April 30, 2016, Entergy Mississippi’s storm damage provision balance was less than $10 million, therefore Entergy Mississippi resumed billing the monthly storm damage provision effective with June 2016 bills. As of September 30, 2016, however, Entergy Mississippi’s storm damage provision balance exceeded $15 million. Accordingly the storm damage provision was reset to zero beginning with November 2016 bills. As of July 31, 2017, the balance in Entergy Mississippi’s accumulated storm damage provision was again less than $10 million, therefore Entergy Mississippi resumed billing the monthly storm damage provision effective with September 2017 bills. As of June 30, 2018, Entergy Mississippi’s storm damage provision balance exceeded $15 million. Accordingly the storm damage provision was reset to zero beginning with August 2018 bills.

Entergy New Orleans

In August 2012, Hurricane Isaac caused extensive damage to Entergy New Orleans’s service area. In January 2015 the City Council issued a resolution approving the terms of a joint agreement in principle filed by Entergy New Orleans, Entergy Louisiana, and the City Council Advisors determining, among other things, that Entergy New Orleans’s prudently-incurred storm recovery costs were $49.3 million, of which $31.7 million, net of reimbursements from the storm reserve escrow account, remained recoverable from Entergy New Orleans’s electric customers. The resolution also directed Entergy New Orleans to file an application to securitize the unrecovered City Council-approved storm recovery costs of $31.7 million pursuant to the Louisiana Electric Utility Storm Recovery Securitization Act (Louisiana Act 64). In addition, the resolution found that it was reasonable for Entergy New Orleans to include in the principal amount of its potential securitization the costs to fund and replenish Entergy New Orleans’s storm reserve in an amount that achieved the City Council-approved funding level of $75 million. In January 2015, in compliance with that directive, Entergy New Orleans filed with the City Council an application requesting that the City Council grant a financing order authorizing the financing of Entergy New Orleans’s storm costs, storm reserves, and issuance costs pursuant to Louisiana Act 64. In May 2015 the parties entered into an agreement in principle and the City Council issued a financing order authorizing Entergy New Orleans to issue storm recovery bonds in the aggregate amount of $98.7 million, including $31.8 million for recovery of Entergy New Orleans’s Hurricane Isaac storm recovery costs, including carrying costs, $63.9 million to fund and replenish Entergy New Orleans’s storm reserve, and approximately $3 million for estimated up-front financing costs associated with the securitization. See Note 5 to the financial statements for discussion of the issuance of the securitization bonds in July 2015.

New Nuclear Generation Development Costs

Entergy Louisiana

Entergy Louisiana and Entergy Gulf States Louisiana were developing a project option for new nuclear generation at River Bend.  In March 2010, Entergy Louisiana and Entergy Gulf States Louisiana filed with the LPSC seeking approval to continue the limited development activities necessary to preserve an option to construct a new unit at River Bend.  At its June 2012 meeting the LPSC voted to uphold an ALJ recommendation that the request of Entergy Louisiana and Entergy Gulf States Louisiana be declined on the basis that the LPSC’s rule on new nuclear development does not apply to activities to preserve an option to develop and on the further grounds that the companies improperly engaged in advanced preparation activities prior to certification.  The LPSC directed that Entergy Louisiana and Entergy Gulf States Louisiana be permitted to seek recovery of these costs in their upcoming rate case filings that were subsequently filed in February 2013. In the resolution of the rate case proceeding the LPSC provided for an eight-year amortization of costs incurred in connection with the potential development of new nuclear generation at River Bend, without carrying costs, beginning in December 2014, provided, however, that amortization of these costs shall not result in a future rate increase. As of December 31, 2018, Entergy Louisiana has a regulatory asset of $28.5 million on its balance sheet related to these new nuclear generation development costs.

Entergy Mississippi [Member]

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, 2018 and 2017:

Other Regulatory Assets

Entergy

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$2,611.5		$2,642.3
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	814.3		746.0
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 – Storm Cost Recovery Filings with Retail Regulators) (Note 5)	452.7		558.9
Removal costs - recovered through depreciation rates (Note 9)	375.8		436.5
Opportunity Sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding)	116.3		109.8
Unamortized loss on reacquired debt - recovered over term of debt	74.5		82.9
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy)	52.1		73.7
Retail rate deferrals - recovered through rate riders as rates are redetermined by retail regulators	39.0		86.4
New nuclear generation development costs (Note 2 - New Nuclear Generation Development Costs) (b)	29.0		36.4
Transition to competition costs - recovered over a 15-year period through February 2021	26.7		37.7
Other	154.6		125.1
Entergy Total		$4,746.5		$4,935.7

Entergy Arkansas

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$747.2		$757.0
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	381.7		345.2
Removal costs - recovered through depreciation rates (Note 9)	138.3		176.9
Opportunity sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding)	116.3		109.8
Storm damage costs - recovered either through securitization or retail rates (Note 5 - Entergy Arkansas Securitization Bonds)	60.7		76.2
Unamortized loss on reacquired debt - recovered over term of debt	21.2		24.3
Retail rate deferrals - recovered through rate riders as rates are redetermined annually	20.5		28.2
ANO Fukushima and Flood Barrier costs - recovered through retail rates through February 2026 (Note 2 - Retail Rate Proceedings) (b)	12.6		14.4
Other	36.5		35.4
Entergy Arkansas Total		$1,535.0		$1,567.4

Entergy Louisiana

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (a)		$711.8		$724.6
Asset Retirement Obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	232.9		218.6
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy)	49.8		71.4
New nuclear generation development costs - recovery through formula rate plan December 2014 through November 2022 (Note 2 - New Nuclear Generation Development Costs) (b)	28.5		35.8
Unamortized loss on reacquired debt - recovered over term of debt	22.5		24.7
Storm damage costs - recovered through retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)	17.9		14.3
Business combination external costs deferral - recovery through formula rate plan December 2015 through November 2025 (b)	12.4		14.1
River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC)	11.0		12.9
Other	18.3		29.4
Entergy Louisiana Total		$1,105.1		$1,145.8

Entergy Mississippi

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$215.9		$218.7
Removal costs - recovered through depreciation rates (Note 9)	63.5		91.6
Attorney General litigation costs (Note 2 - Mississippi Attorney General Complaint) (b)	23.6		9.3
Retail rate deferrals - recovered through rate riders as rates are redetermined annually	16.6		49.4
Unamortized loss on reacquired debt - recovered over term of debt	16.2		17.6
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a)	7.2		7.6
Other	—		3.7
Entergy Mississippi Total		$343.0		$397.9

Entergy New Orleans

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$96.2		$102.8
Storm damage costs, including hurricane costs - recovered through retail rates and securitization (Note 2 - Storm Cost Recovery Filings with Retail Regulators)	70.4		82.3
Removal costs - recovered through depreciation rates (Note 9)	49.3		44.8
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a)	4.5		4.3
Unamortized loss on reacquired debt - recovered over term of debt	2.6		3.0
Rate case costs - recovered over a 6-year period through September 2021 (Note 2 - Retail Rate Proceedings)	1.9		2.6
Retail rate deferrals - recovered through rate riders as rates are redetermined monthly or annually	—		4.4
Other	4.9		7.2
Entergy New Orleans Total		$229.8		$251.4

Entergy Texas

	2018		2017
	(In Millions)
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 5 - Entergy Texas Securitization Bonds)		$303.6		$386.1
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)	171.8		169.2
Removal costs - recovered through depreciation rates (Note 9)	50.9		55.2
Transition to competition costs - recovered over a 15-year period through February 2021	26.7		37.7
Neches and Sabine costs - recovered over a ten-year period through September 2028 (Note 2 - Retail Rate Proceedings) (b)	23.6		—
Unamortized loss on reacquired debt - recovered over term of debt	8.2		8.7
Other	13.2		4.5
Entergy Texas Total		$598.0		$661.4

System Energy

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Other Postretirement Benefits) (a)		$179.3		$202.7
Asset retirement obligation - recovery dependent upon timing of decommissioning (Note 9) (a)	186.9		169.1
Removal costs - recovered through depreciation rates (Note 9)	76.4		67.9
Unamortized loss on reacquired debt - recovered over term of debt	3.8		4.6
System Energy Total		$446.4		$444.3

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

(b) Does not earn a return on investment.

Other Regulatory Liabilities

Entergy

	2018		2017
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)		$815.9		$989.3
Vidalia purchased power agreement (Note 8) (b)	139.7		151.6
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) (b)	111.1		124.8
Income tax rate change - returned to electric and gas customers through retail rates (Note 2 - Retail Rate Proceedings)	74.7		—
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions)	67.9		67.9
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination)	50.8		65.8
Grand Gulf over-recovery - will be refunded through rate riders as rates are redetermined annually	48.6		—
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)	44.4		—
Internal restructuring guaranteed customer credits (Note 2 - Retail Rate Proceedings)	39.6		—
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)	39.1		36.7
Excess decommissioning recovery for Willow Glen - (Note 14 - Dispositions)	31.9		—
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement	25.0		32.1
Removal costs - returned to customers through depreciation rates (Note 9)	18.8		32.4
Other	68.4		43.5
Entergy Total		$1,620.3		$1,588.5

Entergy Arkansas

	2018		2017
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)		$297.2		$354.0
Internal restructuring guaranteed customer credits (Note 2 - Retail Rate Proceedings)	39.6		—
Future formula rate plan revenue reductions (Note 2 - Retail Rate Proceedings)	35.1		—
Grand Gulf over-recovery - will be refunded through rate riders as rates are redetermined annually	26.0		—
Other	4.8		9.6
Entergy Arkansas Total		$402.7		$363.6

Entergy Louisiana

	2018		2017
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)		$274.1		$323.7
Vidalia purchased power agreement (Note 8) (b)	139.7		151.6
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) (b)	111.1		124.8
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination)	50.8		65.8
Income tax rate change - returned to electric customers through retail rates September 2018 through August 2019 (Note 2 - Retail Rate Proceedings)	49.9		—
Asset Retirement Obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)	39.1		36.7
Excess decommissioning recovery for Willow Glen - (Note 14 - Dispositions)	31.9		—
Removal costs - returned to customers through depreciation rates (Note 9)	18.8		32.4
Other	33.4		26.1
Entergy Louisiana Total		$748.8		$761.1

Entergy Mississippi

	2018		2017
	(In Millions)
Grand Gulf Over-Recovery - returned to customers through rate riders when rates are redetermined annually		$22.6		$—
Future formula rate plan revenue reductions (Note 2 - Retail Rate Proceedings)	9.3		—
Other	1.7		0.9
Entergy Mississippi Total		$33.6		$0.9

Entergy Texas

	2018		2017
	(In Millions)
Income tax rate change - refunded through a rate rider (Note 2 - Retail Rate Proceedings)		$23.1		$—
Advanced metering system surcharge (Note 2 - Advanced Metering Infrastructure (AMI) Filings)	16.5		—
Transition to competition costs - returned to customers through rate riders when rates are redetermined periodically	4.2		4.8
Other	4.1		2.1
Entergy Texas Total		$47.9		$6.9

System Energy

	2018		2017
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 17) (a)		$244.6		$311.6
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions)	67.9		67.9
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
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement	25.0		32.1
System Energy Total		$381.9		$456.0

(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 $25.0 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 will be 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 to be 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 existing formula rate plan rider for its customers to realize the remaining benefits of the Tax Act. Entergy Arkansas’s formula rate plan rider includes a netting adjustment that compares 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.

Entergy Louisiana

In a 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 will be 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. Entergy Mississippi’s formula rate plan includes a look-back evaluation report filing in March 2019 that will compare actual 2018 results to the allowed return on rate base. The stipulation approved in June 2018 provides 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 any true-up to be 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. In November 2018, Entergy Mississippi’s annual redetermination of the annual factor to be applied under the power management rider included an insignificant true-up to the amount of unprotected excess accumulated deferred income taxes. In January 2019 the MPSC approved the proposed power management cost factor effective for February 2019 bills.

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. In both a memorandum issued prior to the open meeting when the order was discussed and during the discussions at the open meeting regarding the order, the PUCT indicated that it would consider utility earnings in determining the treatment of the liability and the effects of the Tax Act. 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. Entergy Texas also stated that it would be inappropriate for the PUCT to require a refund of the reduction in income tax expense in 2018 resulting from the Act on a retroactive basis and without a comprehensive review of Entergy Texas’s cost of service and earned return on equity.

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 will 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 will 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 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 larger customers and over a period of four years for other customers.

System Energy

In a filing made with the FERC in March 2018, Entergy proposed revisions to the Unit Power Sales Agreement, among other agreements, to reflect the effects of the Tax Act. In the filing System Energy proposed to return all of its 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 are ongoing.

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, 2018 and 2017 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.

	2018			2017
	(In Millions)
Entergy Arkansas (a)		$86.5			$130.4
Entergy Louisiana (b)		$136.7			$96.7
Entergy Mississippi		$8.0			$32.4
Entergy New Orleans (b)		$2.8			($3.7	)
Entergy Texas		($19.7	)		($67.3	)

(a) Includes $67.3 million in 2018 and $67.1 million in 2017 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

Production Cost Allocation Rider

The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings, which are discussed in the “System Agreement Cost Equalization Proceedings” section below.

In May 2016, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected recovery of the production cost allocation rider true-up adjustment of the 2014 and 2015 unrecovered retail balance in the amount of $1.9 million. Additionally, the redetermined rates reflected the recovery of a $1.9 million System Agreement bandwidth remedy payment resulting from a compliance filing pursuant to the FERC’s December 2015 order related to test year 2009 production costs. The rates for the 2016 production cost allocation rider update were effective July 2016 through June 2017.

In May 2017, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected a credit amount of $0.3 million resulting from a compliance filing pursuant to the FERC’s September 2016 order. Additionally, the redetermined rate reflected recovery of the production cost allocation rider true-up adjustment of the 2016 unrecovered retail balance in the amount of $0.3 million. Because of the small effect of the 2017 production cost allocation rider update, Entergy Arkansas proposed to reduce the effective period of the update to one month, July 2017. After the one month collection period, rates were set to zero for all rate classes for the period August 2017 through June 2018.

In May 2018, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected recovery of the 2017 under-recovered retail balance and a $2.8 million payment by Entergy Arkansas associated with a compliance filing pursuant to a March 2018 FERC order related to 2010 production costs. The rates for the 2018 production cost allocation rider update are effective July 2018 through June 2019.

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.

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 December 2011 the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates.  The audit included a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 2005 through 2009.  In March 2016 the LPSC staff consultant issued its audit report. In its report, the LPSC staff consultant recommended that Entergy Louisiana refund approximately $8.6 million, plus interest, to customers and realign the recovery of approximately $12.7 million from Entergy Gulf States Louisiana’s fuel adjustment clause to base rates. In September 2016 the LPSC staff filed testimony stating that it was no longer recommending a disallowance of $3.4 million of the $8.6 million discussed above, but otherwise maintained the positions from its report. Subsequently, the parties entered into a settlement, which was approved by the LPSC in November 2016. The settlement recognized the dry cask storage recovery method issue, which was addressed in the separate proceeding approved by the LPSC in October 2017, provided for a refund of $5 million, which was made to legacy Entergy Gulf States Louisiana customers in December 2016, and resolved all other issues raised in the audit.

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 is evaluating the staff’s recommended disallowance.

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 consultant issued its audit report. In its report, the LPSC staff consultant recommended 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 is evaluating the staff’s recommended disallowance.

In June 2016 the LPSC staff provided notice of audits of Entergy Louisiana’s fuel adjustment clause filings and purchased gas adjustment clause filings. In recognition of the business combination that occurred in 2015, the audit notice was issued to Entergy Louisiana and will also include a review of charges to legacy Entergy Gulf States Louisiana customers prior to the business combination. The audit includes 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. Discovery commenced in March 2017. No report of audit has been issued.

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.  Discovery commenced in September 2018.  No report of audit has been issued.

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 November 2015, 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 a projected over-recovery balance of $48 million projected through January 31, 2016. In January 2016 the MPSC approved the redetermined annual factor effective February 1, 2016. The MPSC further ordered, however, that due to the significant change in natural gas price forecasts since Entergy Mississippi’s filing in November 2015 Entergy Mississippi should file a revised fuel factor with the MPSC no later than February 1, 2016. Pursuant to that order, Entergy Mississippi submitted a revised fuel factor. Additionally, because Entergy Mississippi’s projected over-recovery balance for the period ending January 31, 2016 was $68 million, in February 2016, Entergy Mississippi filed for another interim adjustment to the energy cost factor effective April 2016 to flow through to customers the projected over-recovery balance over a six-month period. That interim adjustment was approved by the MPSC in February 2016 effective for April 2016 bills.

In November 2016, 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 less than $2 million as of September 30, 2016. In January 2017 the MPSC approved the annual factor effective with February 2017 bills. Also 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 its order, the MPSC expressly reserved the right to review and determine the recoverability of any and all purchased power expenditures made during fiscal year 2016. The MPSC hired independent auditors to conduct an annual operations audit and a financial audit. The independent auditors issued their audit reports in December 2017. The audit reports included several recommendations for action by Entergy Mississippi but did not recommend any cost disallowances. In January 2018 the MPSC certified the audit reports to the Mississippi Legislature. In November 2017 the Public Utilities Staff separately engaged a consultant to review the outage at the Grand Gulf Nuclear Station that began in 2016. The review is currently in progress.

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. Entergy Mississippi proposed a two-tiered energy cost factor designed to promote overall rate stability throughout 2018 particularly during the summer months. 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.

Mississippi Attorney General Complaint

The Mississippi Attorney General filed a complaint in state court in December 2008 against Entergy Corporation, Entergy Mississippi, Entergy Services, and Entergy Power alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution.  The complaint is wide ranging and relates to tariffs and procedures under which Entergy Mississippi purchases power not generated in Mississippi to meet electricity demand.  Entergy believes the complaint is unfounded.  In December 2008 the defendant Entergy companies removed the Attorney General’s lawsuit to U.S. District Court in Jackson, Mississippi. In June 2010 the MPSC authorized the deferral of certain legal expenses associated with this litigation until it is resolved. As of December 31, 2018, Entergy Mississippi has a regulatory asset of $23.6 million for these deferred legal expenses. Pre-trial and settlement conferences were held in October 2018. In October 2018 the District Court rescheduled the trial to April 2019.

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 July 2015 certain parties filed briefs in a PUCT proceeding asserting that Entergy Texas should refund to retail customers an additional $10.9 million in bandwidth remedy payments Entergy Texas received related to calendar year 2006 production costs.  In October 2015 an ALJ issued a proposal for decision recommending that the additional bandwidth remedy payments be refunded to retail customers. In January 2016 the PUCT issued its order affirming the ALJ’s recommendation, and Entergy Texas filed a motion for rehearing of the PUCT’s decision, which the PUCT denied. In March 2016, Entergy Texas filed a complaint in Federal District Court for the Western District of Texas and a petition in the Travis County (State) District Court appealing the PUCT’s decision. The pending appeals did not stay the PUCT’s decision. In April 2016, Entergy Texas filed with the PUCT an application to refund to customers approximately $56.2 million. The refund resulted from (i) $41.8 million of fuel cost recovery over-collections through February 2016, (ii) the $10.9 million in bandwidth remedy payments, discussed above, that Entergy Texas received related to calendar year 2006 production costs, and (iii) $3.5 million in bandwidth remedy payments that Entergy Texas received related to 2006-2008 production costs. In June 2016, Entergy Texas filed an unopposed settlement agreement that added additional over-recovered fuel costs for the months of March and April 2016. The settlement resulted in a $68 million refund. The ALJ approved the refund on an interim basis and it was made to most customers over a four-month period beginning with the first billing cycle of July 2016. In July 2016 the PUCT issued an order approving the interim refund. The federal appeal of the PUCT’s January 2016 decision was heard in December 2016, and the Federal District Court granted Entergy Texas’s requested relief. In January 2017 the PUCT and an intervenor filed petitions for appeal of the Federal District Court ruling to the U.S. Court of Appeals for the Fifth Circuit. Oral argument was held before the Fifth Circuit in February 2018. In April 2018 the Fifth Circuit reversed the decision of the Federal District Court, reinstating the original PUCT decision. In October 2018, Entergy Texas filed notice of nonsuit in its appeal to the Travis County District Court regarding the PUCT’s January 2016 decision.

In July 2016, Entergy Texas filed an application to reconcile its fuel and purchased power costs for the period April 1, 2013 through March 31, 2016. During the reconciliation period, Entergy Texas incurred approximately $1.77 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 over-recovery balance of approximately $19.3 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning April 2016. Entergy Texas also noted, however, that the estimated $19.3 million over collection was being refunded to customers as a portion of the interim fuel refund beginning with the first billing cycle of July 2016, discussed above. Entergy Texas also requested a prudence finding for each of the fuel-related contracts and arrangements entered into or modified during the reconciliation period that have not been reviewed by the PUCT in a prior proceeding. In December 2016, Entergy Texas entered into a stipulation and settlement agreement resulting in a $6 million disallowance not associated with any particular issue raised and a refund of the over-recovery balance of $21 million as of November 30, 2016, to most customers beginning April 2017 through June 2017. This settlement was developed concurrently with the stipulation and settlement agreement in the 2016 transmission cost recovery factor rider amendment discussed below, and the terms and conditions in both settlements are interdependent. The fuel reconciliation settlement was approved by the PUCT in March 2017 and the refunds were made.

In June 2017, Entergy Texas filed an application for a fuel refund of approximately $30.7 million for the months of December 2016 through April 2017. For most customers, the refunds flowed through bills for the months of July 2017 through September 2017. The fuel refund was approved by the PUCT in August 2017.

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.

Retail Rate Proceedings

Filings with the APSC (Entergy Arkansas)

Retail Rates

2015 Base Rate Filing

In April 2015, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. The filing notified the APSC of Entergy Arkansas’s intent to implement a forward test year formula rate plan pursuant to Arkansas legislation passed in 2015, and requested a retail rate increase of $268.4 million, with a net increase in revenue of $167 million. The filing requested a 10.2% return on common equity. In December 2015, Entergy Arkansas, the APSC staff, and certain of the intervenors in the rate case filed with the APSC a joint motion for approval of a settlement of the case that proposed a retail rate increase of approximately $225 million with a net increase in revenue of approximately $133 million; an authorized return on common equity of 9.75%; and a formula rate plan tariff that provides a +/- 50 basis point band around the 9.75% allowed return on common equity. A significant portion of the rate increase is related to Entergy Arkansas’s acquisition in March 2016 of Union Power Station Power Block 2 for a base purchase price of $237 million. The settlement agreement also provided for amortization over a 10-year period of $7.7 million of previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance. In February 2016 the APSC approved the settlement with one exception that reduced the retail rate increase proposed in the settlement by $5 million. The settling parties agreed to the APSC modifications in February 2016. The new rates were effective February 24, 2016 and began billing with the first billing cycle of April 2016. In March 2016, Entergy Arkansas made a compliance filing regarding the new rates that included an interim base rate adjustment surcharge, effective with the first billing cycle of April 2016, to recover the incremental revenue requirement for the period February 24, 2016 through March 31, 2016. The interim base rate adjustment surcharge was designed to recover a total of $21.1 million over the nine-month period from April 2016 through December 2016.

2016 Formula Rate Plan Filing

In July 2016, Entergy Arkansas filed with the APSC its 2016 formula rate plan filing showing Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2017 test period to be below the formula rate plan bandwidth. The filing requested a $67.7 million revenue requirement increase to achieve Entergy Arkansas’s target earned return on common equity of 9.75%. In October 2016, Entergy Arkansas filed with the APSC revised formula rate plan attachments with an updated request for a $54.4 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors, as well as three additional adjustments identified as appropriate by Entergy Arkansas. In November 2016 a hearing was held and the APSC issued an order directing the parties to brief certain issues. In December 2016 the APSC approved a settlement agreement and the $54.4 million revenue requirement increase with approximately $25 million of the $54.4 million revenue requirement subject to possible future adjustment and refund to customers with interest. The APSC requested supplemental information for some of Entergy Arkansas’s requested nuclear expenditures. In December 2016 the APSC approved Entergy Arkansas’s formula rate plan compliance tariff, and the rates became effective with the first billing cycle of January 2017. In April 2017, Entergy Arkansas filed a motion consented to by all parties requesting that it be permitted to submit the supplemental information requested by the APSC in conjunction with its 2017 formula rate plan filing, which was subsequently made in July 2017 and is discussed below. In May 2017 the APSC approved the joint motion and proposal to review Entergy Arkansas’s supplemental information on a concurrent schedule with the 2017 formula rate plan filing. In October 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement resolving all issues in the proceeding and providing for recovery of the 2017 and 2018 nuclear costs. In December 2017 the APSC approved the settlement agreement and recovery of the 2017 and 2018 nuclear costs.

2017 Formula Rate Plan Filing

In July 2017, Entergy Arkansas filed with the APSC its 2017 formula rate plan filing showing Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2018 test period to be below the formula rate plan bandwidth.  The filing projected a $129.7 million revenue requirement increase to achieve Entergy Arkansas’s target earned return on common equity of 9.75%.  Entergy Arkansas’s formula rate plan is subject to a four percent annual revenue constraint and the projected annual revenue requirement increase exceeded the four percent, resulting in a proposed increase for the 2017 formula rate plan of $70.9 million. In October 2017, Entergy Arkansas filed with the APSC revised formula rate plan attachments that projected a $126.2 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors. The revised formula rate plan filing included a proposed $71.1 million revenue requirement increase based on a revision to the four percent constraint calculation. In October 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement resolving all issues in the proceeding and providing for recovery of the 2017 and 2018 nuclear costs. In December 2017 the APSC approved the settlement agreement and the $71.1 million revenue requirement increase, as well as Entergy Arkansas’s formula rate plan compliance tariff, and the rates became effective with the first billing cycle of January 2018.

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 shows 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 includes 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 includes a projected $73.4 millionrevenue 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 exceeds the constraint, the resulting increase is 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, which included additional actual revenues for 2018. 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 certain 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. An additional schedule was issued by the APSC for briefing other contested issues, the outcome of which did not affect the 2018 filing but could affect future Entergy Arkansas formula rate plan filings. That briefing was completed in February 2019, and the APSC has not indicated when a decision on those issues can be expected.

Similar to the 2018 filing, the formula rate plan filing that will be made in 2019 to set the formula rates for the 2020 calendar year will include a netting adjustment that will compare projected costs and sales for 2018 that were approved in the 2017 formula rate plan filing to actual 2018 costs and sales data. In the fourth quarter 2018, Entergy Arkansas recorded a provision of $35.1 million that reflects the estimate of the historical year netting adjustment that will be included in the 2019 filing to reflect the change in formula rate plan revenues associated with actual 2018 results when compared to the allowed rate of return on equity. 

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. Entergy Arkansas also filed a notice with the Missouri Public Service Commission in December 2017 out of an abundance of caution, although Entergy Arkansas does not serve any retail customers in Missouri. In April 2018 the Missouri Public Service Commission approved Entergy Arkansas’s filing. 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

2015 Formula Rate Plan Filing

In May 2016, Entergy Louisiana filed its formula rate plan evaluation report for its 2015 calendar year operations. The evaluation report reflected an earned return on common equity of 9.07%. As such, no adjustment to base formula rate plan revenue was required. The following other adjustments, however, were required under the formula rate plan: an increase in the legacy Entergy Louisiana additional capacity mechanism of $14.2 million; a separate increase in legacy Entergy Louisiana revenue of $10 million primarily to reflect the effects of the termination of the System Agreement; an increase in the legacy Entergy Gulf States Louisiana additional capacity mechanism of $0.5 million; a decrease in legacy Entergy Gulf States Louisiana revenue of $58.7 million primarily to reflect the effects of the termination of the System Agreement; and an increase of $11 million to the MISO cost recovery mechanism. Rates were implemented with the first billing cycle of September 2016, subject to refund. Following implementation of the as-filed rates in September 2016, there were several interim updates to Entergy Louisiana’s formula rate plan, including the one submitted in December 2016, reflecting implementation of the settlement of the Waterford 3 replacement steam generator project prudence review described below. In June 2017 the LPSC staff and Entergy Louisiana filed a joint report of proceedings, which was accepted by the LPSC in June 2017, finalizing the results of the May 2016 evaluation report, interim updates, and corresponding proceedings with no changes to rates already implemented.

2016 Formula Rate Plan Filing

In May 2017, Entergy Louisiana filed its formula rate plan evaluation report for its 2016 calendar year operations. The evaluation report reflected an earned return on common equity of 9.84%. As such, no adjustment to base formula rate plan revenue was required. Adjustments, however, were required under the formula rate plan; the 2016 formula rate plan evaluation report showed a decrease in formula rate plan revenue of approximately $16.9 million, comprised of a decrease in legacy Entergy Louisiana formula rate plan revenue of $3.5 million, a decrease in legacy Entergy Gulf States Louisiana formula rate plan revenue of $9.7 million, and a decrease in incremental formula rate plan revenue of $3.7 million. Additionally, the formula rate plan evaluation report called for a decrease of $40.5 million in the MISO cost recovery revenue requirement from $46.8 million to $6.3 million. Rates reflecting these adjustments were implemented with the first billing cycle of September 2017, subject to refund. In September 2017 the LPSC issued its report indicating that no changes to Entergy Louisiana’s original formula rate plan evaluation report were required but reserved for several issues, including Entergy Louisiana’s September 2017 update to its formula rate plan evaluation report.  In July 2018, Entergy Louisiana and the LPSC staff filed an unopposed joint report setting forth a correction to the annualization calculation, the effect of which was a net $3.5 million revenue requirement reduction and indicating that there are no outstanding issues with the 2016 formula rate plan report, the supplemental report, or the interim updates.  In September 2018 the LPSC approved the unopposed joint report.

Formula Rate Plan Extension Through 2019 Test Year

In August 2017, Entergy Louisiana filed a request with the LPSC seeking to extend its formula rate plan for three years (2017-2019) with limited modifications of its terms.  Those modifications include: a one-time resetting of base rates to the midpoint of the band at Entergy Louisiana’s authorized return on equity of 9.95% for the 2017 test year; narrowing of the formula rate plan bandwidth from a total of 160 basis points to 80 basis points; and a forward-looking mechanism that would allow Entergy Louisiana to recover certain transmission-related costs contemporaneously with when those projects begin delivering benefits to customers.  In April 2018 the LPSC approved an unopposed joint motion filed by Entergy Louisiana and the LPSC staff that settled the matter. The settlement extended the formula rate plan for three years, providing for rates through at least August 2021. In addition to retaining the major features of the traditional formula rate plan, substantive features of the extended formula rate plan include:

• a mid-point reset of formula rate plan revenues to a 9.95% earned return on common equity for the 2017 test year and for the St. Charles Power Station when it enters commercial operation;

• a 9.8% target earned return on common equity for the 2018 and 2019 test years;

• narrowing of the common equity bandwidth to plus or minus 60 basis points around the target earned return on common equity;

• a cap on potential revenue increase of $35 million for the 2018 evaluation period, and $70 million for the cumulative 2018 and 2019 evaluation periods, on formula rate plan cost of service rate increases (the cap excludes rate changes associated with the transmission recovery mechanism described below and rate changes associated with additional capacity);

• a framework for the flow back of certain tax benefits created by the Tax Act to customers, as described in “Regulatory activity regarding the Tax Cuts and Jobs Act” above; and

• a transmission recovery mechanism providing for the opportunity to recover certain transmission-related expenditures in excess of $100 million annually for projects placed in service up to one month prior to rate change outside of sharing that is designed to operate in a fashion similar to the additional capacity mechanism.

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.

Waterford 3 Replacement Steam Generator Project

Following the completion of the Waterford 3 replacement steam generator project, the LPSC undertook a prudence review in connection with a filing made by Entergy Louisiana in April 2013 with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs. In July 2014 the LPSC staff filed testimony recommending potential project and replacement power cost disallowances of up to $71 million, citing a need for further explanation or documentation from Entergy Louisiana.  An intervenor filed testimony recommending disallowance of $141 million of incremental project costs, claiming the steam generator fabricator was imprudent.  Entergy Louisiana provided further documentation and explanation requested by the LPSC staff. An evidentiary hearing was held in December 2014. Entergy Louisiana believed that the replacement steam generator costs were prudently incurred and applicable legal principles supported their recovery in rates.  Nevertheless, Entergy Louisiana recorded a write-off of $16 million of Waterford 3’s plant balance in December 2014 because of the uncertainty at the time associated with the resolution of the prudence review. In December 2015 the ALJ issued a proposed recommendation, which was subsequently finalized, concluding that Entergy Louisiana prudently managed the Waterford 3 replacement steam generator project, including the selection, use, and oversight of contractors, and could not reasonably have anticipated the damage to the steam generators. Nevertheless, the ALJ concluded that Entergy Louisiana was liable for the conduct of its contractor and subcontractor and, therefore, recommended a disallowance of $67 million in capital costs. Additionally, the ALJ concluded that Entergy Louisiana did not sufficiently justify the incurrence of $2 million in replacement power costs during the replacement outage. Although the ALJ’s recommendation had not yet been considered by the LPSC, after considering the progress of the proceeding in light of the ALJ recommendation, Entergy Louisiana recorded in the fourth quarter 2015 approximately $77 million in charges, including a $45 million asset write-off and a $32 million regulatory charge, to reflect that a portion of the assets associated with the Waterford 3 replacement steam generator project was no longer probable of recovery. Entergy Louisiana maintained that the ALJ’s recommendation contained significant factual and legal errors.

In October 2016 the parties reached a settlement in this matter. The settlement was approved by the LPSC in December 2016. The settlement effectively provided for an agreed-upon disallowance of $67 million of plant, which had been previously written off by Entergy Louisiana, as discussed above. The refund to customers of approximately $71 million as a result of the settlement approved by the LPSC was made to customers in January 2017. Of the $71 million of refunds, $68 million was credited to customers through Entergy Louisiana’s formula rate plan, outside of sharing, and $3 million through its fuel adjustment clause. Entergy Louisiana had previously recorded a provision of $48 million for this refund. The previously-recorded provision included the cumulative revenues recorded through December 2016 related to the $67 million of disallowed plant. An additional regulatory charge of $23 million was recorded in fourth quarter 2016 to reflect the effects of the settlement. The settlement also provided that Entergy Louisiana could retain the value associated with potential service credits agreed to by the project contractor, to the extent they are realized in the future. Following a review by the parties, an unopposed joint report of proceedings was filed by the LPSC staff and Entergy Louisiana in May 2017 and the LPSC accepted the joint report of proceedings resolving the matter.

Union Power Station and Deactivation or Retirement Decisions for Entergy Louisiana Plants

In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC for approval of the acquisition and cost recovery of two power blocks of the Union Power Station for an expected base purchase price of approximately $237 million per power block, subject to adjustments. In September 2015, Entergy Gulf States Louisiana agreed to settlement terms with all parties for Entergy Gulf States Louisiana’s purchase of the two power blocks. In October 2015 the LPSC voted unanimously to approve the uncontested settlement which finds, among other things, that acquisition of Power Blocks 3 and 4 is in the public interest and, therefore, prudent. The business combination of Entergy Gulf States Louisiana and Entergy Louisiana received regulatory approval and closed in October 2015 making Entergy Louisiana the named purchaser of Power Blocks 3 and 4 of the Union Power Station. In March 2016, Entergy Louisiana acquired Power Blocks 3 and 4 of Union Power Station for an aggregate purchase price of approximately $475 million and implemented rates to collect the estimated first-year revenue requirement with the first billing cycle of March 2016.

As a term of the LPSC-approved settlement authorizing the purchase of Power Blocks 3 and 4 of the Union Power Station, Entergy Louisiana agreed to make a filing with the LPSC to review its decisions to deactivate Ninemile 3 and Willow Glen 2 and 4 and its decision to retire Little Gypsy 1.  In January 2016, Entergy Louisiana made its compliance filing with the LPSC. Entergy Louisiana, LPSC staff, and intervenors participated in a technical conference in March 2016 where Entergy Louisiana presented information on its deactivation/retirement decisions for these four units in addition to information on the current deactivation decisions for the ten-year planning horizon. Parties requested further proceedings on the prudence of the decision to deactivate Willow Glen 2 and 4.  No party contested the prudence of the decision to deactivate Willow Glen 2 and 4 or suggested reactivation of these units; however, issues were raised related to Entergy Louisiana’s decision to give up its transmission service rights in MISO for Willow Glen 2 and 4 rather than placing the units into suspended status for the three-year term permitted by MISO. In March 2018 the LPSC adopted the ALJ’s recommended order finding that Entergy Louisiana did not demonstrate that its decision to permanently surrender transmission rights for the mothballed (not retired) Willow Glen 2 and 4 units was reasonable and that Entergy Louisiana should hold customers harmless from increased transmission expenses should those units be reactivated. Because no party or the LPSC suggested that Willow Glen 2 and 4 should be reactivated and because the cost to return those units to service far exceeded the revenue the units were expected to generate in MISO, Entergy Louisiana retired Willow Glen 2 and 4 in March 2018. Entergy Louisiana submitted a compliance filing regarding retirement of Willow Glen 2 and 4, and the LPSC closed the proceeding.

Retail Rates - Gas

2016 Rate Stabilization Plan Filing

In January 2017, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2016. The filing of the evaluation report for test year 2016 reflected an earned return on common equity of 6.37%. In April 2017 the LPSC approved a joint report of proceedings and Entergy Louisiana submitted a revised evaluation report reflecting a $1.2 million annual increase in revenue with rates implemented with the first billing cycle of May 2017.

2017 Rate Stabilization Plan Filing

In January 2018, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2017.  The filing of the evaluation report for the test year 2017 reflected an earned return on common equity of 9.06%.  This earned return is below the earnings sharing band of the rate stabilization plan and results in a rate increase of $0.1 million.  Due to the enactment in late-December 2017 of the Tax Cuts and Jobs Act, Entergy Louisiana did not have adequate time to reflect the effects of this tax legislation in the rate stabilization plan.  In April 2018, Entergy Louisiana filed a supplemental evaluation report for the test year ended September 2017, reflecting the effects of the Tax Act, including a proposal to use the unprotected excess accumulated deferred income taxes to offset approximately $1.4 million of storm restoration deferred operation and maintenance costs incurred by Entergy Louisiana in connection with the August 2016 flooding disaster in its gas service area. The supplemental filing reflects an earned return on common equity of 10.79%. As-filed rates from the supplemental filing were implemented, subject to refund, with customers receiving a cost reduction of approximately $0.7 million effective with bills rendered on and after the first billing cycle of May 2018, as well as a $0.2 million reduction in the gas infrastructure rider effective with bills rendered on and after the first billing cycle of July 2018. The proceeding is currently in its discovery phase. A procedural schedule has not been established.

2018 Rate Stabilization Plan Filing

In January 2019, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2018. The filing of the evaluation report for the test year 2018 reflected an earned return on common equity of 2.69%. This earned return is below the earning sharing band of the gas rate stabilization plan and results in a rate increase of $2.8 million. Entergy Louisiana will make a compliance filing in April 2019 and rates will be implemented during the first billing cycle of May 2019.

Filings with the MPSC (Entergy Mississippi)

Formula Rate Plan Filings

In March 2016, Entergy Mississippi submitted its formula rate plan 2016 test year filing showing Entergy Mississippi’s projected earned return for the 2016 calendar year to be below the formula rate plan bandwidth. The filing showed a $32.6 million rate increase was necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 9.96%, within the formula rate plan bandwidth. In June 2016 the MPSC approved Entergy Mississippi’s joint stipulation with the Mississippi Public Utilities Staff. The joint stipulation provided for a total revenue increase of $23.7 million. The revenue increase included a $19.4 million increase through the formula rate plan, resulting in a return on common equity point of adjustment of 10.07%. The revenue increase also included $4.3 million in incremental ad valorem tax expenses to be collected through an updated ad valorem tax adjustment rider. The revenue increase and ad valorem tax adjustment rider were effective with the July 2016 bills.

In March 2017, Entergy Mississippi submitted its formula rate plan 2017 test year filing and 2016 look-back filing showing Entergy Mississippi’s earned return for the historical 2016 calendar year and projected earned return for the 2017 calendar year to be within the formula rate plan bandwidth, resulting in no change in rates. In June 2017, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a stipulation that confirmed that Entergy Mississippi’s earned returns for both the 2016 look-back filing and 2017 test year were within the respective formula rate plan bandwidths. In June 2017 the MPSC approved the stipulation, which resulted in no change in rates.

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.

Entergy Mississippi’s formula rate plan includes a look-back evaluation report filing in March 2019 that will compare actual 2018 results to the performance-adjusted allowed return on rate base.  In fourth quarter 2018, Entergy Mississippi recorded a provision of $9.3 million that reflects the estimate of the difference between the 2018 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 October 2018, Entergy Mississippi proposed revisions to its formula rate plan that would provide for a mechanism, the interim capacity rate adjustment mechanism, in the formula rate plan 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 additions, such as the Sunflower Solar Facility, that are approved by the MPSC.

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

As a provision of the settlement agreement approved by the City Council in May 2015 providing for the transfer from Entergy Louisiana to Entergy New Orleans of certain assets that supported the provision of service to Entergy Louisiana’s customers in Algiers, it was agreed that, with limited exceptions, no action may be taken with respect to Entergy New Orleans’s base rates until rates are implemented from a base rate case that must be filed for its electric and gas operations in 2018. This provision eliminated the formula rate plan applicable to Algiers operations. The limited exceptions included continued implementation of the then-remaining two years of the four-year phased-in rate increase for the Algiers area and certain exceptional cost increases or decreases in the base revenue requirement. An additional provision of the settlement agreement allowed for continued recovery of the revenue requirement associated with the capacity and energy from Ninemile 6 received by Entergy New Orleans under a power purchase agreement with Entergy Louisiana (Algiers PPA). The settlement authorized Entergy New Orleans to recover the remaining revenue requirement related to the Algiers PPA through base rates charged to Algiers customers. The settlement also provided for continued implementation of the Algiers MISO recovery rider.

In addition to the Algiers PPA, Entergy New Orleans has a separate power purchase agreement with Entergy Louisiana for 20% of the capacity and energy from Ninemile 6 (Ninemile PPA), which commenced operation in December 2014. Initially, recovery of the non-fuel costs associated with the Ninemile PPA was authorized through a special Ninemile 6 rider billed only to Entergy New Orleans customers outside of Algiers.

In August 2015, Entergy New Orleans filed an application with the City Council seeking authorization to proceed with the purchase of Union Power Block 1, with an expected base purchase price of approximately $237 million, subject to adjustments, and seeking approval of the recovery of the associated costs. In November 2015 the City Council issued written resolutions and an order approving an agreement in principle between Entergy New Orleans and City Council advisors providing that the purchase of Union Power Block 1 and related assets by Entergy New Orleans is prudent and in the public interest. The City Council authorized expansion of the terms of the purchased power and capacity acquisition cost recovery rider to recover the non-fuel purchased power expense from Ninemile 6, the revenue requirement associated with the purchase of Power Block 1 of the Union Power Station, and a credit to customers of $400 thousand monthly beginning June 2016 in recognition of the decrease in other operation and maintenance expenses that would result with the deactivation of Michoud Units 2 and 3. In March 2016, Entergy New Orleans purchased Power Block 1 of the Union Power Station for approximately $237 million and initiated recovery of these costs with March 2016 bills. In July 2016, Entergy New Orleans and the City Council Utility Committee agreed to a temporary increase in the Michoud credit to customers to a total of $1.4 million monthly for August 2016 through December 2016.

A 2008 rate case settlement included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs.  The rate settlement provided an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provided a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs. In January 2015 the City Council approved funding for the Energy Smart program from April 2015 through March 2017 using the remainder of the approximately $12.8 million of 2014 rough production cost equalization funds, with any remaining costs being recovered through the fuel adjustment clause. This funding methodology was modified in November 2015 when the City Council directed Entergy New Orleans to use a combination of guaranteed customer savings related to a prior agreement with the City Council and rough production cost equalization funds to cover program costs prior to recovering any costs through the fuel adjustment clause. In April 2017 the City Council approved an implementation plan for the Energy Smart program from April 2017 through December 2019. The City Council directed that the $11.8 million balance reported for Energy Smart funds be used to continue funding the program for Entergy New Orleans’s legacy customers and that the Energy Smart Algiers program continue to be funded through the Algiers fuel adjustment clause, until additional customer funding is required for the legacy customers. In September 2017, Entergy New Orleans filed a supplemental plan and proposed several options for an interim cost recovery mechanism necessary to recover program costs during the period between when existing funds directed to Energy Smart programs are depleted and when new rates from the 2018 combined rate case, which includes a cost recovery mechanism for Energy Smart funding, take effect (estimated to be August 2019). In December 2017 the City Council approved an energy efficiency cost recovery rider as an interim funding mechanism for Energy Smart, subject to verification that no additional funding sources exist. In June 2018 the City Council also approved a resolution recommending that Entergy New Orleans allocate approximately $13.5 million of benefits resulting from the Tax Act to Energy Smart. Entergy New Orleans is seeking approval of a permanent and stable source of funding for Energy Smart as part of its base rate case filed in September 2018.

In September 2018, Entergy New Orleans filed an electric and gas base rate case with the City Council. The filing requests 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 requests 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 includes a proposed gas rate decrease of $142 thousand. Entergy New Orleans’s rates reflect 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 ending 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’s request for a change in rates is based on the projected twelve months ending December 31, 2018.

The filing’s major provisions include: (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 have recommended, among other things, overall rate reductions of approximately $33 million in electric rates and $3.8 million in gas rates. Certain intervenors have recommended overall rate reductions of up to approximately $49 million in electric rates and $5 million in gas rates. The procedural schedule calls for an evidentiary hearing to be held in June 2019.

Internal Restructuring

In July 2016, Entergy New Orleans filed an application with the City Council seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy New Orleans, Inc. to a new entity, which would ultimately be owned by an existing Entergy subsidiary holding company. In May 2017 the City Council adopted a resolution approving the proposed internal restructuring pursuant to an agreement in principle with the City Council advisors and certain intervenors. Pursuant to the agreement in principle, Entergy New Orleans would credit retail customers $10 million in 2017, $1.4 million in the first quarter of the year after the transaction closes, and $117,500 each month in the second year after the transaction closes until such time as new base rates go into effect as a result of the then-anticipated 2018 base rate case (which has subsequently been filed). Entergy New Orleans began crediting retail customers in June 2017. In June 2017 the FERC approved the transaction and, pursuant to the agreement in principle, Entergy New Orleans will provide additional credits to retail customers of $5 million in each of the years 2018, 2019, and 2020.

In November 2017, Entergy New Orleans undertook a multi-step restructuring, including the following:

• Entergy New Orleans, Inc. redeemed its outstanding preferred stock at a price of approximately $21 million, which included a call premium of approximately $819,000, plus any accumulated and unpaid dividends.

• Entergy New Orleans, Inc. converted from a Louisiana corporation to a Texas corporation.

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

• Entergy New Orleans, Inc. contributed the membership interests in Entergy New Orleans 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 New Orleans Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.

In December 2017, Entergy New Orleans, Inc. changed its name to Entergy Utility Group, Inc., and Entergy New Orleans Power then changed its name to Entergy New Orleans, LLC. Entergy New Orleans, LLC holds substantially all of the assets, and has assumed substantially all of the liabilities, of Entergy New Orleans, Inc. The restructuring was accounted for as a transaction between entities under common control.

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 electricity 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), 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 June 2017, Entergy Texas filed an application to amend its DCRF rider by increasing the total collection from $8.65 million to approximately $19 million. In July 2017, Entergy Texas, the PUCT staff, and the two other parties in the proceeding entered into an unopposed stipulation and settlement agreement resulting in an amended DCRF annual revenue requirement of $18.3 million. In September 2017 the PUCT issued its final order approving the unopposed stipulation and settlement agreement. The amended DCRF rider rates became effective for usage on and after September 1, 2017. DCRF rates were set to zero upon implementation of new base rates on October 17, 2018, as described above in the discussion of the 2018 base rate case.

Transmission Cost Recovery Factor (TCRF) Rider

In September 2015, Entergy Texas filed for a TCRF rider requesting a $13 million increase, incremental to base rates. Testimony was filed in November 2015, with the PUCT staff and other parties proposing various disallowances involving, among other things, MISO charges, vegetation management costs, and bad debt expenses that would reduce the requested increase by approximately $2 million. In addition to those recommended disallowances, a number of parties recommended that Entergy Texas’s request be reduced by an additional $3.4 million to account for load growth since base rates were last set. In February 2016 a State Office of Administrative Hearings ALJ issued a proposal for decision recommending that the PUCT disallow approximately $2 million from Entergy Texas’s $13 million request, but recommending that the PUCT not accept the load growth offset. In June 2016 the PUCT indicated that it would take up in a future rulemaking project the issue of whether a load growth adjustment should apply to a TCRF. In July 2016 the PUCT issued an order generally accepting the proposal for decision but declining to adjust the TCRF baseline in two instances as recommended by the ALJ, which resulted in a total annual allowance of approximately $10.5 million. The PUCT also ordered its staff and Entergy Texas to track all spare autotransformer transfers going forward so that it could address the appropriate accounting treatment and prudence of such transfers in Entergy Texas’s next base rate case. Entergy Texas implemented the TCRF rider beginning with September 2016 bills.

In September 2016, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The proposed amended TCRF rider was designed to collect approximately $29.5 million annually from Entergy Texas’s retail customers. This amount included the approximately $10.5 million annually that Entergy Texas was previously authorized to collect through the TCRF rider, as discussed above. In December 2016, concurrent with the 2016 fuel reconciliation stipulation and settlement agreement discussed above, Entergy Texas and the PUCT staff reached a settlement agreeing to the amended TCRF annual revenue requirement of $29.5 million. As discussed above, the terms of the two settlements are interdependent. The PUCT approved the settlement and issued a final order in March 2017. Entergy Texas implemented the amended TCRF rider beginning with bills covering usage on and after March 20, 2017. TCRF rates were set to zero upon implementation of new base rates on October 17, 2018, as described above in the 2018 base rate case discussion.

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. The proceeding is currently ongoing at the PUCT.

Advanced Metering Infrastructure (AMI) Filings

Entergy Arkansas

In September 2016, Entergy Arkansas filed an application seeking a finding from the APSC that Entergy Arkansas’s deployment of AMI is in the public interest. Entergy Arkansas proposed to replace existing meters with advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Arkansas’s modernized power grid. The filing included an estimate of implementation costs for AMI of $208 million. The filing identified a number of quantified and unquantified benefits, and Entergy Arkansas provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal net benefit to customers of $406 million. Entergy Arkansas also sought to continue to include in rate base the remaining book value of existing meters, which was approximately $57 million at December 31, 2015, that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Arkansas proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Deployment of the communications network began in 2018. Entergy Arkansas proposed to include the AMI deployment costs and the quantified benefits in future formula rate plan filings, and the 2018 costs were approved in the 2017 formula rate plan filing. In August 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement. In October 2017 the APSC issued an order finding that Entergy Arkansas’s AMI deployment is in the public interest and approving the settlement agreement subject to a minor modification. Entergy Arkansas expects to recover the undepreciated balance of its existing meters through a regulatory asset to be amortized over 15 years.

Entergy Louisiana

In November 2016, Entergy Louisiana filed an application seeking a finding from the LPSC that Entergy Louisiana’s deployment of advanced electric and gas metering infrastructure is in the public interest. Entergy Louisiana proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Louisiana’s modernized power grid. The filing included an estimate of implementation costs for AMI of $330 million. The filing identified a number of quantified and unquantified benefits, and Entergy Louisiana provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $607 million. Entergy Louisiana also sought to continue to include in rate base the remaining book value, approximately $92 million at December 31, 2015, of the existing electric meters and also to depreciate those assets using current depreciation rates. Entergy Louisiana proposed a 15-year useful life for the new advanced meters, the three-year deployment of which began in 2019. Deployment of the communications network began in 2018. Entergy Louisiana proposed to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022. The parties reached an uncontested stipulation permitting implementation of Entergy Louisiana’s proposed AMI system, with modifications to the proposed customer charge. In July 2017 the LPSC approved the stipulation. Entergy Louisiana expects to recover the undepreciated balance of its existing meters through a regulatory asset to be amortized at current depreciation rates.

Entergy Mississippi

In November 2016, Entergy Mississippi filed an application seeking an order from the MPSC granting a certificate of public convenience and necessity and finding that Entergy Mississippi’s deployment of AMI is in the public interest. Entergy Mississippi proposed to replace existing meters with advanced meters that enable two-way data communication; to design and build a secure and reliable network to support such communications; and to implement support systems. AMI is intended to serve as the foundation of Entergy Mississippi’s modernized power grid. The filing included an estimate of implementation costs for AMI of $132 million. The filing identified a number of quantified and unquantified benefits, and Entergy Mississippi provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal benefit to customers of $496 million over a 15-year period, which when netted against the costs of AMI results in $183 million of net customer benefits. Entergy Mississippi also sought to continue to include in rate base the remaining book value, approximately $56 million at December 31, 2015, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Mississippi proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019, subject to approval by the MPSC. Deployment of the communications network began in 2018. Entergy Mississippi proposed to include the AMI deployment costs and the quantified benefits in existing rate mechanisms, primarily through future formula rate plan filings and/or future energy cost recovery rider schedule re-determinations, as applicable. In May 2017 the Mississippi Public Utilities Staff and Entergy Mississippi entered into and filed a joint stipulation supporting Entergy Mississippi’s filing, and the MPSC issued an order approving the filing without material changes, finding that Entergy Mississippi’s deployment of AMI is in the public interest and granting a certificate of public convenience and necessity. The MPSC order also confirmed that Entergy Mississippi shall continue to include in rate base the remaining book value of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. In June 2018, as part of the order approving the joint stipulation between the Mississippi Public Utilities Staff and Entergy Mississippi addressing Entergy Mississippi’s 2018 formula rate plan evaluation report and the ratemaking effects of the Tax Act, the MPSC approved the acceleration of the recovery of substantially all of Entergy Mississippi’s existing customer meters in anticipation of AMI deployment.

Entergy New Orleans

In October 2016, Entergy New Orleans filed an application seeking a finding from the City Council that Entergy New Orleans’s deployment of advanced electric and gas metering infrastructure is in the public interest.  Entergy New Orleans proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems.  AMI is intended to serve as the foundation of Entergy New Orleans’s modernized power grid.  The filing included an estimate of implementation costs for AMI of $75 million. The filing identified a number of quantified and unquantified benefits, and Entergy New Orleans provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $101 million.  Entergy New Orleans also sought to continue to include in rate base the remaining book value, approximately $21 million at December 31, 2015, of the existing electric meters and also to depreciate those assets using current depreciation rates.  Entergy New Orleans proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which began in 2019.  Deployment of the information technology infrastructure began in 2017 and deployment of the communications network began in 2018.  Entergy New Orleans proposed to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022.  The City Council’s advisors filed testimony in May 2017 recommending the adoption of AMI subject to certain modifications, including the denial of Entergy New Orleans’s proposed customer charge as a cost recovery mechanism. In January 2018 a settlement was reached between the City Council’s advisors and Entergy New Orleans. In February 2018 the City Council approved the settlement, which deferred cost recovery to the 2018 Entergy New Orleans rate case, but also stated that an adjustment for 2018-2019 AMI costs can be filed in the rate case and that, for all subsequent AMI costs, the mechanism to be approved in the 2018 rate case will allow for the timely recovery of such costs. In April 2018 the City Council adopted a resolution directing Entergy New Orleans to explore the options for accelerating the deployment of AMI. In June 2018 the City Council approved a one-year acceleration of AMI in its service area for an incremental $4.4 million.

Entergy Texas

In April 2017 the Texas legislature enacted legislation that extends statutory support for AMI deployment to Entergy Texas and directs that if Entergy Texas elects to deploy AMI, it shall do so as rapidly as practicable. In July 2017, Entergy Texas filed an application seeking an order from the PUCT approving Entergy Texas’s deployment of AMI. Entergy Texas proposed to replace existing meters with advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Texas’s modernized power grid. The filing included an estimate of implementation costs for AMI of $132 million. The filing identified a number of quantified and unquantified benefits, with Entergy Texas showing that its AMI deployment is expected to produce nominal net operational cost savings to customers of $33 million. Entergy Texas also sought to continue to include in rate base the remaining book value, approximately $41 million at December 31, 2016, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Texas proposed a seven-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Entergy Texas also proposed a surcharge tariff to recover the reasonable and necessary costs it has and will incur under the deployment plan for the full deployment of advanced meters. Further, Entergy Texas sought approval of fees that would be charged to customers who choose to opt out of receiving service through an advanced meter and instead receive electric service with a non-standard meter. In October 2017, Entergy Texas and other parties entered into and filed an unopposed stipulation and settlement agreement, permitting deployment of AMI with limited modifications. The PUCT approved the stipulation and settlement agreement in December 2017. Entergy Texas implemented the AMI surcharge tariff beginning with January 2018 bills. As of December 31, 2018, Entergy Texas has a regulatory liability related to the collection of the surcharge from customers. Consistent with the approval, deployment of the communications network began in 2018 and deployment of the advanced meters will begin in March 2019. Entergy Texas expects to recover the remaining net book value of its existing meters through a regulatory asset to be amortized at current depreciation rates.

System Agreement Cost Equalization Proceedings

Prior to its final termination in 2016, the Utility operating companies historically engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement.  Entergy Arkansas terminated its participation in the System Agreement in December 2013. Entergy Mississippi terminated its participation in the System Agreement in November 2015. The System Agreement terminated with respect to its remaining participants in August 2016.

Although the System Agreement has terminated, certain of the Utility operating companies’ retail regulators continue to pursue litigation involving the System Agreement at the FERC and in federal courts.  The proceedings include challenges to the allocation of costs as defined by the System Agreement and other matters.

In June 2005 the FERC issued a decision in System Agreement litigation that had been commenced by the LPSC, and essentially affirmed its decision in a December 2005 order on rehearing.  The decision included, among other things:

• The FERC’s conclusion that the System Agreement no longer roughly equalized total production costs among the Utility operating companies.

• In order to reach rough production cost equalization, the FERC imposed a bandwidth remedy by which each company’s total annual production costs would have to be within +/- 11% of Entergy System average total annual production costs.

• In calculating the production costs for this purpose under the FERC’s order, output from the Vidalia hydroelectric power plant would not reflect the actual Vidalia price for the year but be priced at that year’s average price paid by Entergy Louisiana for the exchange of electric energy under Service Schedule MSS-3 of the System Agreement, thereby reducing the amount of Vidalia costs reflected in the comparison of the Utility operating companies’ total production costs.

• The remedy ordered by the FERC in 2005 required no refunds and became effective based on calendar year 2006 production costs with the first reallocation payments made in 2007.

The FERC’s decision reallocated total production costs of the Utility operating companies whose relative total production costs expressed as a percentage of Entergy System average production costs are outside an upper or lower bandwidth.  This was accomplished by payments from Utility operating companies whose production costs were more than 11% below Entergy System average production costs to Utility operating companies whose production costs were more than the Entergy System average production cost, with payments going first to those Utility operating companies whose total production costs were farthest above the Entergy System average.

The LPSC, APSC, MPSC, and the Arkansas Electric Energy Consumers appealed the FERC’s December 2005 decision to the United States Court of Appeals for the D.C. Circuit.  Entergy and the City of New Orleans intervened in the various appeals.  The D.C. Circuit issued its decision in April 2008.  The D.C. Circuit concluded that the FERC’s orders had failed to adequately explain both its conclusion that it was prohibited from ordering refunds for the 20-month period from September 13, 2001 - May 2, 2003 and its determination to implement the bandwidth remedy commencing on January 1, 2006, rather than June 1, 2005.  The D.C. Circuit remanded the case to the FERC for further proceedings on those two issues.

In October 2011 the FERC issued an order addressing the D.C. Circuit remand on the two issues.  On the first issue, the FERC concluded that it did have the authority to order refunds, but decided that it would exercise its equitable discretion and not require refunds for the 20-month period from September 13, 2001 - May 2, 2003.  Because the ruling on refunds relied on findings in the interruptible load proceeding, which is discussed in a separate section below, the FERC concluded that this refund ruling will be held in abeyance pending the outcome of the rehearing requests in the interruptible load proceeding.  On the second issue, the FERC reversed its prior decision and ordered that the prospective bandwidth remedy begin on June 1, 2005 (the date of its initial order in the proceeding) rather than January 1, 2006, as it had previously ordered.  Pursuant to the October 2011 order, Entergy was required to calculate bandwidth payments for the period June - December 2005 utilizing the bandwidth formula tariff prescribed by the FERC that was filed in a December 2006 compliance filing and accepted by the FERC in an April 2007 order.  

In March 2015, in light of a December 2014 decision by the D.C. Circuit in the interruptible load proceeding, Entergy filed with the FERC a motion to establish a briefing schedule on refund issues and an initial brief addressing refund issues. The initial brief argued that the FERC, in response to the D.C. Circuit decision, should clarify its policy on refunds and find that refunds are not required in this proceeding. In October 2015 the FERC issued three orders related to the commencement of the remedy on June 1, 2005 and the inclusion of interest for the period June 1, 2005 through December 31, 2005. Specifically, the FERC rejected Entergy’s request for rehearing of its decision to include interest for the seven-month period. The FERC also rejected Entergy’s request for rehearing of the order rejecting the compliance filing with regard to the issue of interest. Finally, the FERC set for hearing and settlement procedures the 2014 compliance filing that included the bandwidth calculation for the seven months June 1, 2005 through December 31, 2005. In setting the compliance filing for hearing, the FERC rejected the APSC’s protest that Entergy Arkansas should not be subject to the filing because Entergy Arkansas would be making the payments during a period following its exit from the System Agreement. In January 2018 the D.C. Circuit affirmed the FERC decision that Entergy Arkansas was subject to the filing.

In December 2011, Entergy filed with the FERC its compliance filing that provided the payments and receipts among the Utility operating companies pursuant to the FERC’s October 2011 order.  The APSC, the LPSC, the PUCT, and other parties intervened in the December 2011 compliance filing proceeding, and the APSC and the LPSC also filed protests. The filing showed the following payments/receipts among the Utility operating companies:

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$156
Entergy Louisiana	($75)
Entergy Mississippi	($33)
Entergy New Orleans	($5)
Entergy Texas	($43)

Entergy Arkansas made its payment in January 2012.  In February 2012, Entergy Arkansas filed for an interim adjustment to its production cost allocation rider requesting that the $156 million be collected from customers over the 22-month period from March 2012 through December 2013.  In March 2012 the APSC issued an order stating that the payment can be recovered from retail customers through the production cost allocation rider, subject to refund.  The LPSC and the APSC requested rehearing of the FERC’s October 2011 order.  

In February 2014 the FERC issued a rehearing order addressing its October 2011 order. The FERC denied the LPSC’s request for rehearing on the issues of whether the bandwidth remedy should be made effective earlier than June 1, 2005, and whether refunds should be ordered for the 20-month refund effective period. The FERC granted the LPSC’s rehearing request on the issue of interest on the bandwidth payments/receipts for the June - December 2005 period, requiring that interest be accrued from June 1, 2006 until the date those bandwidth payments/receipts are made. Also in February 2014 the FERC issued an order rejecting the December 2011 compliance filing that calculated the bandwidth payments/receipts for the June - December 2005 period. The FERC order required a new compliance filing that calculates the bandwidth payments/receipts for the June - December 2005 period based on monthly data for the seven individual months including interest pursuant to the February 2014 rehearing order. Entergy sought rehearing of the February 2014 order with respect to the FERC’s determinations regarding interest. In April 2014 the LPSC filed a petition for review of the FERC’s October 2011 and February 2014 orders with the U.S. Court of Appeals for the D.C. Circuit. In August 2017 the D.C. Circuit issued a decision denying the LPSC’s appeal of the FERC’s October 2011 and February 2014 orders. On the issue of the FERC’s implementation of the prospective remedy as of June 2005 and whether the bandwidth remedy should be extended for an additional 17 months in years 2004-2005, the D.C. Circuit affirmed the FERC’s implementation of the remedy and denied the LPSC’s appeal. On the issue of whether the operating companies should be required to issue refunds for the 20-month period from September 2001 to May 2003, the D.C. Circuit granted the FERC’s request for agency reconsideration and remanded that issue back to the FERC for further proceedings as requested by all parties to the appeal. In response to the D.C. Circuit’s remand, various parties filed briefs with the FERC addressing whether the FERC should require the Utility operating companies to issue refunds for the 20-month refund period from September 2001 to May 2003. The LPSC has argued in favor of such remands and Entergy has opposed the LPSC’s request. The briefing was completed in September 2018 and the matter is pending before the FERC.

In April and May 2014, Entergy filed with the FERC an updated compliance filing that provided the payments and receipts among the Utility operating companies pursuant to the FERC’s February 2014 orders.  The filing showed the following net payments and receipts, including interest, among the Utility operating companies:

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$68
Entergy Louisiana	($10)
Entergy Mississippi	($11)
Entergy New Orleans	$2
Entergy Texas	($49)

These payments were made in May 2014. The LPSC, City Council, and APSC filed protests.

The hearing on the bandwidth calculation for the seven months June 1, 2005 through December 31, 2005 occurred in July 2016. The presiding judge issued an initial decision in November 2016. In the initial decision, the presiding judge agreed with the Utility operating companies’ position that: (1) interest on the bandwidth payments for the 2005 test period should be accrued from June 1, 2006 until the date that the bandwidth payments for that calculation are paid, which is consistent with how the Utility operating companies performed the calculation; and (2) a portion of Entergy Louisiana’s 2001-vintage Louisiana state net operating loss accumulated deferred income tax that results from the Vidalia tax deduction should be excluded from the 2005 test period bandwidth calculation. Various participants filed briefs on exceptions and/or briefs opposing exceptions related to the initial decision, including the LPSC, the APSC, the FERC trial staff, and Entergy Services. In May 2018 the FERC issued an order affirming the initial decision and ordered a comprehensive recalculation of the bandwidth payments/receipts for the seven months June 1, 2005 through December 31, 2005 and a recalculation of the 2006 and 2007 test years as a result of limited revisions. Entergy filed the comprehensive recalculation of the bandwidth payments/receipts for the seven months June 1, 2005 through December 31, 2005 and the 2006 and 2007 test years in July 2018. The filing shows the additional following payments and receipts among the Utility operating companies:

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	($4)
Entergy Louisiana	($23)
Entergy Mississippi	$16
Entergy New Orleans	$5
Entergy Texas	$6

These payments were made in July 2018. In January 2019 the FERC denied the LPSC’s request for rehearing of the May 2018 order.

Rough Production Cost Equalization Rates

Each May from 2007 through 2016 Entergy filed with the FERC the rates to implement the FERC’s orders in the System Agreement proceeding.  These filings showed the following payments/receipts among the Utility operating companies were necessary to achieve rough production cost equalization as defined by the FERC’s orders:

	Payments (Receipts)
	2007			2008			2009			2010			2011			2012			2013			2014
	(In Millions)
Entergy Arkansas		$252			$252			$390			$41			$77			$41			$—			$—
Entergy Louisiana		($211	)		($160	)		($247	)		($22	)		($12	)		($41	)		$—			$—
Entergy Mississippi		($41	)		($20	)		($24	)		($19	)		($40	)		$—			$—			$—
Entergy New Orleans		$—			($7	)		$—			$—			($25	)		$—			($15	)		($15	)
Entergy Texas		($30	)		($65	)		($119	)		$—			$—			$—			$15			$15

The Utility operating companies recorded accounts payable or accounts receivable to reflect the rough production cost equalization payments and receipts required to implement the FERC’s remedy.  When accounts payable were recorded, a corresponding regulatory asset was recorded for the right to collect the payments from customers. When accounts receivable were recorded, a corresponding regulatory liability was recorded for the obligations to pass the receipts on to customers.  No payments were required in 2016 or 2015 to implement the FERC’s remedy based on calendar year 2015 production costs and 2014 production costs, respectively. The System Agreement terminated in August 2016.

The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas.  Entergy Texas recovered its 2013 rough production cost equalization payment over three years beginning April 2014. Entergy Texas included its 2014 rough production cost equalization payment as a component of an interim fuel refund made in 2014. Management believes that any changes in the allocation of production costs resulting from the FERC’s decision and related retail proceedings should result in similar rate changes for retail customers, subject to specific circumstances that have caused trapped costs.

The following rough production cost equalization rate proceedings are still ongoing or were ongoing during the period 2016-2018.

2010 Rate Filing Based on Calendar Year 2009 Production Costs

In May 2010, Entergy filed with the FERC the 2010 rates in accordance with the FERC’s orders in the System Agreement proceeding, and supplemented the filing in September 2010.  Several parties intervened in the proceeding at the FERC, including the LPSC and the City Council, which also filed protests.  In July 2010 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2010, subject to refund.  After an abeyance of the proceeding schedule, a hearing was held in March 2014 and in December 2015 the FERC issued an order. Among other things, the December 2015 order directed Entergy to submit a compliance filing. In January 2016 the LPSC, the APSC, and Entergy filed requests for rehearing of the FERC’s December 2015 order. In February 2016, Entergy submitted the compliance filing ordered in the December 2015 order.  The result of the true-up payments and receipts for the recalculation of production costs resulted in the following payments/receipts among the Utility operating companies:

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$2
Entergy Louisiana	$6
Entergy Mississippi	($4)
Entergy New Orleans	($1)
Entergy Texas	($3)

In September 2016 the FERC accepted the February 2016 compliance filing subject to a further compliance filing made in November 2016. The further compliance filing was required as a result of an order issued in September 2016 ruling on the January 2016 rehearing requests filed by the LPSC, the APSC, and Entergy. In the order addressing the rehearing requests, the FERC granted the LPSC’s rehearing request and directed that interest be calculated on the payment/receipt amounts. The FERC also granted the APSC’s and Entergy’s rehearing request and ordered the removal of both securitized asset accumulated deferred income taxes and contra-securitization accumulated deferred income taxes from the calculation. In November 2016, Entergy submitted its compliance filing in response to the FERC’s order on rehearing. The compliance filing included a revised calculation of the bandwidth true-up payments and receipts based on 2009 test year data and interest calculations. The LPSC protested the interest calculations. In November 2017 the FERC issued an order rejecting the November 2016 compliance filing. The FERC determined that the payments detailed in the November 2016 compliance filing did not include adequate interest for the payments from Entergy Arkansas to Entergy Louisiana because it did not include interest on the principal portion of the payment that was made in February 2016. In December 2017, Entergy recalculated the interest pursuant to the November 2017 order. As a result of the recalculations, Entergy Arkansas owed very minor payments to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.

2011 Rate Filing Based on Calendar Year 2010 Production Costs

In May 2011, Entergy filed with the FERC the 2011 rates in accordance with the FERC’s orders in the System Agreement proceeding.  Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest.  In July 2011 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2011, subject to refund. After an abeyance of the proceeding schedule, in December 2014 the FERC consolidated the 2011 rate filing with the 2012, 2013, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

2012 Rate Filing Based on Calendar Year 2011 Production Costs

In May 2012, Entergy filed with the FERC the 2012 rates in accordance with the FERC’s orders in the System Agreement proceeding.  Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest.  In August 2012 the FERC accepted Entergy’s proposed rates for filing, effective June 2012, subject to refund. After an abeyance of the proceeding schedule, in December 2014 the FERC consolidated the 2012 rate filing with the 2011, 2013, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

2013 Rate Filing Based on Calendar Year 2012 Production Costs

In May 2013, Entergy filed with the FERC the 2013 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest. The City Council intervened and filed comments related to including the outcome of a related FERC proceeding in the 2013 cost equalization calculation. In August 2013 the FERC issued an order accepting the 2013 rates, effective June 1, 2013, subject to refund. After an abeyance of the proceeding schedule, in December 2014 the FERC consolidated the 2013 rate filing with the 2011, 2012, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

2014 Rate Filing Based on Calendar Year 2013 Production Costs

In May 2014, Entergy filed with the FERC the 2014 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest. The City Council intervened and filed comments. In December 2014 the FERC issued an order accepting the 2014 rates, effective June 1, 2014, subject to refund, set the proceeding for hearing procedures, and consolidated the 2014 rate filing with the 2011, 2012, and 2013 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

Consolidated 2011, 2012, 2013, and 2014 Rate Filing Proceedings

As discussed above, in December 2014 the FERC consolidated the 2011, 2012, 2013, and 2014 rate filings for settlement and hearing procedures. In May 2015, Entergy filed direct testimony in the consolidated rate filings and the LPSC filed direct testimony concerning its complaint proceeding that is consolidated with the rate filings, challenging certain components of the pending bandwidth calculations for prior years. Hearings occurred in November 2015, and the ALJ issued an initial decision in July 2016. In the initial decision, the ALJ generally agreed with Entergy’s bandwidth calculations with one exception on the accounting related to the Waterford 3 sale/leaseback. In March 2018 the FERC issued an order affirming the initial decision. In April 2018 the LPSC requested rehearing of the FERC’s March 2018 order affirming the ALJ’s initial decision. Entergy filed in May 2018 the bandwidth true-up payments and receipts for the 2011-2014 rate filings (table does not net to zero due to rounding):

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$3
Entergy Louisiana	$3
Entergy Mississippi	($1)
Entergy New Orleans	$1
Entergy Texas	($5)

These payments were made in May 2018. The LPSC request for rehearing is pending.

Utility Operating Company Termination of System Agreement Participation

Entergy Arkansas and Entergy Mississippi ceased participating in the System Agreement effective December 18, 2013 and November 7, 2015, respectively. Entergy Louisiana, Entergy New Orleans, and Entergy Texas terminated participation in the System Agreement on August 31, 2016, which resulted in the termination of the System Agreement in its entirety pursuant to a settlement agreement approved by the FERC in December 2015.

In December 2013 the FERC set one issue for hearing involving whether and how the benefits associated with settlement with Union Pacific regarding certain coal delivery issues should be allocated among Entergy Arkansas and the other Utility operating companies post-termination of the System Agreement. In December 2014 a FERC ALJ issued an initial decision finding that Entergy Arkansas would realize benefits after December 18, 2013 from the 2008 settlement agreement between Entergy Services, Entergy Arkansas, and Union Pacific, related to certain coal delivery issues. In March 2016 the FERC issued an opinion affirming the December 2014 initial decision with regard to the determination that there were benefits related to the Union Pacific settlement, which were realized post-Entergy Arkansas’s December 2013 withdrawal from the System Agreement, that should be shared with the other Utility operating companies utilizing the methodology proposed by the MPSC and trued-up to actual coal volumes purchased. In May 2016, Entergy made a compliance filing that provided the calculation of Union Pacific settlement benefits utilizing the methodology adopted by the initial decision, trued-up for the actual volumes of coal purchased. The payments were made in May 2016. In August 2016 the FERC issued an order accepting Entergy’s compliance filing. Also in August 2016 the APSC filed a petition for review of the FERC’s March 2016 and August 2016 orders with the U.S. Court of Appeals for the D.C. Circuit. In June 2018 the D.C. Circuit denied the APSC’s petition.

Interruptible Load Proceeding

In April 2007 the U.S. Court of Appeals for the D.C. Circuit issued its opinion in the LPSC’s appeal of the FERC’s March 2004 and April 2005 orders related to the treatment under the System Agreement of the Utility operating companies’ interruptible loads.  In its opinion the D.C. Circuit concluded that the FERC: (1) acted arbitrarily and capriciously by allowing the Utility operating companies to phase-in the effects of the elimination of the interruptible load over a 12-month period of time; (2) failed to adequately explain why refunds could not be ordered under Section 206(c) of the Federal Power Act; and (3) exercised appropriately its discretion to defer addressing the cost of sulfur dioxide allowances until a later time.  The D.C. Circuit remanded the matter to the FERC for a more considered determination on the issue of refunds.  The FERC issued its order on remand in September 2007, in which it directed Entergy to make a compliance filing removing all interruptible load from the computation of peak load responsibility commencing April 1, 2004 and to issue any necessary refunds to reflect this change.  In addition, the order directed the Utility operating companies to make refunds for the period May 1995 through July 1996.  In November 2007 the Utility operating companies filed a refund report describing the refunds to be issued pursuant to the FERC’s orders.  The LPSC filed a protest to the refund report in December 2007.  The refunds were made in October 2008 by the Utility operating companies that owed refunds to the Utility operating companies that were due refunds under the decision.  The APSC and the Utility operating companies appealed the FERC decisions to the D.C. Circuit.

Following the filing of petitioners’ initial briefs, the FERC filed a motion requesting the D.C. Circuit hold the appeal of the FERC’s decisions ordering refunds in the interruptible load proceeding in abeyance and remand the record to the FERC.  The D.C. Circuit granted the FERC’s unopposed motion in June 2009.  In December 2009 the FERC established a paper hearing to determine whether the FERC had the authority and, if so, whether it would be appropriate to order refunds resulting from changes in the treatment of interruptible load in the allocation of capacity costs by the Utility operating companies.  In August 2010 the FERC issued an order stating that it has the authority and refunds are appropriate.  The APSC, the MPSC, and Entergy requested rehearing of the FERC’s decision.  In June 2011 the FERC issued an order granting rehearing in part and denying rehearing in part, in which the FERC determined to invoke its discretion to deny refunds.  The FERC held that in this case where “the Entergy system as a whole collected the proper level of revenue, but, as was later established, incorrectly allocated peak load responsibility among the various Entergy operating companies….the Commission will apply here our usual practice in such cases, invoking our equitable discretion to not order refunds, notwithstanding our authority to do so.”  The LPSC requested rehearing of the FERC’s June 2011 decision.  In July 2011 the refunds made in the fourth quarter 2008 described above were reversed. In October 2011 the FERC issued an “Order Establishing Paper Hearing” inviting parties that oppose refunds to file briefs within 30 days addressing the LPSC’s argument that FERC precedent supports refunds under the circumstances present in this proceeding.  Parties that favor refunds were then invited to file reply briefs within 21 days of the date that the initial briefs were due.  

In March 2013 the FERC issued an order denying the LPSC’s request for rehearing of the FERC’s June 2011 order wherein the FERC concluded it would exercise its discretion and not order refunds in the interruptible load proceeding. Based on its review of the LPSC’s request for rehearing and the briefs filed as part of the paper hearing established in October 2011, the FERC affirmed its earlier ruling and declined to order refunds under the circumstances of the case. In May 2013 the LPSC filed a petition for review with the U.S. Court of Appeals for the D.C. Circuit seeking review of FERC orders in the interruptible load proceeding that concluded that the FERC would exercise its discretion and not order refunds in the proceeding. Oral argument was held on the appeal in the D.C. Circuit in September 2014. In December 2014 the D.C. Circuit issued an order on the LPSC’s appeal and remanded the case back to the FERC. The D.C. Circuit rejected the LPSC’s argument that there is a presumption in favor of refunds, but it held that the FERC had not adequately explained its decision to deny refunds and directed the FERC “to consider the relevant factors and weigh them against one another.” In March 2015, Entergy filed with the FERC an initial brief on remand to address the December 2014 decision by the D.C. Circuit. The initial brief on remand argued that the FERC, in response to the D.C. Circuit decision, should clarify its policy on refunds and find that refunds are not required in the interruptible load proceeding.

In April 2016 the FERC issued an order on remand that addressed the December 2014 decision by the D.C. Circuit in the interruptible load proceeding. The order on remand affirmed the FERC’s denial of refunds for the 15-month refund effective period. The FERC explained and clarified its policies regarding refunds and concluded that the evidence in the record demonstrated that the relevant equitable factors favored not requiring refunds in this case. The FERC also noted that, under Section 206(c) of the Federal Power Act, in a Section 206 proceeding involving two or more electric utility companies of a registered holding company system, the FERC may order refunds only if it determines the refunds would not cause the registered holding company to experience any reduction in revenues resulting from an inability of an electric utility company in the system to recover the resulting increase in costs. The FERC stated it was not able to find that the Entergy system would not experience a reduction in revenues if refunds were awarded in this proceeding, which further supported the denial of refunds. In May 2016 the LPSC filed a request for rehearing of the FERC’s April 2016 order. In September 2016 the FERC issued an order denying the LPSC’s request for rehearing and reaffirming its denial of refunds for the 15-month refund effective period. The LPSC appealed the April and September 2016 orders to the U.S. Court of Appeals for the D.C. Circuit. In March 2018 the D.C. Circuit issued an order denying the LPSC’s appeal and affirming the FERC’s decision that it would be inequitable to award refunds in the proceeding. In April 2018 the LPSC sought rehearing en banc of the D.C. Circuit’s order denying the LPSC’s appeal. In May 2018 the D.C. Circuit denied the LPSC’s rehearing request. In August 2018 the LPSC filed with the Supreme Court of the United States a petition for a writ of certiorari to review the judgment of the D.C. Circuit. In November 2018 the Supreme Court of the United States denied the LPSC’s petition for a writ of certiorari to review the judgment of the D.C. Circuit, effectively terminating the interruptible load proceeding.

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’s 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’s appeal and held all of the appeals in abeyance pending final resolution of the related proceeding before the FERC.

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 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. 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.

Complaints Against System Energy

Return on Equity 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 the FERC to institute 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. System Energy is recording a provision against revenue for the potential outcome of this proceeding. In September 2017 the FERC established a refund effective date of January 23, 2017, consolidated the return on equity complaint with the proceeding described in Unit Power Sales Agreement below, 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 effective date 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 System Energy’s return on equity, with a refund effective date of April 2018. The portion of the LPSC’s complaint dealing with return on equity was subsequently consolidated with the APSC and MPSC complaint for hearing. The consolidated hearing has been scheduled for September 2019, and the parties are required to address 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 complaint, and System Energy submitted a response to the amended complaint in October 2018. In January 2019 the FERC set the amended complaint for settlement and hearing proceedings.

Grand Gulf Sale-leaseback Renewal Complaint

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 2018. The hearing has been scheduled for November 2019.

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 proposed amendments would result in lower charges to the Utility operating companies that buy capacity and energy from System Energy under the Unit Power Sales Agreement. The proposed changes are 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. System Energy requested that the FERC accept the amendments effective October 1, 2017.

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 propose 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. The FERC also consolidated the Unit Power Sales Agreement amendment proceeding with the proceeding described in“Return on Equity Complaints” above, and directed the parties to engage in settlement proceedings before an ALJ. 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.  The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages.  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.

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.  In February 2012, Entergy Louisiana sold 500,000 of its Class A preferred membership units in Entergy Holdings Company LLC, a wholly-owned Entergy subsidiary, to a third party in exchange for $51 million plus accrued but unpaid distributions on the units.  The 500,000 preferred membership units are mandatorily redeemable in January 2112.

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. As of April 30, 2016, Entergy Mississippi’s storm damage provision balance was less than $10 million, therefore Entergy Mississippi resumed billing the monthly storm damage provision effective with June 2016 bills. As of September 30, 2016, however, Entergy Mississippi’s storm damage provision balance exceeded $15 million. Accordingly the storm damage provision was reset to zero beginning with November 2016 bills. As of July 31, 2017, the balance in Entergy Mississippi’s accumulated storm damage provision was again less than $10 million, therefore Entergy Mississippi resumed billing the monthly storm damage provision effective with September 2017 bills. As of June 30, 2018, Entergy Mississippi’s storm damage provision balance exceeded $15 million. Accordingly the storm damage provision was reset to zero beginning with August 2018 bills.

Entergy New Orleans

In August 2012, Hurricane Isaac caused extensive damage to Entergy New Orleans’s service area. In January 2015 the City Council issued a resolution approving the terms of a joint agreement in principle filed by Entergy New Orleans, Entergy Louisiana, and the City Council Advisors determining, among other things, that Entergy New Orleans’s prudently-incurred storm recovery costs were $49.3 million, of which $31.7 million, net of reimbursements from the storm reserve escrow account, remained recoverable from Entergy New Orleans’s electric customers. The resolution also directed Entergy New Orleans to file an application to securitize the unrecovered City Council-approved storm recovery costs of $31.7 million pursuant to the Louisiana Electric Utility Storm Recovery Securitization Act (Louisiana Act 64). In addition, the resolution found that it was reasonable for Entergy New Orleans to include in the principal amount of its potential securitization the costs to fund and replenish Entergy New Orleans’s storm reserve in an amount that achieved the City Council-approved funding level of $75 million. In January 2015, in compliance with that directive, Entergy New Orleans filed with the City Council an application requesting that the City Council grant a financing order authorizing the financing of Entergy New Orleans’s storm costs, storm reserves, and issuance costs pursuant to Louisiana Act 64. In May 2015 the parties entered into an agreement in principle and the City Council issued a financing order authorizing Entergy New Orleans to issue storm recovery bonds in the aggregate amount of $98.7 million, including $31.8 million for recovery of Entergy New Orleans’s Hurricane Isaac storm recovery costs, including carrying costs, $63.9 million to fund and replenish Entergy New Orleans’s storm reserve, and approximately $3 million for estimated up-front financing costs associated with the securitization. See Note 5 to the financial statements for discussion of the issuance of the securitization bonds in July 2015.

New Nuclear Generation Development Costs

Entergy Louisiana

Entergy Louisiana and Entergy Gulf States Louisiana were developing a project option for new nuclear generation at River Bend.  In March 2010, Entergy Louisiana and Entergy Gulf States Louisiana filed with the LPSC seeking approval to continue the limited development activities necessary to preserve an option to construct a new unit at River Bend.  At its June 2012 meeting the LPSC voted to uphold an ALJ recommendation that the request of Entergy Louisiana and Entergy Gulf States Louisiana be declined on the basis that the LPSC’s rule on new nuclear development does not apply to activities to preserve an option to develop and on the further grounds that the companies improperly engaged in advanced preparation activities prior to certification.  The LPSC directed that Entergy Louisiana and Entergy Gulf States Louisiana be permitted to seek recovery of these costs in their upcoming rate case filings that were subsequently filed in February 2013. In the resolution of the rate case proceeding the LPSC provided for an eight-year amortization of costs incurred in connection with the potential development of new nuclear generation at River Bend, without carrying costs, beginning in December 2014, provided, however, that amortization of these costs shall not result in a future rate increase. As of December 31, 2018, Entergy Louisiana has a regulatory asset of $28.5 million on its balance sheet related to these new nuclear generation development costs.

Entergy New Orleans [Member]

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, 2018 and 2017:

Other Regulatory Assets

Entergy

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$2,611.5		$2,642.3
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	814.3		746.0
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 – Storm Cost Recovery Filings with Retail Regulators) (Note 5)	452.7		558.9
Removal costs - recovered through depreciation rates (Note 9)	375.8		436.5
Opportunity Sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding)	116.3		109.8
Unamortized loss on reacquired debt - recovered over term of debt	74.5		82.9
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy)	52.1		73.7
Retail rate deferrals - recovered through rate riders as rates are redetermined by retail regulators	39.0		86.4
New nuclear generation development costs (Note 2 - New Nuclear Generation Development Costs) (b)	29.0		36.4
Transition to competition costs - recovered over a 15-year period through February 2021	26.7		37.7
Other	154.6		125.1
Entergy Total		$4,746.5		$4,935.7

Entergy Arkansas

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$747.2		$757.0
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	381.7		345.2
Removal costs - recovered through depreciation rates (Note 9)	138.3		176.9
Opportunity sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding)	116.3		109.8
Storm damage costs - recovered either through securitization or retail rates (Note 5 - Entergy Arkansas Securitization Bonds)	60.7		76.2
Unamortized loss on reacquired debt - recovered over term of debt	21.2		24.3
Retail rate deferrals - recovered through rate riders as rates are redetermined annually	20.5		28.2
ANO Fukushima and Flood Barrier costs - recovered through retail rates through February 2026 (Note 2 - Retail Rate Proceedings) (b)	12.6		14.4
Other	36.5		35.4
Entergy Arkansas Total		$1,535.0		$1,567.4

Entergy Louisiana

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (a)		$711.8		$724.6
Asset Retirement Obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	232.9		218.6
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy)	49.8		71.4
New nuclear generation development costs - recovery through formula rate plan December 2014 through November 2022 (Note 2 - New Nuclear Generation Development Costs) (b)	28.5		35.8
Unamortized loss on reacquired debt - recovered over term of debt	22.5		24.7
Storm damage costs - recovered through retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)	17.9		14.3
Business combination external costs deferral - recovery through formula rate plan December 2015 through November 2025 (b)	12.4		14.1
River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC)	11.0		12.9
Other	18.3		29.4
Entergy Louisiana Total		$1,105.1		$1,145.8

Entergy Mississippi

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$215.9		$218.7
Removal costs - recovered through depreciation rates (Note 9)	63.5		91.6
Attorney General litigation costs (Note 2 - Mississippi Attorney General Complaint) (b)	23.6		9.3
Retail rate deferrals - recovered through rate riders as rates are redetermined annually	16.6		49.4
Unamortized loss on reacquired debt - recovered over term of debt	16.2		17.6
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a)	7.2		7.6
Other	—		3.7
Entergy Mississippi Total		$343.0		$397.9

Entergy New Orleans

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$96.2		$102.8
Storm damage costs, including hurricane costs - recovered through retail rates and securitization (Note 2 - Storm Cost Recovery Filings with Retail Regulators)	70.4		82.3
Removal costs - recovered through depreciation rates (Note 9)	49.3		44.8
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a)	4.5		4.3
Unamortized loss on reacquired debt - recovered over term of debt	2.6		3.0
Rate case costs - recovered over a 6-year period through September 2021 (Note 2 - Retail Rate Proceedings)	1.9		2.6
Retail rate deferrals - recovered through rate riders as rates are redetermined monthly or annually	—		4.4
Other	4.9		7.2
Entergy New Orleans Total		$229.8		$251.4

Entergy Texas

	2018		2017
	(In Millions)
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 5 - Entergy Texas Securitization Bonds)		$303.6		$386.1
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)	171.8		169.2
Removal costs - recovered through depreciation rates (Note 9)	50.9		55.2
Transition to competition costs - recovered over a 15-year period through February 2021	26.7		37.7
Neches and Sabine costs - recovered over a ten-year period through September 2028 (Note 2 - Retail Rate Proceedings) (b)	23.6		—
Unamortized loss on reacquired debt - recovered over term of debt	8.2		8.7
Other	13.2		4.5
Entergy Texas Total		$598.0		$661.4

System Energy

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Other Postretirement Benefits) (a)		$179.3		$202.7
Asset retirement obligation - recovery dependent upon timing of decommissioning (Note 9) (a)	186.9		169.1
Removal costs - recovered through depreciation rates (Note 9)	76.4		67.9
Unamortized loss on reacquired debt - recovered over term of debt	3.8		4.6
System Energy Total		$446.4		$444.3

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

(b) Does not earn a return on investment.

Other Regulatory Liabilities

Entergy

	2018		2017
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)		$815.9		$989.3
Vidalia purchased power agreement (Note 8) (b)	139.7		151.6
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) (b)	111.1		124.8
Income tax rate change - returned to electric and gas customers through retail rates (Note 2 - Retail Rate Proceedings)	74.7		—
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions)	67.9		67.9
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination)	50.8		65.8
Grand Gulf over-recovery - will be refunded through rate riders as rates are redetermined annually	48.6		—
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)	44.4		—
Internal restructuring guaranteed customer credits (Note 2 - Retail Rate Proceedings)	39.6		—
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)	39.1		36.7
Excess decommissioning recovery for Willow Glen - (Note 14 - Dispositions)	31.9		—
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement	25.0		32.1
Removal costs - returned to customers through depreciation rates (Note 9)	18.8		32.4
Other	68.4		43.5
Entergy Total		$1,620.3		$1,588.5

Entergy Arkansas

	2018		2017
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)		$297.2		$354.0
Internal restructuring guaranteed customer credits (Note 2 - Retail Rate Proceedings)	39.6		—
Future formula rate plan revenue reductions (Note 2 - Retail Rate Proceedings)	35.1		—
Grand Gulf over-recovery - will be refunded through rate riders as rates are redetermined annually	26.0		—
Other	4.8		9.6
Entergy Arkansas Total		$402.7		$363.6

Entergy Louisiana

	2018		2017
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)		$274.1		$323.7
Vidalia purchased power agreement (Note 8) (b)	139.7		151.6
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) (b)	111.1		124.8
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination)	50.8		65.8
Income tax rate change - returned to electric customers through retail rates September 2018 through August 2019 (Note 2 - Retail Rate Proceedings)	49.9		—
Asset Retirement Obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)	39.1		36.7
Excess decommissioning recovery for Willow Glen - (Note 14 - Dispositions)	31.9		—
Removal costs - returned to customers through depreciation rates (Note 9)	18.8		32.4
Other	33.4		26.1
Entergy Louisiana Total		$748.8		$761.1

Entergy Mississippi

	2018		2017
	(In Millions)
Grand Gulf Over-Recovery - returned to customers through rate riders when rates are redetermined annually		$22.6		$—
Future formula rate plan revenue reductions (Note 2 - Retail Rate Proceedings)	9.3		—
Other	1.7		0.9
Entergy Mississippi Total		$33.6		$0.9

Entergy Texas

	2018		2017
	(In Millions)
Income tax rate change - refunded through a rate rider (Note 2 - Retail Rate Proceedings)		$23.1		$—
Advanced metering system surcharge (Note 2 - Advanced Metering Infrastructure (AMI) Filings)	16.5		—
Transition to competition costs - returned to customers through rate riders when rates are redetermined periodically	4.2		4.8
Other	4.1		2.1
Entergy Texas Total		$47.9		$6.9

System Energy

	2018		2017
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 17) (a)		$244.6		$311.6
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions)	67.9		67.9
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
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement	25.0		32.1
System Energy Total		$381.9		$456.0

(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 $25.0 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 will be 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 to be 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 existing formula rate plan rider for its customers to realize the remaining benefits of the Tax Act. Entergy Arkansas’s formula rate plan rider includes a netting adjustment that compares 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.

Entergy Louisiana

In a 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 will be 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. Entergy Mississippi’s formula rate plan includes a look-back evaluation report filing in March 2019 that will compare actual 2018 results to the allowed return on rate base. The stipulation approved in June 2018 provides 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 any true-up to be 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. In November 2018, Entergy Mississippi’s annual redetermination of the annual factor to be applied under the power management rider included an insignificant true-up to the amount of unprotected excess accumulated deferred income taxes. In January 2019 the MPSC approved the proposed power management cost factor effective for February 2019 bills.

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. In both a memorandum issued prior to the open meeting when the order was discussed and during the discussions at the open meeting regarding the order, the PUCT indicated that it would consider utility earnings in determining the treatment of the liability and the effects of the Tax Act. 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. Entergy Texas also stated that it would be inappropriate for the PUCT to require a refund of the reduction in income tax expense in 2018 resulting from the Act on a retroactive basis and without a comprehensive review of Entergy Texas’s cost of service and earned return on equity.

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 will 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 will 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 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 larger customers and over a period of four years for other customers.

System Energy

In a filing made with the FERC in March 2018, Entergy proposed revisions to the Unit Power Sales Agreement, among other agreements, to reflect the effects of the Tax Act. In the filing System Energy proposed to return all of its 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 are ongoing.

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, 2018 and 2017 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.

	2018			2017
	(In Millions)
Entergy Arkansas (a)		$86.5			$130.4
Entergy Louisiana (b)		$136.7			$96.7
Entergy Mississippi		$8.0			$32.4
Entergy New Orleans (b)		$2.8			($3.7	)
Entergy Texas		($19.7	)		($67.3	)

(a) Includes $67.3 million in 2018 and $67.1 million in 2017 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

Production Cost Allocation Rider

The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings, which are discussed in the “System Agreement Cost Equalization Proceedings” section below.

In May 2016, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected recovery of the production cost allocation rider true-up adjustment of the 2014 and 2015 unrecovered retail balance in the amount of $1.9 million. Additionally, the redetermined rates reflected the recovery of a $1.9 million System Agreement bandwidth remedy payment resulting from a compliance filing pursuant to the FERC’s December 2015 order related to test year 2009 production costs. The rates for the 2016 production cost allocation rider update were effective July 2016 through June 2017.

In May 2017, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected a credit amount of $0.3 million resulting from a compliance filing pursuant to the FERC’s September 2016 order. Additionally, the redetermined rate reflected recovery of the production cost allocation rider true-up adjustment of the 2016 unrecovered retail balance in the amount of $0.3 million. Because of the small effect of the 2017 production cost allocation rider update, Entergy Arkansas proposed to reduce the effective period of the update to one month, July 2017. After the one month collection period, rates were set to zero for all rate classes for the period August 2017 through June 2018.

In May 2018, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected recovery of the 2017 under-recovered retail balance and a $2.8 million payment by Entergy Arkansas associated with a compliance filing pursuant to a March 2018 FERC order related to 2010 production costs. The rates for the 2018 production cost allocation rider update are effective July 2018 through June 2019.

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.

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 December 2011 the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates.  The audit included a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 2005 through 2009.  In March 2016 the LPSC staff consultant issued its audit report. In its report, the LPSC staff consultant recommended that Entergy Louisiana refund approximately $8.6 million, plus interest, to customers and realign the recovery of approximately $12.7 million from Entergy Gulf States Louisiana’s fuel adjustment clause to base rates. In September 2016 the LPSC staff filed testimony stating that it was no longer recommending a disallowance of $3.4 million of the $8.6 million discussed above, but otherwise maintained the positions from its report. Subsequently, the parties entered into a settlement, which was approved by the LPSC in November 2016. The settlement recognized the dry cask storage recovery method issue, which was addressed in the separate proceeding approved by the LPSC in October 2017, provided for a refund of $5 million, which was made to legacy Entergy Gulf States Louisiana customers in December 2016, and resolved all other issues raised in the audit.

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 is evaluating the staff’s recommended disallowance.

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 consultant issued its audit report. In its report, the LPSC staff consultant recommended 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 is evaluating the staff’s recommended disallowance.

In June 2016 the LPSC staff provided notice of audits of Entergy Louisiana’s fuel adjustment clause filings and purchased gas adjustment clause filings. In recognition of the business combination that occurred in 2015, the audit notice was issued to Entergy Louisiana and will also include a review of charges to legacy Entergy Gulf States Louisiana customers prior to the business combination. The audit includes 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. Discovery commenced in March 2017. No report of audit has been issued.

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.  Discovery commenced in September 2018.  No report of audit has been issued.

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 November 2015, 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 a projected over-recovery balance of $48 million projected through January 31, 2016. In January 2016 the MPSC approved the redetermined annual factor effective February 1, 2016. The MPSC further ordered, however, that due to the significant change in natural gas price forecasts since Entergy Mississippi’s filing in November 2015 Entergy Mississippi should file a revised fuel factor with the MPSC no later than February 1, 2016. Pursuant to that order, Entergy Mississippi submitted a revised fuel factor. Additionally, because Entergy Mississippi’s projected over-recovery balance for the period ending January 31, 2016 was $68 million, in February 2016, Entergy Mississippi filed for another interim adjustment to the energy cost factor effective April 2016 to flow through to customers the projected over-recovery balance over a six-month period. That interim adjustment was approved by the MPSC in February 2016 effective for April 2016 bills.

In November 2016, 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 less than $2 million as of September 30, 2016. In January 2017 the MPSC approved the annual factor effective with February 2017 bills. Also 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 its order, the MPSC expressly reserved the right to review and determine the recoverability of any and all purchased power expenditures made during fiscal year 2016. The MPSC hired independent auditors to conduct an annual operations audit and a financial audit. The independent auditors issued their audit reports in December 2017. The audit reports included several recommendations for action by Entergy Mississippi but did not recommend any cost disallowances. In January 2018 the MPSC certified the audit reports to the Mississippi Legislature. In November 2017 the Public Utilities Staff separately engaged a consultant to review the outage at the Grand Gulf Nuclear Station that began in 2016. The review is currently in progress.

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. Entergy Mississippi proposed a two-tiered energy cost factor designed to promote overall rate stability throughout 2018 particularly during the summer months. 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.

Mississippi Attorney General Complaint

The Mississippi Attorney General filed a complaint in state court in December 2008 against Entergy Corporation, Entergy Mississippi, Entergy Services, and Entergy Power alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution.  The complaint is wide ranging and relates to tariffs and procedures under which Entergy Mississippi purchases power not generated in Mississippi to meet electricity demand.  Entergy believes the complaint is unfounded.  In December 2008 the defendant Entergy companies removed the Attorney General’s lawsuit to U.S. District Court in Jackson, Mississippi. In June 2010 the MPSC authorized the deferral of certain legal expenses associated with this litigation until it is resolved. As of December 31, 2018, Entergy Mississippi has a regulatory asset of $23.6 million for these deferred legal expenses. Pre-trial and settlement conferences were held in October 2018. In October 2018 the District Court rescheduled the trial to April 2019.

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 July 2015 certain parties filed briefs in a PUCT proceeding asserting that Entergy Texas should refund to retail customers an additional $10.9 million in bandwidth remedy payments Entergy Texas received related to calendar year 2006 production costs.  In October 2015 an ALJ issued a proposal for decision recommending that the additional bandwidth remedy payments be refunded to retail customers. In January 2016 the PUCT issued its order affirming the ALJ’s recommendation, and Entergy Texas filed a motion for rehearing of the PUCT’s decision, which the PUCT denied. In March 2016, Entergy Texas filed a complaint in Federal District Court for the Western District of Texas and a petition in the Travis County (State) District Court appealing the PUCT’s decision. The pending appeals did not stay the PUCT’s decision. In April 2016, Entergy Texas filed with the PUCT an application to refund to customers approximately $56.2 million. The refund resulted from (i) $41.8 million of fuel cost recovery over-collections through February 2016, (ii) the $10.9 million in bandwidth remedy payments, discussed above, that Entergy Texas received related to calendar year 2006 production costs, and (iii) $3.5 million in bandwidth remedy payments that Entergy Texas received related to 2006-2008 production costs. In June 2016, Entergy Texas filed an unopposed settlement agreement that added additional over-recovered fuel costs for the months of March and April 2016. The settlement resulted in a $68 million refund. The ALJ approved the refund on an interim basis and it was made to most customers over a four-month period beginning with the first billing cycle of July 2016. In July 2016 the PUCT issued an order approving the interim refund. The federal appeal of the PUCT’s January 2016 decision was heard in December 2016, and the Federal District Court granted Entergy Texas’s requested relief. In January 2017 the PUCT and an intervenor filed petitions for appeal of the Federal District Court ruling to the U.S. Court of Appeals for the Fifth Circuit. Oral argument was held before the Fifth Circuit in February 2018. In April 2018 the Fifth Circuit reversed the decision of the Federal District Court, reinstating the original PUCT decision. In October 2018, Entergy Texas filed notice of nonsuit in its appeal to the Travis County District Court regarding the PUCT’s January 2016 decision.

In July 2016, Entergy Texas filed an application to reconcile its fuel and purchased power costs for the period April 1, 2013 through March 31, 2016. During the reconciliation period, Entergy Texas incurred approximately $1.77 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 over-recovery balance of approximately $19.3 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning April 2016. Entergy Texas also noted, however, that the estimated $19.3 million over collection was being refunded to customers as a portion of the interim fuel refund beginning with the first billing cycle of July 2016, discussed above. Entergy Texas also requested a prudence finding for each of the fuel-related contracts and arrangements entered into or modified during the reconciliation period that have not been reviewed by the PUCT in a prior proceeding. In December 2016, Entergy Texas entered into a stipulation and settlement agreement resulting in a $6 million disallowance not associated with any particular issue raised and a refund of the over-recovery balance of $21 million as of November 30, 2016, to most customers beginning April 2017 through June 2017. This settlement was developed concurrently with the stipulation and settlement agreement in the 2016 transmission cost recovery factor rider amendment discussed below, and the terms and conditions in both settlements are interdependent. The fuel reconciliation settlement was approved by the PUCT in March 2017 and the refunds were made.

In June 2017, Entergy Texas filed an application for a fuel refund of approximately $30.7 million for the months of December 2016 through April 2017. For most customers, the refunds flowed through bills for the months of July 2017 through September 2017. The fuel refund was approved by the PUCT in August 2017.

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.

Retail Rate Proceedings

Filings with the APSC (Entergy Arkansas)

Retail Rates

2015 Base Rate Filing

In April 2015, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. The filing notified the APSC of Entergy Arkansas’s intent to implement a forward test year formula rate plan pursuant to Arkansas legislation passed in 2015, and requested a retail rate increase of $268.4 million, with a net increase in revenue of $167 million. The filing requested a 10.2% return on common equity. In December 2015, Entergy Arkansas, the APSC staff, and certain of the intervenors in the rate case filed with the APSC a joint motion for approval of a settlement of the case that proposed a retail rate increase of approximately $225 million with a net increase in revenue of approximately $133 million; an authorized return on common equity of 9.75%; and a formula rate plan tariff that provides a +/- 50 basis point band around the 9.75% allowed return on common equity. A significant portion of the rate increase is related to Entergy Arkansas’s acquisition in March 2016 of Union Power Station Power Block 2 for a base purchase price of $237 million. The settlement agreement also provided for amortization over a 10-year period of $7.7 million of previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance. In February 2016 the APSC approved the settlement with one exception that reduced the retail rate increase proposed in the settlement by $5 million. The settling parties agreed to the APSC modifications in February 2016. The new rates were effective February 24, 2016 and began billing with the first billing cycle of April 2016. In March 2016, Entergy Arkansas made a compliance filing regarding the new rates that included an interim base rate adjustment surcharge, effective with the first billing cycle of April 2016, to recover the incremental revenue requirement for the period February 24, 2016 through March 31, 2016. The interim base rate adjustment surcharge was designed to recover a total of $21.1 million over the nine-month period from April 2016 through December 2016.

2016 Formula Rate Plan Filing

In July 2016, Entergy Arkansas filed with the APSC its 2016 formula rate plan filing showing Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2017 test period to be below the formula rate plan bandwidth. The filing requested a $67.7 million revenue requirement increase to achieve Entergy Arkansas’s target earned return on common equity of 9.75%. In October 2016, Entergy Arkansas filed with the APSC revised formula rate plan attachments with an updated request for a $54.4 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors, as well as three additional adjustments identified as appropriate by Entergy Arkansas. In November 2016 a hearing was held and the APSC issued an order directing the parties to brief certain issues. In December 2016 the APSC approved a settlement agreement and the $54.4 million revenue requirement increase with approximately $25 million of the $54.4 million revenue requirement subject to possible future adjustment and refund to customers with interest. The APSC requested supplemental information for some of Entergy Arkansas’s requested nuclear expenditures. In December 2016 the APSC approved Entergy Arkansas’s formula rate plan compliance tariff, and the rates became effective with the first billing cycle of January 2017. In April 2017, Entergy Arkansas filed a motion consented to by all parties requesting that it be permitted to submit the supplemental information requested by the APSC in conjunction with its 2017 formula rate plan filing, which was subsequently made in July 2017 and is discussed below. In May 2017 the APSC approved the joint motion and proposal to review Entergy Arkansas’s supplemental information on a concurrent schedule with the 2017 formula rate plan filing. In October 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement resolving all issues in the proceeding and providing for recovery of the 2017 and 2018 nuclear costs. In December 2017 the APSC approved the settlement agreement and recovery of the 2017 and 2018 nuclear costs.

2017 Formula Rate Plan Filing

In July 2017, Entergy Arkansas filed with the APSC its 2017 formula rate plan filing showing Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2018 test period to be below the formula rate plan bandwidth.  The filing projected a $129.7 million revenue requirement increase to achieve Entergy Arkansas’s target earned return on common equity of 9.75%.  Entergy Arkansas’s formula rate plan is subject to a four percent annual revenue constraint and the projected annual revenue requirement increase exceeded the four percent, resulting in a proposed increase for the 2017 formula rate plan of $70.9 million. In October 2017, Entergy Arkansas filed with the APSC revised formula rate plan attachments that projected a $126.2 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors. The revised formula rate plan filing included a proposed $71.1 million revenue requirement increase based on a revision to the four percent constraint calculation. In October 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement resolving all issues in the proceeding and providing for recovery of the 2017 and 2018 nuclear costs. In December 2017 the APSC approved the settlement agreement and the $71.1 million revenue requirement increase, as well as Entergy Arkansas’s formula rate plan compliance tariff, and the rates became effective with the first billing cycle of January 2018.

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 shows 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 includes 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 includes a projected $73.4 millionrevenue 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 exceeds the constraint, the resulting increase is 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, which included additional actual revenues for 2018. 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 certain 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. An additional schedule was issued by the APSC for briefing other contested issues, the outcome of which did not affect the 2018 filing but could affect future Entergy Arkansas formula rate plan filings. That briefing was completed in February 2019, and the APSC has not indicated when a decision on those issues can be expected.

Similar to the 2018 filing, the formula rate plan filing that will be made in 2019 to set the formula rates for the 2020 calendar year will include a netting adjustment that will compare projected costs and sales for 2018 that were approved in the 2017 formula rate plan filing to actual 2018 costs and sales data. In the fourth quarter 2018, Entergy Arkansas recorded a provision of $35.1 million that reflects the estimate of the historical year netting adjustment that will be included in the 2019 filing to reflect the change in formula rate plan revenues associated with actual 2018 results when compared to the allowed rate of return on equity. 

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. Entergy Arkansas also filed a notice with the Missouri Public Service Commission in December 2017 out of an abundance of caution, although Entergy Arkansas does not serve any retail customers in Missouri. In April 2018 the Missouri Public Service Commission approved Entergy Arkansas’s filing. 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

2015 Formula Rate Plan Filing

In May 2016, Entergy Louisiana filed its formula rate plan evaluation report for its 2015 calendar year operations. The evaluation report reflected an earned return on common equity of 9.07%. As such, no adjustment to base formula rate plan revenue was required. The following other adjustments, however, were required under the formula rate plan: an increase in the legacy Entergy Louisiana additional capacity mechanism of $14.2 million; a separate increase in legacy Entergy Louisiana revenue of $10 million primarily to reflect the effects of the termination of the System Agreement; an increase in the legacy Entergy Gulf States Louisiana additional capacity mechanism of $0.5 million; a decrease in legacy Entergy Gulf States Louisiana revenue of $58.7 million primarily to reflect the effects of the termination of the System Agreement; and an increase of $11 million to the MISO cost recovery mechanism. Rates were implemented with the first billing cycle of September 2016, subject to refund. Following implementation of the as-filed rates in September 2016, there were several interim updates to Entergy Louisiana’s formula rate plan, including the one submitted in December 2016, reflecting implementation of the settlement of the Waterford 3 replacement steam generator project prudence review described below. In June 2017 the LPSC staff and Entergy Louisiana filed a joint report of proceedings, which was accepted by the LPSC in June 2017, finalizing the results of the May 2016 evaluation report, interim updates, and corresponding proceedings with no changes to rates already implemented.

2016 Formula Rate Plan Filing

In May 2017, Entergy Louisiana filed its formula rate plan evaluation report for its 2016 calendar year operations. The evaluation report reflected an earned return on common equity of 9.84%. As such, no adjustment to base formula rate plan revenue was required. Adjustments, however, were required under the formula rate plan; the 2016 formula rate plan evaluation report showed a decrease in formula rate plan revenue of approximately $16.9 million, comprised of a decrease in legacy Entergy Louisiana formula rate plan revenue of $3.5 million, a decrease in legacy Entergy Gulf States Louisiana formula rate plan revenue of $9.7 million, and a decrease in incremental formula rate plan revenue of $3.7 million. Additionally, the formula rate plan evaluation report called for a decrease of $40.5 million in the MISO cost recovery revenue requirement from $46.8 million to $6.3 million. Rates reflecting these adjustments were implemented with the first billing cycle of September 2017, subject to refund. In September 2017 the LPSC issued its report indicating that no changes to Entergy Louisiana’s original formula rate plan evaluation report were required but reserved for several issues, including Entergy Louisiana’s September 2017 update to its formula rate plan evaluation report.  In July 2018, Entergy Louisiana and the LPSC staff filed an unopposed joint report setting forth a correction to the annualization calculation, the effect of which was a net $3.5 million revenue requirement reduction and indicating that there are no outstanding issues with the 2016 formula rate plan report, the supplemental report, or the interim updates.  In September 2018 the LPSC approved the unopposed joint report.

Formula Rate Plan Extension Through 2019 Test Year

In August 2017, Entergy Louisiana filed a request with the LPSC seeking to extend its formula rate plan for three years (2017-2019) with limited modifications of its terms.  Those modifications include: a one-time resetting of base rates to the midpoint of the band at Entergy Louisiana’s authorized return on equity of 9.95% for the 2017 test year; narrowing of the formula rate plan bandwidth from a total of 160 basis points to 80 basis points; and a forward-looking mechanism that would allow Entergy Louisiana to recover certain transmission-related costs contemporaneously with when those projects begin delivering benefits to customers.  In April 2018 the LPSC approved an unopposed joint motion filed by Entergy Louisiana and the LPSC staff that settled the matter. The settlement extended the formula rate plan for three years, providing for rates through at least August 2021. In addition to retaining the major features of the traditional formula rate plan, substantive features of the extended formula rate plan include:

• a mid-point reset of formula rate plan revenues to a 9.95% earned return on common equity for the 2017 test year and for the St. Charles Power Station when it enters commercial operation;

• a 9.8% target earned return on common equity for the 2018 and 2019 test years;

• narrowing of the common equity bandwidth to plus or minus 60 basis points around the target earned return on common equity;

• a cap on potential revenue increase of $35 million for the 2018 evaluation period, and $70 million for the cumulative 2018 and 2019 evaluation periods, on formula rate plan cost of service rate increases (the cap excludes rate changes associated with the transmission recovery mechanism described below and rate changes associated with additional capacity);

• a framework for the flow back of certain tax benefits created by the Tax Act to customers, as described in “Regulatory activity regarding the Tax Cuts and Jobs Act” above; and

• a transmission recovery mechanism providing for the opportunity to recover certain transmission-related expenditures in excess of $100 million annually for projects placed in service up to one month prior to rate change outside of sharing that is designed to operate in a fashion similar to the additional capacity mechanism.

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.

Waterford 3 Replacement Steam Generator Project

Following the completion of the Waterford 3 replacement steam generator project, the LPSC undertook a prudence review in connection with a filing made by Entergy Louisiana in April 2013 with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs. In July 2014 the LPSC staff filed testimony recommending potential project and replacement power cost disallowances of up to $71 million, citing a need for further explanation or documentation from Entergy Louisiana.  An intervenor filed testimony recommending disallowance of $141 million of incremental project costs, claiming the steam generator fabricator was imprudent.  Entergy Louisiana provided further documentation and explanation requested by the LPSC staff. An evidentiary hearing was held in December 2014. Entergy Louisiana believed that the replacement steam generator costs were prudently incurred and applicable legal principles supported their recovery in rates.  Nevertheless, Entergy Louisiana recorded a write-off of $16 million of Waterford 3’s plant balance in December 2014 because of the uncertainty at the time associated with the resolution of the prudence review. In December 2015 the ALJ issued a proposed recommendation, which was subsequently finalized, concluding that Entergy Louisiana prudently managed the Waterford 3 replacement steam generator project, including the selection, use, and oversight of contractors, and could not reasonably have anticipated the damage to the steam generators. Nevertheless, the ALJ concluded that Entergy Louisiana was liable for the conduct of its contractor and subcontractor and, therefore, recommended a disallowance of $67 million in capital costs. Additionally, the ALJ concluded that Entergy Louisiana did not sufficiently justify the incurrence of $2 million in replacement power costs during the replacement outage. Although the ALJ’s recommendation had not yet been considered by the LPSC, after considering the progress of the proceeding in light of the ALJ recommendation, Entergy Louisiana recorded in the fourth quarter 2015 approximately $77 million in charges, including a $45 million asset write-off and a $32 million regulatory charge, to reflect that a portion of the assets associated with the Waterford 3 replacement steam generator project was no longer probable of recovery. Entergy Louisiana maintained that the ALJ’s recommendation contained significant factual and legal errors.

In October 2016 the parties reached a settlement in this matter. The settlement was approved by the LPSC in December 2016. The settlement effectively provided for an agreed-upon disallowance of $67 million of plant, which had been previously written off by Entergy Louisiana, as discussed above. The refund to customers of approximately $71 million as a result of the settlement approved by the LPSC was made to customers in January 2017. Of the $71 million of refunds, $68 million was credited to customers through Entergy Louisiana’s formula rate plan, outside of sharing, and $3 million through its fuel adjustment clause. Entergy Louisiana had previously recorded a provision of $48 million for this refund. The previously-recorded provision included the cumulative revenues recorded through December 2016 related to the $67 million of disallowed plant. An additional regulatory charge of $23 million was recorded in fourth quarter 2016 to reflect the effects of the settlement. The settlement also provided that Entergy Louisiana could retain the value associated with potential service credits agreed to by the project contractor, to the extent they are realized in the future. Following a review by the parties, an unopposed joint report of proceedings was filed by the LPSC staff and Entergy Louisiana in May 2017 and the LPSC accepted the joint report of proceedings resolving the matter.

Union Power Station and Deactivation or Retirement Decisions for Entergy Louisiana Plants

In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC for approval of the acquisition and cost recovery of two power blocks of the Union Power Station for an expected base purchase price of approximately $237 million per power block, subject to adjustments. In September 2015, Entergy Gulf States Louisiana agreed to settlement terms with all parties for Entergy Gulf States Louisiana’s purchase of the two power blocks. In October 2015 the LPSC voted unanimously to approve the uncontested settlement which finds, among other things, that acquisition of Power Blocks 3 and 4 is in the public interest and, therefore, prudent. The business combination of Entergy Gulf States Louisiana and Entergy Louisiana received regulatory approval and closed in October 2015 making Entergy Louisiana the named purchaser of Power Blocks 3 and 4 of the Union Power Station. In March 2016, Entergy Louisiana acquired Power Blocks 3 and 4 of Union Power Station for an aggregate purchase price of approximately $475 million and implemented rates to collect the estimated first-year revenue requirement with the first billing cycle of March 2016.

As a term of the LPSC-approved settlement authorizing the purchase of Power Blocks 3 and 4 of the Union Power Station, Entergy Louisiana agreed to make a filing with the LPSC to review its decisions to deactivate Ninemile 3 and Willow Glen 2 and 4 and its decision to retire Little Gypsy 1.  In January 2016, Entergy Louisiana made its compliance filing with the LPSC. Entergy Louisiana, LPSC staff, and intervenors participated in a technical conference in March 2016 where Entergy Louisiana presented information on its deactivation/retirement decisions for these four units in addition to information on the current deactivation decisions for the ten-year planning horizon. Parties requested further proceedings on the prudence of the decision to deactivate Willow Glen 2 and 4.  No party contested the prudence of the decision to deactivate Willow Glen 2 and 4 or suggested reactivation of these units; however, issues were raised related to Entergy Louisiana’s decision to give up its transmission service rights in MISO for Willow Glen 2 and 4 rather than placing the units into suspended status for the three-year term permitted by MISO. In March 2018 the LPSC adopted the ALJ’s recommended order finding that Entergy Louisiana did not demonstrate that its decision to permanently surrender transmission rights for the mothballed (not retired) Willow Glen 2 and 4 units was reasonable and that Entergy Louisiana should hold customers harmless from increased transmission expenses should those units be reactivated. Because no party or the LPSC suggested that Willow Glen 2 and 4 should be reactivated and because the cost to return those units to service far exceeded the revenue the units were expected to generate in MISO, Entergy Louisiana retired Willow Glen 2 and 4 in March 2018. Entergy Louisiana submitted a compliance filing regarding retirement of Willow Glen 2 and 4, and the LPSC closed the proceeding.

Retail Rates - Gas

2016 Rate Stabilization Plan Filing

In January 2017, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2016. The filing of the evaluation report for test year 2016 reflected an earned return on common equity of 6.37%. In April 2017 the LPSC approved a joint report of proceedings and Entergy Louisiana submitted a revised evaluation report reflecting a $1.2 million annual increase in revenue with rates implemented with the first billing cycle of May 2017.

2017 Rate Stabilization Plan Filing

In January 2018, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2017.  The filing of the evaluation report for the test year 2017 reflected an earned return on common equity of 9.06%.  This earned return is below the earnings sharing band of the rate stabilization plan and results in a rate increase of $0.1 million.  Due to the enactment in late-December 2017 of the Tax Cuts and Jobs Act, Entergy Louisiana did not have adequate time to reflect the effects of this tax legislation in the rate stabilization plan.  In April 2018, Entergy Louisiana filed a supplemental evaluation report for the test year ended September 2017, reflecting the effects of the Tax Act, including a proposal to use the unprotected excess accumulated deferred income taxes to offset approximately $1.4 million of storm restoration deferred operation and maintenance costs incurred by Entergy Louisiana in connection with the August 2016 flooding disaster in its gas service area. The supplemental filing reflects an earned return on common equity of 10.79%. As-filed rates from the supplemental filing were implemented, subject to refund, with customers receiving a cost reduction of approximately $0.7 million effective with bills rendered on and after the first billing cycle of May 2018, as well as a $0.2 million reduction in the gas infrastructure rider effective with bills rendered on and after the first billing cycle of July 2018. The proceeding is currently in its discovery phase. A procedural schedule has not been established.

2018 Rate Stabilization Plan Filing

In January 2019, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2018. The filing of the evaluation report for the test year 2018 reflected an earned return on common equity of 2.69%. This earned return is below the earning sharing band of the gas rate stabilization plan and results in a rate increase of $2.8 million. Entergy Louisiana will make a compliance filing in April 2019 and rates will be implemented during the first billing cycle of May 2019.

Filings with the MPSC (Entergy Mississippi)

Formula Rate Plan Filings

In March 2016, Entergy Mississippi submitted its formula rate plan 2016 test year filing showing Entergy Mississippi’s projected earned return for the 2016 calendar year to be below the formula rate plan bandwidth. The filing showed a $32.6 million rate increase was necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 9.96%, within the formula rate plan bandwidth. In June 2016 the MPSC approved Entergy Mississippi’s joint stipulation with the Mississippi Public Utilities Staff. The joint stipulation provided for a total revenue increase of $23.7 million. The revenue increase included a $19.4 million increase through the formula rate plan, resulting in a return on common equity point of adjustment of 10.07%. The revenue increase also included $4.3 million in incremental ad valorem tax expenses to be collected through an updated ad valorem tax adjustment rider. The revenue increase and ad valorem tax adjustment rider were effective with the July 2016 bills.

In March 2017, Entergy Mississippi submitted its formula rate plan 2017 test year filing and 2016 look-back filing showing Entergy Mississippi’s earned return for the historical 2016 calendar year and projected earned return for the 2017 calendar year to be within the formula rate plan bandwidth, resulting in no change in rates. In June 2017, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a stipulation that confirmed that Entergy Mississippi’s earned returns for both the 2016 look-back filing and 2017 test year were within the respective formula rate plan bandwidths. In June 2017 the MPSC approved the stipulation, which resulted in no change in rates.

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.

Entergy Mississippi’s formula rate plan includes a look-back evaluation report filing in March 2019 that will compare actual 2018 results to the performance-adjusted allowed return on rate base.  In fourth quarter 2018, Entergy Mississippi recorded a provision of $9.3 million that reflects the estimate of the difference between the 2018 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 October 2018, Entergy Mississippi proposed revisions to its formula rate plan that would provide for a mechanism, the interim capacity rate adjustment mechanism, in the formula rate plan 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 additions, such as the Sunflower Solar Facility, that are approved by the MPSC.

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

As a provision of the settlement agreement approved by the City Council in May 2015 providing for the transfer from Entergy Louisiana to Entergy New Orleans of certain assets that supported the provision of service to Entergy Louisiana’s customers in Algiers, it was agreed that, with limited exceptions, no action may be taken with respect to Entergy New Orleans’s base rates until rates are implemented from a base rate case that must be filed for its electric and gas operations in 2018. This provision eliminated the formula rate plan applicable to Algiers operations. The limited exceptions included continued implementation of the then-remaining two years of the four-year phased-in rate increase for the Algiers area and certain exceptional cost increases or decreases in the base revenue requirement. An additional provision of the settlement agreement allowed for continued recovery of the revenue requirement associated with the capacity and energy from Ninemile 6 received by Entergy New Orleans under a power purchase agreement with Entergy Louisiana (Algiers PPA). The settlement authorized Entergy New Orleans to recover the remaining revenue requirement related to the Algiers PPA through base rates charged to Algiers customers. The settlement also provided for continued implementation of the Algiers MISO recovery rider.

In addition to the Algiers PPA, Entergy New Orleans has a separate power purchase agreement with Entergy Louisiana for 20% of the capacity and energy from Ninemile 6 (Ninemile PPA), which commenced operation in December 2014. Initially, recovery of the non-fuel costs associated with the Ninemile PPA was authorized through a special Ninemile 6 rider billed only to Entergy New Orleans customers outside of Algiers.

In August 2015, Entergy New Orleans filed an application with the City Council seeking authorization to proceed with the purchase of Union Power Block 1, with an expected base purchase price of approximately $237 million, subject to adjustments, and seeking approval of the recovery of the associated costs. In November 2015 the City Council issued written resolutions and an order approving an agreement in principle between Entergy New Orleans and City Council advisors providing that the purchase of Union Power Block 1 and related assets by Entergy New Orleans is prudent and in the public interest. The City Council authorized expansion of the terms of the purchased power and capacity acquisition cost recovery rider to recover the non-fuel purchased power expense from Ninemile 6, the revenue requirement associated with the purchase of Power Block 1 of the Union Power Station, and a credit to customers of $400 thousand monthly beginning June 2016 in recognition of the decrease in other operation and maintenance expenses that would result with the deactivation of Michoud Units 2 and 3. In March 2016, Entergy New Orleans purchased Power Block 1 of the Union Power Station for approximately $237 million and initiated recovery of these costs with March 2016 bills. In July 2016, Entergy New Orleans and the City Council Utility Committee agreed to a temporary increase in the Michoud credit to customers to a total of $1.4 million monthly for August 2016 through December 2016.

A 2008 rate case settlement included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs.  The rate settlement provided an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provided a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs. In January 2015 the City Council approved funding for the Energy Smart program from April 2015 through March 2017 using the remainder of the approximately $12.8 million of 2014 rough production cost equalization funds, with any remaining costs being recovered through the fuel adjustment clause. This funding methodology was modified in November 2015 when the City Council directed Entergy New Orleans to use a combination of guaranteed customer savings related to a prior agreement with the City Council and rough production cost equalization funds to cover program costs prior to recovering any costs through the fuel adjustment clause. In April 2017 the City Council approved an implementation plan for the Energy Smart program from April 2017 through December 2019. The City Council directed that the $11.8 million balance reported for Energy Smart funds be used to continue funding the program for Entergy New Orleans’s legacy customers and that the Energy Smart Algiers program continue to be funded through the Algiers fuel adjustment clause, until additional customer funding is required for the legacy customers. In September 2017, Entergy New Orleans filed a supplemental plan and proposed several options for an interim cost recovery mechanism necessary to recover program costs during the period between when existing funds directed to Energy Smart programs are depleted and when new rates from the 2018 combined rate case, which includes a cost recovery mechanism for Energy Smart funding, take effect (estimated to be August 2019). In December 2017 the City Council approved an energy efficiency cost recovery rider as an interim funding mechanism for Energy Smart, subject to verification that no additional funding sources exist. In June 2018 the City Council also approved a resolution recommending that Entergy New Orleans allocate approximately $13.5 million of benefits resulting from the Tax Act to Energy Smart. Entergy New Orleans is seeking approval of a permanent and stable source of funding for Energy Smart as part of its base rate case filed in September 2018.

In September 2018, Entergy New Orleans filed an electric and gas base rate case with the City Council. The filing requests 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 requests 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 includes a proposed gas rate decrease of $142 thousand. Entergy New Orleans’s rates reflect 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 ending 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’s request for a change in rates is based on the projected twelve months ending December 31, 2018.

The filing’s major provisions include: (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 have recommended, among other things, overall rate reductions of approximately $33 million in electric rates and $3.8 million in gas rates. Certain intervenors have recommended overall rate reductions of up to approximately $49 million in electric rates and $5 million in gas rates. The procedural schedule calls for an evidentiary hearing to be held in June 2019.

Internal Restructuring

In July 2016, Entergy New Orleans filed an application with the City Council seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy New Orleans, Inc. to a new entity, which would ultimately be owned by an existing Entergy subsidiary holding company. In May 2017 the City Council adopted a resolution approving the proposed internal restructuring pursuant to an agreement in principle with the City Council advisors and certain intervenors. Pursuant to the agreement in principle, Entergy New Orleans would credit retail customers $10 million in 2017, $1.4 million in the first quarter of the year after the transaction closes, and $117,500 each month in the second year after the transaction closes until such time as new base rates go into effect as a result of the then-anticipated 2018 base rate case (which has subsequently been filed). Entergy New Orleans began crediting retail customers in June 2017. In June 2017 the FERC approved the transaction and, pursuant to the agreement in principle, Entergy New Orleans will provide additional credits to retail customers of $5 million in each of the years 2018, 2019, and 2020.

In November 2017, Entergy New Orleans undertook a multi-step restructuring, including the following:

• Entergy New Orleans, Inc. redeemed its outstanding preferred stock at a price of approximately $21 million, which included a call premium of approximately $819,000, plus any accumulated and unpaid dividends.

• Entergy New Orleans, Inc. converted from a Louisiana corporation to a Texas corporation.

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

• Entergy New Orleans, Inc. contributed the membership interests in Entergy New Orleans 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 New Orleans Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.

In December 2017, Entergy New Orleans, Inc. changed its name to Entergy Utility Group, Inc., and Entergy New Orleans Power then changed its name to Entergy New Orleans, LLC. Entergy New Orleans, LLC holds substantially all of the assets, and has assumed substantially all of the liabilities, of Entergy New Orleans, Inc. The restructuring was accounted for as a transaction between entities under common control.

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 electricity 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), 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 June 2017, Entergy Texas filed an application to amend its DCRF rider by increasing the total collection from $8.65 million to approximately $19 million. In July 2017, Entergy Texas, the PUCT staff, and the two other parties in the proceeding entered into an unopposed stipulation and settlement agreement resulting in an amended DCRF annual revenue requirement of $18.3 million. In September 2017 the PUCT issued its final order approving the unopposed stipulation and settlement agreement. The amended DCRF rider rates became effective for usage on and after September 1, 2017. DCRF rates were set to zero upon implementation of new base rates on October 17, 2018, as described above in the discussion of the 2018 base rate case.

Transmission Cost Recovery Factor (TCRF) Rider

In September 2015, Entergy Texas filed for a TCRF rider requesting a $13 million increase, incremental to base rates. Testimony was filed in November 2015, with the PUCT staff and other parties proposing various disallowances involving, among other things, MISO charges, vegetation management costs, and bad debt expenses that would reduce the requested increase by approximately $2 million. In addition to those recommended disallowances, a number of parties recommended that Entergy Texas’s request be reduced by an additional $3.4 million to account for load growth since base rates were last set. In February 2016 a State Office of Administrative Hearings ALJ issued a proposal for decision recommending that the PUCT disallow approximately $2 million from Entergy Texas’s $13 million request, but recommending that the PUCT not accept the load growth offset. In June 2016 the PUCT indicated that it would take up in a future rulemaking project the issue of whether a load growth adjustment should apply to a TCRF. In July 2016 the PUCT issued an order generally accepting the proposal for decision but declining to adjust the TCRF baseline in two instances as recommended by the ALJ, which resulted in a total annual allowance of approximately $10.5 million. The PUCT also ordered its staff and Entergy Texas to track all spare autotransformer transfers going forward so that it could address the appropriate accounting treatment and prudence of such transfers in Entergy Texas’s next base rate case. Entergy Texas implemented the TCRF rider beginning with September 2016 bills.

In September 2016, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The proposed amended TCRF rider was designed to collect approximately $29.5 million annually from Entergy Texas’s retail customers. This amount included the approximately $10.5 million annually that Entergy Texas was previously authorized to collect through the TCRF rider, as discussed above. In December 2016, concurrent with the 2016 fuel reconciliation stipulation and settlement agreement discussed above, Entergy Texas and the PUCT staff reached a settlement agreeing to the amended TCRF annual revenue requirement of $29.5 million. As discussed above, the terms of the two settlements are interdependent. The PUCT approved the settlement and issued a final order in March 2017. Entergy Texas implemented the amended TCRF rider beginning with bills covering usage on and after March 20, 2017. TCRF rates were set to zero upon implementation of new base rates on October 17, 2018, as described above in the 2018 base rate case discussion.

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. The proceeding is currently ongoing at the PUCT.

Advanced Metering Infrastructure (AMI) Filings

Entergy Arkansas

In September 2016, Entergy Arkansas filed an application seeking a finding from the APSC that Entergy Arkansas’s deployment of AMI is in the public interest. Entergy Arkansas proposed to replace existing meters with advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Arkansas’s modernized power grid. The filing included an estimate of implementation costs for AMI of $208 million. The filing identified a number of quantified and unquantified benefits, and Entergy Arkansas provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal net benefit to customers of $406 million. Entergy Arkansas also sought to continue to include in rate base the remaining book value of existing meters, which was approximately $57 million at December 31, 2015, that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Arkansas proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Deployment of the communications network began in 2018. Entergy Arkansas proposed to include the AMI deployment costs and the quantified benefits in future formula rate plan filings, and the 2018 costs were approved in the 2017 formula rate plan filing. In August 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement. In October 2017 the APSC issued an order finding that Entergy Arkansas’s AMI deployment is in the public interest and approving the settlement agreement subject to a minor modification. Entergy Arkansas expects to recover the undepreciated balance of its existing meters through a regulatory asset to be amortized over 15 years.

Entergy Louisiana

In November 2016, Entergy Louisiana filed an application seeking a finding from the LPSC that Entergy Louisiana’s deployment of advanced electric and gas metering infrastructure is in the public interest. Entergy Louisiana proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Louisiana’s modernized power grid. The filing included an estimate of implementation costs for AMI of $330 million. The filing identified a number of quantified and unquantified benefits, and Entergy Louisiana provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $607 million. Entergy Louisiana also sought to continue to include in rate base the remaining book value, approximately $92 million at December 31, 2015, of the existing electric meters and also to depreciate those assets using current depreciation rates. Entergy Louisiana proposed a 15-year useful life for the new advanced meters, the three-year deployment of which began in 2019. Deployment of the communications network began in 2018. Entergy Louisiana proposed to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022. The parties reached an uncontested stipulation permitting implementation of Entergy Louisiana’s proposed AMI system, with modifications to the proposed customer charge. In July 2017 the LPSC approved the stipulation. Entergy Louisiana expects to recover the undepreciated balance of its existing meters through a regulatory asset to be amortized at current depreciation rates.

Entergy Mississippi

In November 2016, Entergy Mississippi filed an application seeking an order from the MPSC granting a certificate of public convenience and necessity and finding that Entergy Mississippi’s deployment of AMI is in the public interest. Entergy Mississippi proposed to replace existing meters with advanced meters that enable two-way data communication; to design and build a secure and reliable network to support such communications; and to implement support systems. AMI is intended to serve as the foundation of Entergy Mississippi’s modernized power grid. The filing included an estimate of implementation costs for AMI of $132 million. The filing identified a number of quantified and unquantified benefits, and Entergy Mississippi provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal benefit to customers of $496 million over a 15-year period, which when netted against the costs of AMI results in $183 million of net customer benefits. Entergy Mississippi also sought to continue to include in rate base the remaining book value, approximately $56 million at December 31, 2015, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Mississippi proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019, subject to approval by the MPSC. Deployment of the communications network began in 2018. Entergy Mississippi proposed to include the AMI deployment costs and the quantified benefits in existing rate mechanisms, primarily through future formula rate plan filings and/or future energy cost recovery rider schedule re-determinations, as applicable. In May 2017 the Mississippi Public Utilities Staff and Entergy Mississippi entered into and filed a joint stipulation supporting Entergy Mississippi’s filing, and the MPSC issued an order approving the filing without material changes, finding that Entergy Mississippi’s deployment of AMI is in the public interest and granting a certificate of public convenience and necessity. The MPSC order also confirmed that Entergy Mississippi shall continue to include in rate base the remaining book value of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. In June 2018, as part of the order approving the joint stipulation between the Mississippi Public Utilities Staff and Entergy Mississippi addressing Entergy Mississippi’s 2018 formula rate plan evaluation report and the ratemaking effects of the Tax Act, the MPSC approved the acceleration of the recovery of substantially all of Entergy Mississippi’s existing customer meters in anticipation of AMI deployment.

Entergy New Orleans

In October 2016, Entergy New Orleans filed an application seeking a finding from the City Council that Entergy New Orleans’s deployment of advanced electric and gas metering infrastructure is in the public interest.  Entergy New Orleans proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems.  AMI is intended to serve as the foundation of Entergy New Orleans’s modernized power grid.  The filing included an estimate of implementation costs for AMI of $75 million. The filing identified a number of quantified and unquantified benefits, and Entergy New Orleans provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $101 million.  Entergy New Orleans also sought to continue to include in rate base the remaining book value, approximately $21 million at December 31, 2015, of the existing electric meters and also to depreciate those assets using current depreciation rates.  Entergy New Orleans proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which began in 2019.  Deployment of the information technology infrastructure began in 2017 and deployment of the communications network began in 2018.  Entergy New Orleans proposed to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022.  The City Council’s advisors filed testimony in May 2017 recommending the adoption of AMI subject to certain modifications, including the denial of Entergy New Orleans’s proposed customer charge as a cost recovery mechanism. In January 2018 a settlement was reached between the City Council’s advisors and Entergy New Orleans. In February 2018 the City Council approved the settlement, which deferred cost recovery to the 2018 Entergy New Orleans rate case, but also stated that an adjustment for 2018-2019 AMI costs can be filed in the rate case and that, for all subsequent AMI costs, the mechanism to be approved in the 2018 rate case will allow for the timely recovery of such costs. In April 2018 the City Council adopted a resolution directing Entergy New Orleans to explore the options for accelerating the deployment of AMI. In June 2018 the City Council approved a one-year acceleration of AMI in its service area for an incremental $4.4 million.

Entergy Texas

In April 2017 the Texas legislature enacted legislation that extends statutory support for AMI deployment to Entergy Texas and directs that if Entergy Texas elects to deploy AMI, it shall do so as rapidly as practicable. In July 2017, Entergy Texas filed an application seeking an order from the PUCT approving Entergy Texas’s deployment of AMI. Entergy Texas proposed to replace existing meters with advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Texas’s modernized power grid. The filing included an estimate of implementation costs for AMI of $132 million. The filing identified a number of quantified and unquantified benefits, with Entergy Texas showing that its AMI deployment is expected to produce nominal net operational cost savings to customers of $33 million. Entergy Texas also sought to continue to include in rate base the remaining book value, approximately $41 million at December 31, 2016, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Texas proposed a seven-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Entergy Texas also proposed a surcharge tariff to recover the reasonable and necessary costs it has and will incur under the deployment plan for the full deployment of advanced meters. Further, Entergy Texas sought approval of fees that would be charged to customers who choose to opt out of receiving service through an advanced meter and instead receive electric service with a non-standard meter. In October 2017, Entergy Texas and other parties entered into and filed an unopposed stipulation and settlement agreement, permitting deployment of AMI with limited modifications. The PUCT approved the stipulation and settlement agreement in December 2017. Entergy Texas implemented the AMI surcharge tariff beginning with January 2018 bills. As of December 31, 2018, Entergy Texas has a regulatory liability related to the collection of the surcharge from customers. Consistent with the approval, deployment of the communications network began in 2018 and deployment of the advanced meters will begin in March 2019. Entergy Texas expects to recover the remaining net book value of its existing meters through a regulatory asset to be amortized at current depreciation rates.

System Agreement Cost Equalization Proceedings

Prior to its final termination in 2016, the Utility operating companies historically engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement.  Entergy Arkansas terminated its participation in the System Agreement in December 2013. Entergy Mississippi terminated its participation in the System Agreement in November 2015. The System Agreement terminated with respect to its remaining participants in August 2016.

Although the System Agreement has terminated, certain of the Utility operating companies’ retail regulators continue to pursue litigation involving the System Agreement at the FERC and in federal courts.  The proceedings include challenges to the allocation of costs as defined by the System Agreement and other matters.

In June 2005 the FERC issued a decision in System Agreement litigation that had been commenced by the LPSC, and essentially affirmed its decision in a December 2005 order on rehearing.  The decision included, among other things:

• The FERC’s conclusion that the System Agreement no longer roughly equalized total production costs among the Utility operating companies.

• In order to reach rough production cost equalization, the FERC imposed a bandwidth remedy by which each company’s total annual production costs would have to be within +/- 11% of Entergy System average total annual production costs.

• In calculating the production costs for this purpose under the FERC’s order, output from the Vidalia hydroelectric power plant would not reflect the actual Vidalia price for the year but be priced at that year’s average price paid by Entergy Louisiana for the exchange of electric energy under Service Schedule MSS-3 of the System Agreement, thereby reducing the amount of Vidalia costs reflected in the comparison of the Utility operating companies’ total production costs.

• The remedy ordered by the FERC in 2005 required no refunds and became effective based on calendar year 2006 production costs with the first reallocation payments made in 2007.

The FERC’s decision reallocated total production costs of the Utility operating companies whose relative total production costs expressed as a percentage of Entergy System average production costs are outside an upper or lower bandwidth.  This was accomplished by payments from Utility operating companies whose production costs were more than 11% below Entergy System average production costs to Utility operating companies whose production costs were more than the Entergy System average production cost, with payments going first to those Utility operating companies whose total production costs were farthest above the Entergy System average.

The LPSC, APSC, MPSC, and the Arkansas Electric Energy Consumers appealed the FERC’s December 2005 decision to the United States Court of Appeals for the D.C. Circuit.  Entergy and the City of New Orleans intervened in the various appeals.  The D.C. Circuit issued its decision in April 2008.  The D.C. Circuit concluded that the FERC’s orders had failed to adequately explain both its conclusion that it was prohibited from ordering refunds for the 20-month period from September 13, 2001 - May 2, 2003 and its determination to implement the bandwidth remedy commencing on January 1, 2006, rather than June 1, 2005.  The D.C. Circuit remanded the case to the FERC for further proceedings on those two issues.

In October 2011 the FERC issued an order addressing the D.C. Circuit remand on the two issues.  On the first issue, the FERC concluded that it did have the authority to order refunds, but decided that it would exercise its equitable discretion and not require refunds for the 20-month period from September 13, 2001 - May 2, 2003.  Because the ruling on refunds relied on findings in the interruptible load proceeding, which is discussed in a separate section below, the FERC concluded that this refund ruling will be held in abeyance pending the outcome of the rehearing requests in the interruptible load proceeding.  On the second issue, the FERC reversed its prior decision and ordered that the prospective bandwidth remedy begin on June 1, 2005 (the date of its initial order in the proceeding) rather than January 1, 2006, as it had previously ordered.  Pursuant to the October 2011 order, Entergy was required to calculate bandwidth payments for the period June - December 2005 utilizing the bandwidth formula tariff prescribed by the FERC that was filed in a December 2006 compliance filing and accepted by the FERC in an April 2007 order.  

In March 2015, in light of a December 2014 decision by the D.C. Circuit in the interruptible load proceeding, Entergy filed with the FERC a motion to establish a briefing schedule on refund issues and an initial brief addressing refund issues. The initial brief argued that the FERC, in response to the D.C. Circuit decision, should clarify its policy on refunds and find that refunds are not required in this proceeding. In October 2015 the FERC issued three orders related to the commencement of the remedy on June 1, 2005 and the inclusion of interest for the period June 1, 2005 through December 31, 2005. Specifically, the FERC rejected Entergy’s request for rehearing of its decision to include interest for the seven-month period. The FERC also rejected Entergy’s request for rehearing of the order rejecting the compliance filing with regard to the issue of interest. Finally, the FERC set for hearing and settlement procedures the 2014 compliance filing that included the bandwidth calculation for the seven months June 1, 2005 through December 31, 2005. In setting the compliance filing for hearing, the FERC rejected the APSC’s protest that Entergy Arkansas should not be subject to the filing because Entergy Arkansas would be making the payments during a period following its exit from the System Agreement. In January 2018 the D.C. Circuit affirmed the FERC decision that Entergy Arkansas was subject to the filing.

In December 2011, Entergy filed with the FERC its compliance filing that provided the payments and receipts among the Utility operating companies pursuant to the FERC’s October 2011 order.  The APSC, the LPSC, the PUCT, and other parties intervened in the December 2011 compliance filing proceeding, and the APSC and the LPSC also filed protests. The filing showed the following payments/receipts among the Utility operating companies:

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$156
Entergy Louisiana	($75)
Entergy Mississippi	($33)
Entergy New Orleans	($5)
Entergy Texas	($43)

Entergy Arkansas made its payment in January 2012.  In February 2012, Entergy Arkansas filed for an interim adjustment to its production cost allocation rider requesting that the $156 million be collected from customers over the 22-month period from March 2012 through December 2013.  In March 2012 the APSC issued an order stating that the payment can be recovered from retail customers through the production cost allocation rider, subject to refund.  The LPSC and the APSC requested rehearing of the FERC’s October 2011 order.  

In February 2014 the FERC issued a rehearing order addressing its October 2011 order. The FERC denied the LPSC’s request for rehearing on the issues of whether the bandwidth remedy should be made effective earlier than June 1, 2005, and whether refunds should be ordered for the 20-month refund effective period. The FERC granted the LPSC’s rehearing request on the issue of interest on the bandwidth payments/receipts for the June - December 2005 period, requiring that interest be accrued from June 1, 2006 until the date those bandwidth payments/receipts are made. Also in February 2014 the FERC issued an order rejecting the December 2011 compliance filing that calculated the bandwidth payments/receipts for the June - December 2005 period. The FERC order required a new compliance filing that calculates the bandwidth payments/receipts for the June - December 2005 period based on monthly data for the seven individual months including interest pursuant to the February 2014 rehearing order. Entergy sought rehearing of the February 2014 order with respect to the FERC’s determinations regarding interest. In April 2014 the LPSC filed a petition for review of the FERC’s October 2011 and February 2014 orders with the U.S. Court of Appeals for the D.C. Circuit. In August 2017 the D.C. Circuit issued a decision denying the LPSC’s appeal of the FERC’s October 2011 and February 2014 orders. On the issue of the FERC’s implementation of the prospective remedy as of June 2005 and whether the bandwidth remedy should be extended for an additional 17 months in years 2004-2005, the D.C. Circuit affirmed the FERC’s implementation of the remedy and denied the LPSC’s appeal. On the issue of whether the operating companies should be required to issue refunds for the 20-month period from September 2001 to May 2003, the D.C. Circuit granted the FERC’s request for agency reconsideration and remanded that issue back to the FERC for further proceedings as requested by all parties to the appeal. In response to the D.C. Circuit’s remand, various parties filed briefs with the FERC addressing whether the FERC should require the Utility operating companies to issue refunds for the 20-month refund period from September 2001 to May 2003. The LPSC has argued in favor of such remands and Entergy has opposed the LPSC’s request. The briefing was completed in September 2018 and the matter is pending before the FERC.

In April and May 2014, Entergy filed with the FERC an updated compliance filing that provided the payments and receipts among the Utility operating companies pursuant to the FERC’s February 2014 orders.  The filing showed the following net payments and receipts, including interest, among the Utility operating companies:

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$68
Entergy Louisiana	($10)
Entergy Mississippi	($11)
Entergy New Orleans	$2
Entergy Texas	($49)

These payments were made in May 2014. The LPSC, City Council, and APSC filed protests.

The hearing on the bandwidth calculation for the seven months June 1, 2005 through December 31, 2005 occurred in July 2016. The presiding judge issued an initial decision in November 2016. In the initial decision, the presiding judge agreed with the Utility operating companies’ position that: (1) interest on the bandwidth payments for the 2005 test period should be accrued from June 1, 2006 until the date that the bandwidth payments for that calculation are paid, which is consistent with how the Utility operating companies performed the calculation; and (2) a portion of Entergy Louisiana’s 2001-vintage Louisiana state net operating loss accumulated deferred income tax that results from the Vidalia tax deduction should be excluded from the 2005 test period bandwidth calculation. Various participants filed briefs on exceptions and/or briefs opposing exceptions related to the initial decision, including the LPSC, the APSC, the FERC trial staff, and Entergy Services. In May 2018 the FERC issued an order affirming the initial decision and ordered a comprehensive recalculation of the bandwidth payments/receipts for the seven months June 1, 2005 through December 31, 2005 and a recalculation of the 2006 and 2007 test years as a result of limited revisions. Entergy filed the comprehensive recalculation of the bandwidth payments/receipts for the seven months June 1, 2005 through December 31, 2005 and the 2006 and 2007 test years in July 2018. The filing shows the additional following payments and receipts among the Utility operating companies:

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	($4)
Entergy Louisiana	($23)
Entergy Mississippi	$16
Entergy New Orleans	$5
Entergy Texas	$6

These payments were made in July 2018. In January 2019 the FERC denied the LPSC’s request for rehearing of the May 2018 order.

Rough Production Cost Equalization Rates

Each May from 2007 through 2016 Entergy filed with the FERC the rates to implement the FERC’s orders in the System Agreement proceeding.  These filings showed the following payments/receipts among the Utility operating companies were necessary to achieve rough production cost equalization as defined by the FERC’s orders:

	Payments (Receipts)
	2007			2008			2009			2010			2011			2012			2013			2014
	(In Millions)
Entergy Arkansas		$252			$252			$390			$41			$77			$41			$—			$—
Entergy Louisiana		($211	)		($160	)		($247	)		($22	)		($12	)		($41	)		$—			$—
Entergy Mississippi		($41	)		($20	)		($24	)		($19	)		($40	)		$—			$—			$—
Entergy New Orleans		$—			($7	)		$—			$—			($25	)		$—			($15	)		($15	)
Entergy Texas		($30	)		($65	)		($119	)		$—			$—			$—			$15			$15

The Utility operating companies recorded accounts payable or accounts receivable to reflect the rough production cost equalization payments and receipts required to implement the FERC’s remedy.  When accounts payable were recorded, a corresponding regulatory asset was recorded for the right to collect the payments from customers. When accounts receivable were recorded, a corresponding regulatory liability was recorded for the obligations to pass the receipts on to customers.  No payments were required in 2016 or 2015 to implement the FERC’s remedy based on calendar year 2015 production costs and 2014 production costs, respectively. The System Agreement terminated in August 2016.

The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas.  Entergy Texas recovered its 2013 rough production cost equalization payment over three years beginning April 2014. Entergy Texas included its 2014 rough production cost equalization payment as a component of an interim fuel refund made in 2014. Management believes that any changes in the allocation of production costs resulting from the FERC’s decision and related retail proceedings should result in similar rate changes for retail customers, subject to specific circumstances that have caused trapped costs.

The following rough production cost equalization rate proceedings are still ongoing or were ongoing during the period 2016-2018.

2010 Rate Filing Based on Calendar Year 2009 Production Costs

In May 2010, Entergy filed with the FERC the 2010 rates in accordance with the FERC’s orders in the System Agreement proceeding, and supplemented the filing in September 2010.  Several parties intervened in the proceeding at the FERC, including the LPSC and the City Council, which also filed protests.  In July 2010 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2010, subject to refund.  After an abeyance of the proceeding schedule, a hearing was held in March 2014 and in December 2015 the FERC issued an order. Among other things, the December 2015 order directed Entergy to submit a compliance filing. In January 2016 the LPSC, the APSC, and Entergy filed requests for rehearing of the FERC’s December 2015 order. In February 2016, Entergy submitted the compliance filing ordered in the December 2015 order.  The result of the true-up payments and receipts for the recalculation of production costs resulted in the following payments/receipts among the Utility operating companies:

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$2
Entergy Louisiana	$6
Entergy Mississippi	($4)
Entergy New Orleans	($1)
Entergy Texas	($3)

In September 2016 the FERC accepted the February 2016 compliance filing subject to a further compliance filing made in November 2016. The further compliance filing was required as a result of an order issued in September 2016 ruling on the January 2016 rehearing requests filed by the LPSC, the APSC, and Entergy. In the order addressing the rehearing requests, the FERC granted the LPSC’s rehearing request and directed that interest be calculated on the payment/receipt amounts. The FERC also granted the APSC’s and Entergy’s rehearing request and ordered the removal of both securitized asset accumulated deferred income taxes and contra-securitization accumulated deferred income taxes from the calculation. In November 2016, Entergy submitted its compliance filing in response to the FERC’s order on rehearing. The compliance filing included a revised calculation of the bandwidth true-up payments and receipts based on 2009 test year data and interest calculations. The LPSC protested the interest calculations. In November 2017 the FERC issued an order rejecting the November 2016 compliance filing. The FERC determined that the payments detailed in the November 2016 compliance filing did not include adequate interest for the payments from Entergy Arkansas to Entergy Louisiana because it did not include interest on the principal portion of the payment that was made in February 2016. In December 2017, Entergy recalculated the interest pursuant to the November 2017 order. As a result of the recalculations, Entergy Arkansas owed very minor payments to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.

2011 Rate Filing Based on Calendar Year 2010 Production Costs

In May 2011, Entergy filed with the FERC the 2011 rates in accordance with the FERC’s orders in the System Agreement proceeding.  Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest.  In July 2011 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2011, subject to refund. After an abeyance of the proceeding schedule, in December 2014 the FERC consolidated the 2011 rate filing with the 2012, 2013, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

2012 Rate Filing Based on Calendar Year 2011 Production Costs

In May 2012, Entergy filed with the FERC the 2012 rates in accordance with the FERC’s orders in the System Agreement proceeding.  Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest.  In August 2012 the FERC accepted Entergy’s proposed rates for filing, effective June 2012, subject to refund. After an abeyance of the proceeding schedule, in December 2014 the FERC consolidated the 2012 rate filing with the 2011, 2013, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

2013 Rate Filing Based on Calendar Year 2012 Production Costs

In May 2013, Entergy filed with the FERC the 2013 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest. The City Council intervened and filed comments related to including the outcome of a related FERC proceeding in the 2013 cost equalization calculation. In August 2013 the FERC issued an order accepting the 2013 rates, effective June 1, 2013, subject to refund. After an abeyance of the proceeding schedule, in December 2014 the FERC consolidated the 2013 rate filing with the 2011, 2012, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

2014 Rate Filing Based on Calendar Year 2013 Production Costs

In May 2014, Entergy filed with the FERC the 2014 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest. The City Council intervened and filed comments. In December 2014 the FERC issued an order accepting the 2014 rates, effective June 1, 2014, subject to refund, set the proceeding for hearing procedures, and consolidated the 2014 rate filing with the 2011, 2012, and 2013 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

Consolidated 2011, 2012, 2013, and 2014 Rate Filing Proceedings

As discussed above, in December 2014 the FERC consolidated the 2011, 2012, 2013, and 2014 rate filings for settlement and hearing procedures. In May 2015, Entergy filed direct testimony in the consolidated rate filings and the LPSC filed direct testimony concerning its complaint proceeding that is consolidated with the rate filings, challenging certain components of the pending bandwidth calculations for prior years. Hearings occurred in November 2015, and the ALJ issued an initial decision in July 2016. In the initial decision, the ALJ generally agreed with Entergy’s bandwidth calculations with one exception on the accounting related to the Waterford 3 sale/leaseback. In March 2018 the FERC issued an order affirming the initial decision. In April 2018 the LPSC requested rehearing of the FERC’s March 2018 order affirming the ALJ’s initial decision. Entergy filed in May 2018 the bandwidth true-up payments and receipts for the 2011-2014 rate filings (table does not net to zero due to rounding):

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$3
Entergy Louisiana	$3
Entergy Mississippi	($1)
Entergy New Orleans	$1
Entergy Texas	($5)

These payments were made in May 2018. The LPSC request for rehearing is pending.

Utility Operating Company Termination of System Agreement Participation

Entergy Arkansas and Entergy Mississippi ceased participating in the System Agreement effective December 18, 2013 and November 7, 2015, respectively. Entergy Louisiana, Entergy New Orleans, and Entergy Texas terminated participation in the System Agreement on August 31, 2016, which resulted in the termination of the System Agreement in its entirety pursuant to a settlement agreement approved by the FERC in December 2015.

In December 2013 the FERC set one issue for hearing involving whether and how the benefits associated with settlement with Union Pacific regarding certain coal delivery issues should be allocated among Entergy Arkansas and the other Utility operating companies post-termination of the System Agreement. In December 2014 a FERC ALJ issued an initial decision finding that Entergy Arkansas would realize benefits after December 18, 2013 from the 2008 settlement agreement between Entergy Services, Entergy Arkansas, and Union Pacific, related to certain coal delivery issues. In March 2016 the FERC issued an opinion affirming the December 2014 initial decision with regard to the determination that there were benefits related to the Union Pacific settlement, which were realized post-Entergy Arkansas’s December 2013 withdrawal from the System Agreement, that should be shared with the other Utility operating companies utilizing the methodology proposed by the MPSC and trued-up to actual coal volumes purchased. In May 2016, Entergy made a compliance filing that provided the calculation of Union Pacific settlement benefits utilizing the methodology adopted by the initial decision, trued-up for the actual volumes of coal purchased. The payments were made in May 2016. In August 2016 the FERC issued an order accepting Entergy’s compliance filing. Also in August 2016 the APSC filed a petition for review of the FERC’s March 2016 and August 2016 orders with the U.S. Court of Appeals for the D.C. Circuit. In June 2018 the D.C. Circuit denied the APSC’s petition.

Interruptible Load Proceeding

In April 2007 the U.S. Court of Appeals for the D.C. Circuit issued its opinion in the LPSC’s appeal of the FERC’s March 2004 and April 2005 orders related to the treatment under the System Agreement of the Utility operating companies’ interruptible loads.  In its opinion the D.C. Circuit concluded that the FERC: (1) acted arbitrarily and capriciously by allowing the Utility operating companies to phase-in the effects of the elimination of the interruptible load over a 12-month period of time; (2) failed to adequately explain why refunds could not be ordered under Section 206(c) of the Federal Power Act; and (3) exercised appropriately its discretion to defer addressing the cost of sulfur dioxide allowances until a later time.  The D.C. Circuit remanded the matter to the FERC for a more considered determination on the issue of refunds.  The FERC issued its order on remand in September 2007, in which it directed Entergy to make a compliance filing removing all interruptible load from the computation of peak load responsibility commencing April 1, 2004 and to issue any necessary refunds to reflect this change.  In addition, the order directed the Utility operating companies to make refunds for the period May 1995 through July 1996.  In November 2007 the Utility operating companies filed a refund report describing the refunds to be issued pursuant to the FERC’s orders.  The LPSC filed a protest to the refund report in December 2007.  The refunds were made in October 2008 by the Utility operating companies that owed refunds to the Utility operating companies that were due refunds under the decision.  The APSC and the Utility operating companies appealed the FERC decisions to the D.C. Circuit.

Following the filing of petitioners’ initial briefs, the FERC filed a motion requesting the D.C. Circuit hold the appeal of the FERC’s decisions ordering refunds in the interruptible load proceeding in abeyance and remand the record to the FERC.  The D.C. Circuit granted the FERC’s unopposed motion in June 2009.  In December 2009 the FERC established a paper hearing to determine whether the FERC had the authority and, if so, whether it would be appropriate to order refunds resulting from changes in the treatment of interruptible load in the allocation of capacity costs by the Utility operating companies.  In August 2010 the FERC issued an order stating that it has the authority and refunds are appropriate.  The APSC, the MPSC, and Entergy requested rehearing of the FERC’s decision.  In June 2011 the FERC issued an order granting rehearing in part and denying rehearing in part, in which the FERC determined to invoke its discretion to deny refunds.  The FERC held that in this case where “the Entergy system as a whole collected the proper level of revenue, but, as was later established, incorrectly allocated peak load responsibility among the various Entergy operating companies….the Commission will apply here our usual practice in such cases, invoking our equitable discretion to not order refunds, notwithstanding our authority to do so.”  The LPSC requested rehearing of the FERC’s June 2011 decision.  In July 2011 the refunds made in the fourth quarter 2008 described above were reversed. In October 2011 the FERC issued an “Order Establishing Paper Hearing” inviting parties that oppose refunds to file briefs within 30 days addressing the LPSC’s argument that FERC precedent supports refunds under the circumstances present in this proceeding.  Parties that favor refunds were then invited to file reply briefs within 21 days of the date that the initial briefs were due.  

In March 2013 the FERC issued an order denying the LPSC’s request for rehearing of the FERC’s June 2011 order wherein the FERC concluded it would exercise its discretion and not order refunds in the interruptible load proceeding. Based on its review of the LPSC’s request for rehearing and the briefs filed as part of the paper hearing established in October 2011, the FERC affirmed its earlier ruling and declined to order refunds under the circumstances of the case. In May 2013 the LPSC filed a petition for review with the U.S. Court of Appeals for the D.C. Circuit seeking review of FERC orders in the interruptible load proceeding that concluded that the FERC would exercise its discretion and not order refunds in the proceeding. Oral argument was held on the appeal in the D.C. Circuit in September 2014. In December 2014 the D.C. Circuit issued an order on the LPSC’s appeal and remanded the case back to the FERC. The D.C. Circuit rejected the LPSC’s argument that there is a presumption in favor of refunds, but it held that the FERC had not adequately explained its decision to deny refunds and directed the FERC “to consider the relevant factors and weigh them against one another.” In March 2015, Entergy filed with the FERC an initial brief on remand to address the December 2014 decision by the D.C. Circuit. The initial brief on remand argued that the FERC, in response to the D.C. Circuit decision, should clarify its policy on refunds and find that refunds are not required in the interruptible load proceeding.

In April 2016 the FERC issued an order on remand that addressed the December 2014 decision by the D.C. Circuit in the interruptible load proceeding. The order on remand affirmed the FERC’s denial of refunds for the 15-month refund effective period. The FERC explained and clarified its policies regarding refunds and concluded that the evidence in the record demonstrated that the relevant equitable factors favored not requiring refunds in this case. The FERC also noted that, under Section 206(c) of the Federal Power Act, in a Section 206 proceeding involving two or more electric utility companies of a registered holding company system, the FERC may order refunds only if it determines the refunds would not cause the registered holding company to experience any reduction in revenues resulting from an inability of an electric utility company in the system to recover the resulting increase in costs. The FERC stated it was not able to find that the Entergy system would not experience a reduction in revenues if refunds were awarded in this proceeding, which further supported the denial of refunds. In May 2016 the LPSC filed a request for rehearing of the FERC’s April 2016 order. In September 2016 the FERC issued an order denying the LPSC’s request for rehearing and reaffirming its denial of refunds for the 15-month refund effective period. The LPSC appealed the April and September 2016 orders to the U.S. Court of Appeals for the D.C. Circuit. In March 2018 the D.C. Circuit issued an order denying the LPSC’s appeal and affirming the FERC’s decision that it would be inequitable to award refunds in the proceeding. In April 2018 the LPSC sought rehearing en banc of the D.C. Circuit’s order denying the LPSC’s appeal. In May 2018 the D.C. Circuit denied the LPSC’s rehearing request. In August 2018 the LPSC filed with the Supreme Court of the United States a petition for a writ of certiorari to review the judgment of the D.C. Circuit. In November 2018 the Supreme Court of the United States denied the LPSC’s petition for a writ of certiorari to review the judgment of the D.C. Circuit, effectively terminating the interruptible load proceeding.

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’s 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’s appeal and held all of the appeals in abeyance pending final resolution of the related proceeding before the FERC.

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 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. 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.

Complaints Against System Energy

Return on Equity 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 the FERC to institute 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. System Energy is recording a provision against revenue for the potential outcome of this proceeding. In September 2017 the FERC established a refund effective date of January 23, 2017, consolidated the return on equity complaint with the proceeding described in Unit Power Sales Agreement below, 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 effective date 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 System Energy’s return on equity, with a refund effective date of April 2018. The portion of the LPSC’s complaint dealing with return on equity was subsequently consolidated with the APSC and MPSC complaint for hearing. The consolidated hearing has been scheduled for September 2019, and the parties are required to address 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 complaint, and System Energy submitted a response to the amended complaint in October 2018. In January 2019 the FERC set the amended complaint for settlement and hearing proceedings.

Grand Gulf Sale-leaseback Renewal Complaint

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 2018. The hearing has been scheduled for November 2019.

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 proposed amendments would result in lower charges to the Utility operating companies that buy capacity and energy from System Energy under the Unit Power Sales Agreement. The proposed changes are 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. System Energy requested that the FERC accept the amendments effective October 1, 2017.

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 propose 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. The FERC also consolidated the Unit Power Sales Agreement amendment proceeding with the proceeding described in“Return on Equity Complaints” above, and directed the parties to engage in settlement proceedings before an ALJ. 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.  The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages.  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.

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.  In February 2012, Entergy Louisiana sold 500,000 of its Class A preferred membership units in Entergy Holdings Company LLC, a wholly-owned Entergy subsidiary, to a third party in exchange for $51 million plus accrued but unpaid distributions on the units.  The 500,000 preferred membership units are mandatorily redeemable in January 2112.

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. As of April 30, 2016, Entergy Mississippi’s storm damage provision balance was less than $10 million, therefore Entergy Mississippi resumed billing the monthly storm damage provision effective with June 2016 bills. As of September 30, 2016, however, Entergy Mississippi’s storm damage provision balance exceeded $15 million. Accordingly the storm damage provision was reset to zero beginning with November 2016 bills. As of July 31, 2017, the balance in Entergy Mississippi’s accumulated storm damage provision was again less than $10 million, therefore Entergy Mississippi resumed billing the monthly storm damage provision effective with September 2017 bills. As of June 30, 2018, Entergy Mississippi’s storm damage provision balance exceeded $15 million. Accordingly the storm damage provision was reset to zero beginning with August 2018 bills.

Entergy New Orleans

In August 2012, Hurricane Isaac caused extensive damage to Entergy New Orleans’s service area. In January 2015 the City Council issued a resolution approving the terms of a joint agreement in principle filed by Entergy New Orleans, Entergy Louisiana, and the City Council Advisors determining, among other things, that Entergy New Orleans’s prudently-incurred storm recovery costs were $49.3 million, of which $31.7 million, net of reimbursements from the storm reserve escrow account, remained recoverable from Entergy New Orleans’s electric customers. The resolution also directed Entergy New Orleans to file an application to securitize the unrecovered City Council-approved storm recovery costs of $31.7 million pursuant to the Louisiana Electric Utility Storm Recovery Securitization Act (Louisiana Act 64). In addition, the resolution found that it was reasonable for Entergy New Orleans to include in the principal amount of its potential securitization the costs to fund and replenish Entergy New Orleans’s storm reserve in an amount that achieved the City Council-approved funding level of $75 million. In January 2015, in compliance with that directive, Entergy New Orleans filed with the City Council an application requesting that the City Council grant a financing order authorizing the financing of Entergy New Orleans’s storm costs, storm reserves, and issuance costs pursuant to Louisiana Act 64. In May 2015 the parties entered into an agreement in principle and the City Council issued a financing order authorizing Entergy New Orleans to issue storm recovery bonds in the aggregate amount of $98.7 million, including $31.8 million for recovery of Entergy New Orleans’s Hurricane Isaac storm recovery costs, including carrying costs, $63.9 million to fund and replenish Entergy New Orleans’s storm reserve, and approximately $3 million for estimated up-front financing costs associated with the securitization. See Note 5 to the financial statements for discussion of the issuance of the securitization bonds in July 2015.

New Nuclear Generation Development Costs

Entergy Louisiana

Entergy Louisiana and Entergy Gulf States Louisiana were developing a project option for new nuclear generation at River Bend.  In March 2010, Entergy Louisiana and Entergy Gulf States Louisiana filed with the LPSC seeking approval to continue the limited development activities necessary to preserve an option to construct a new unit at River Bend.  At its June 2012 meeting the LPSC voted to uphold an ALJ recommendation that the request of Entergy Louisiana and Entergy Gulf States Louisiana be declined on the basis that the LPSC’s rule on new nuclear development does not apply to activities to preserve an option to develop and on the further grounds that the companies improperly engaged in advanced preparation activities prior to certification.  The LPSC directed that Entergy Louisiana and Entergy Gulf States Louisiana be permitted to seek recovery of these costs in their upcoming rate case filings that were subsequently filed in February 2013. In the resolution of the rate case proceeding the LPSC provided for an eight-year amortization of costs incurred in connection with the potential development of new nuclear generation at River Bend, without carrying costs, beginning in December 2014, provided, however, that amortization of these costs shall not result in a future rate increase. As of December 31, 2018, Entergy Louisiana has a regulatory asset of $28.5 million on its balance sheet related to these new nuclear generation development costs.

Entergy Texas [Member]

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, 2018 and 2017:

Other Regulatory Assets

Entergy

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$2,611.5		$2,642.3
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	814.3		746.0
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 – Storm Cost Recovery Filings with Retail Regulators) (Note 5)	452.7		558.9
Removal costs - recovered through depreciation rates (Note 9)	375.8		436.5
Opportunity Sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding)	116.3		109.8
Unamortized loss on reacquired debt - recovered over term of debt	74.5		82.9
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy)	52.1		73.7
Retail rate deferrals - recovered through rate riders as rates are redetermined by retail regulators	39.0		86.4
New nuclear generation development costs (Note 2 - New Nuclear Generation Development Costs) (b)	29.0		36.4
Transition to competition costs - recovered over a 15-year period through February 2021	26.7		37.7
Other	154.6		125.1
Entergy Total		$4,746.5		$4,935.7

Entergy Arkansas

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$747.2		$757.0
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	381.7		345.2
Removal costs - recovered through depreciation rates (Note 9)	138.3		176.9
Opportunity sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding)	116.3		109.8
Storm damage costs - recovered either through securitization or retail rates (Note 5 - Entergy Arkansas Securitization Bonds)	60.7		76.2
Unamortized loss on reacquired debt - recovered over term of debt	21.2		24.3
Retail rate deferrals - recovered through rate riders as rates are redetermined annually	20.5		28.2
ANO Fukushima and Flood Barrier costs - recovered through retail rates through February 2026 (Note 2 - Retail Rate Proceedings) (b)	12.6		14.4
Other	36.5		35.4
Entergy Arkansas Total		$1,535.0		$1,567.4

Entergy Louisiana

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (a)		$711.8		$724.6
Asset Retirement Obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	232.9		218.6
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy)	49.8		71.4
New nuclear generation development costs - recovery through formula rate plan December 2014 through November 2022 (Note 2 - New Nuclear Generation Development Costs) (b)	28.5		35.8
Unamortized loss on reacquired debt - recovered over term of debt	22.5		24.7
Storm damage costs - recovered through retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)	17.9		14.3
Business combination external costs deferral - recovery through formula rate plan December 2015 through November 2025 (b)	12.4		14.1
River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC)	11.0		12.9
Other	18.3		29.4
Entergy Louisiana Total		$1,105.1		$1,145.8

Entergy Mississippi

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$215.9		$218.7
Removal costs - recovered through depreciation rates (Note 9)	63.5		91.6
Attorney General litigation costs (Note 2 - Mississippi Attorney General Complaint) (b)	23.6		9.3
Retail rate deferrals - recovered through rate riders as rates are redetermined annually	16.6		49.4
Unamortized loss on reacquired debt - recovered over term of debt	16.2		17.6
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a)	7.2		7.6
Other	—		3.7
Entergy Mississippi Total		$343.0		$397.9

Entergy New Orleans

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$96.2		$102.8
Storm damage costs, including hurricane costs - recovered through retail rates and securitization (Note 2 - Storm Cost Recovery Filings with Retail Regulators)	70.4		82.3
Removal costs - recovered through depreciation rates (Note 9)	49.3		44.8
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a)	4.5		4.3
Unamortized loss on reacquired debt - recovered over term of debt	2.6		3.0
Rate case costs - recovered over a 6-year period through September 2021 (Note 2 - Retail Rate Proceedings)	1.9		2.6
Retail rate deferrals - recovered through rate riders as rates are redetermined monthly or annually	—		4.4
Other	4.9		7.2
Entergy New Orleans Total		$229.8		$251.4

Entergy Texas

	2018		2017
	(In Millions)
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 5 - Entergy Texas Securitization Bonds)		$303.6		$386.1
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)	171.8		169.2
Removal costs - recovered through depreciation rates (Note 9)	50.9		55.2
Transition to competition costs - recovered over a 15-year period through February 2021	26.7		37.7
Neches and Sabine costs - recovered over a ten-year period through September 2028 (Note 2 - Retail Rate Proceedings) (b)	23.6		—
Unamortized loss on reacquired debt - recovered over term of debt	8.2		8.7
Other	13.2		4.5
Entergy Texas Total		$598.0		$661.4

System Energy

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Other Postretirement Benefits) (a)		$179.3		$202.7
Asset retirement obligation - recovery dependent upon timing of decommissioning (Note 9) (a)	186.9		169.1
Removal costs - recovered through depreciation rates (Note 9)	76.4		67.9
Unamortized loss on reacquired debt - recovered over term of debt	3.8		4.6
System Energy Total		$446.4		$444.3

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

(b) Does not earn a return on investment.

Other Regulatory Liabilities

Entergy

	2018		2017
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)		$815.9		$989.3
Vidalia purchased power agreement (Note 8) (b)	139.7		151.6
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) (b)	111.1		124.8
Income tax rate change - returned to electric and gas customers through retail rates (Note 2 - Retail Rate Proceedings)	74.7		—
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions)	67.9		67.9
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination)	50.8		65.8
Grand Gulf over-recovery - will be refunded through rate riders as rates are redetermined annually	48.6		—
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)	44.4		—
Internal restructuring guaranteed customer credits (Note 2 - Retail Rate Proceedings)	39.6		—
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)	39.1		36.7
Excess decommissioning recovery for Willow Glen - (Note 14 - Dispositions)	31.9		—
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement	25.0		32.1
Removal costs - returned to customers through depreciation rates (Note 9)	18.8		32.4
Other	68.4		43.5
Entergy Total		$1,620.3		$1,588.5

Entergy Arkansas

	2018		2017
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)		$297.2		$354.0
Internal restructuring guaranteed customer credits (Note 2 - Retail Rate Proceedings)	39.6		—
Future formula rate plan revenue reductions (Note 2 - Retail Rate Proceedings)	35.1		—
Grand Gulf over-recovery - will be refunded through rate riders as rates are redetermined annually	26.0		—
Other	4.8		9.6
Entergy Arkansas Total		$402.7		$363.6

Entergy Louisiana

	2018		2017
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)		$274.1		$323.7
Vidalia purchased power agreement (Note 8) (b)	139.7		151.6
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) (b)	111.1		124.8
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination)	50.8		65.8
Income tax rate change - returned to electric customers through retail rates September 2018 through August 2019 (Note 2 - Retail Rate Proceedings)	49.9		—
Asset Retirement Obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)	39.1		36.7
Excess decommissioning recovery for Willow Glen - (Note 14 - Dispositions)	31.9		—
Removal costs - returned to customers through depreciation rates (Note 9)	18.8		32.4
Other	33.4		26.1
Entergy Louisiana Total		$748.8		$761.1

Entergy Mississippi

	2018		2017
	(In Millions)
Grand Gulf Over-Recovery - returned to customers through rate riders when rates are redetermined annually		$22.6		$—
Future formula rate plan revenue reductions (Note 2 - Retail Rate Proceedings)	9.3		—
Other	1.7		0.9
Entergy Mississippi Total		$33.6		$0.9

Entergy Texas

	2018		2017
	(In Millions)
Income tax rate change - refunded through a rate rider (Note 2 - Retail Rate Proceedings)		$23.1		$—
Advanced metering system surcharge (Note 2 - Advanced Metering Infrastructure (AMI) Filings)	16.5		—
Transition to competition costs - returned to customers through rate riders when rates are redetermined periodically	4.2		4.8
Other	4.1		2.1
Entergy Texas Total		$47.9		$6.9

System Energy

	2018		2017
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 17) (a)		$244.6		$311.6
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions)	67.9		67.9
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
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement	25.0		32.1
System Energy Total		$381.9		$456.0

(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 $25.0 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 will be 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 to be 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 existing formula rate plan rider for its customers to realize the remaining benefits of the Tax Act. Entergy Arkansas’s formula rate plan rider includes a netting adjustment that compares 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.

Entergy Louisiana

In a 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 will be 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. Entergy Mississippi’s formula rate plan includes a look-back evaluation report filing in March 2019 that will compare actual 2018 results to the allowed return on rate base. The stipulation approved in June 2018 provides 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 any true-up to be 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. In November 2018, Entergy Mississippi’s annual redetermination of the annual factor to be applied under the power management rider included an insignificant true-up to the amount of unprotected excess accumulated deferred income taxes. In January 2019 the MPSC approved the proposed power management cost factor effective for February 2019 bills.

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. In both a memorandum issued prior to the open meeting when the order was discussed and during the discussions at the open meeting regarding the order, the PUCT indicated that it would consider utility earnings in determining the treatment of the liability and the effects of the Tax Act. 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. Entergy Texas also stated that it would be inappropriate for the PUCT to require a refund of the reduction in income tax expense in 2018 resulting from the Act on a retroactive basis and without a comprehensive review of Entergy Texas’s cost of service and earned return on equity.

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 will 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 will 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 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 larger customers and over a period of four years for other customers.

System Energy

In a filing made with the FERC in March 2018, Entergy proposed revisions to the Unit Power Sales Agreement, among other agreements, to reflect the effects of the Tax Act. In the filing System Energy proposed to return all of its 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 are ongoing.

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, 2018 and 2017 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.

	2018			2017
	(In Millions)
Entergy Arkansas (a)		$86.5			$130.4
Entergy Louisiana (b)		$136.7			$96.7
Entergy Mississippi		$8.0			$32.4
Entergy New Orleans (b)		$2.8			($3.7	)
Entergy Texas		($19.7	)		($67.3	)

(a) Includes $67.3 million in 2018 and $67.1 million in 2017 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

Production Cost Allocation Rider

The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings, which are discussed in the “System Agreement Cost Equalization Proceedings” section below.

In May 2016, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected recovery of the production cost allocation rider true-up adjustment of the 2014 and 2015 unrecovered retail balance in the amount of $1.9 million. Additionally, the redetermined rates reflected the recovery of a $1.9 million System Agreement bandwidth remedy payment resulting from a compliance filing pursuant to the FERC’s December 2015 order related to test year 2009 production costs. The rates for the 2016 production cost allocation rider update were effective July 2016 through June 2017.

In May 2017, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected a credit amount of $0.3 million resulting from a compliance filing pursuant to the FERC’s September 2016 order. Additionally, the redetermined rate reflected recovery of the production cost allocation rider true-up adjustment of the 2016 unrecovered retail balance in the amount of $0.3 million. Because of the small effect of the 2017 production cost allocation rider update, Entergy Arkansas proposed to reduce the effective period of the update to one month, July 2017. After the one month collection period, rates were set to zero for all rate classes for the period August 2017 through June 2018.

In May 2018, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected recovery of the 2017 under-recovered retail balance and a $2.8 million payment by Entergy Arkansas associated with a compliance filing pursuant to a March 2018 FERC order related to 2010 production costs. The rates for the 2018 production cost allocation rider update are effective July 2018 through June 2019.

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.

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 December 2011 the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates.  The audit included a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 2005 through 2009.  In March 2016 the LPSC staff consultant issued its audit report. In its report, the LPSC staff consultant recommended that Entergy Louisiana refund approximately $8.6 million, plus interest, to customers and realign the recovery of approximately $12.7 million from Entergy Gulf States Louisiana’s fuel adjustment clause to base rates. In September 2016 the LPSC staff filed testimony stating that it was no longer recommending a disallowance of $3.4 million of the $8.6 million discussed above, but otherwise maintained the positions from its report. Subsequently, the parties entered into a settlement, which was approved by the LPSC in November 2016. The settlement recognized the dry cask storage recovery method issue, which was addressed in the separate proceeding approved by the LPSC in October 2017, provided for a refund of $5 million, which was made to legacy Entergy Gulf States Louisiana customers in December 2016, and resolved all other issues raised in the audit.

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 is evaluating the staff’s recommended disallowance.

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 consultant issued its audit report. In its report, the LPSC staff consultant recommended 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 is evaluating the staff’s recommended disallowance.

In June 2016 the LPSC staff provided notice of audits of Entergy Louisiana’s fuel adjustment clause filings and purchased gas adjustment clause filings. In recognition of the business combination that occurred in 2015, the audit notice was issued to Entergy Louisiana and will also include a review of charges to legacy Entergy Gulf States Louisiana customers prior to the business combination. The audit includes 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. Discovery commenced in March 2017. No report of audit has been issued.

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.  Discovery commenced in September 2018.  No report of audit has been issued.

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 November 2015, 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 a projected over-recovery balance of $48 million projected through January 31, 2016. In January 2016 the MPSC approved the redetermined annual factor effective February 1, 2016. The MPSC further ordered, however, that due to the significant change in natural gas price forecasts since Entergy Mississippi’s filing in November 2015 Entergy Mississippi should file a revised fuel factor with the MPSC no later than February 1, 2016. Pursuant to that order, Entergy Mississippi submitted a revised fuel factor. Additionally, because Entergy Mississippi’s projected over-recovery balance for the period ending January 31, 2016 was $68 million, in February 2016, Entergy Mississippi filed for another interim adjustment to the energy cost factor effective April 2016 to flow through to customers the projected over-recovery balance over a six-month period. That interim adjustment was approved by the MPSC in February 2016 effective for April 2016 bills.

In November 2016, 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 less than $2 million as of September 30, 2016. In January 2017 the MPSC approved the annual factor effective with February 2017 bills. Also 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 its order, the MPSC expressly reserved the right to review and determine the recoverability of any and all purchased power expenditures made during fiscal year 2016. The MPSC hired independent auditors to conduct an annual operations audit and a financial audit. The independent auditors issued their audit reports in December 2017. The audit reports included several recommendations for action by Entergy Mississippi but did not recommend any cost disallowances. In January 2018 the MPSC certified the audit reports to the Mississippi Legislature. In November 2017 the Public Utilities Staff separately engaged a consultant to review the outage at the Grand Gulf Nuclear Station that began in 2016. The review is currently in progress.

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. Entergy Mississippi proposed a two-tiered energy cost factor designed to promote overall rate stability throughout 2018 particularly during the summer months. 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.

Mississippi Attorney General Complaint

The Mississippi Attorney General filed a complaint in state court in December 2008 against Entergy Corporation, Entergy Mississippi, Entergy Services, and Entergy Power alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution.  The complaint is wide ranging and relates to tariffs and procedures under which Entergy Mississippi purchases power not generated in Mississippi to meet electricity demand.  Entergy believes the complaint is unfounded.  In December 2008 the defendant Entergy companies removed the Attorney General’s lawsuit to U.S. District Court in Jackson, Mississippi. In June 2010 the MPSC authorized the deferral of certain legal expenses associated with this litigation until it is resolved. As of December 31, 2018, Entergy Mississippi has a regulatory asset of $23.6 million for these deferred legal expenses. Pre-trial and settlement conferences were held in October 2018. In October 2018 the District Court rescheduled the trial to April 2019.

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 July 2015 certain parties filed briefs in a PUCT proceeding asserting that Entergy Texas should refund to retail customers an additional $10.9 million in bandwidth remedy payments Entergy Texas received related to calendar year 2006 production costs.  In October 2015 an ALJ issued a proposal for decision recommending that the additional bandwidth remedy payments be refunded to retail customers. In January 2016 the PUCT issued its order affirming the ALJ’s recommendation, and Entergy Texas filed a motion for rehearing of the PUCT’s decision, which the PUCT denied. In March 2016, Entergy Texas filed a complaint in Federal District Court for the Western District of Texas and a petition in the Travis County (State) District Court appealing the PUCT’s decision. The pending appeals did not stay the PUCT’s decision. In April 2016, Entergy Texas filed with the PUCT an application to refund to customers approximately $56.2 million. The refund resulted from (i) $41.8 million of fuel cost recovery over-collections through February 2016, (ii) the $10.9 million in bandwidth remedy payments, discussed above, that Entergy Texas received related to calendar year 2006 production costs, and (iii) $3.5 million in bandwidth remedy payments that Entergy Texas received related to 2006-2008 production costs. In June 2016, Entergy Texas filed an unopposed settlement agreement that added additional over-recovered fuel costs for the months of March and April 2016. The settlement resulted in a $68 million refund. The ALJ approved the refund on an interim basis and it was made to most customers over a four-month period beginning with the first billing cycle of July 2016. In July 2016 the PUCT issued an order approving the interim refund. The federal appeal of the PUCT’s January 2016 decision was heard in December 2016, and the Federal District Court granted Entergy Texas’s requested relief. In January 2017 the PUCT and an intervenor filed petitions for appeal of the Federal District Court ruling to the U.S. Court of Appeals for the Fifth Circuit. Oral argument was held before the Fifth Circuit in February 2018. In April 2018 the Fifth Circuit reversed the decision of the Federal District Court, reinstating the original PUCT decision. In October 2018, Entergy Texas filed notice of nonsuit in its appeal to the Travis County District Court regarding the PUCT’s January 2016 decision.

In July 2016, Entergy Texas filed an application to reconcile its fuel and purchased power costs for the period April 1, 2013 through March 31, 2016. During the reconciliation period, Entergy Texas incurred approximately $1.77 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 over-recovery balance of approximately $19.3 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning April 2016. Entergy Texas also noted, however, that the estimated $19.3 million over collection was being refunded to customers as a portion of the interim fuel refund beginning with the first billing cycle of July 2016, discussed above. Entergy Texas also requested a prudence finding for each of the fuel-related contracts and arrangements entered into or modified during the reconciliation period that have not been reviewed by the PUCT in a prior proceeding. In December 2016, Entergy Texas entered into a stipulation and settlement agreement resulting in a $6 million disallowance not associated with any particular issue raised and a refund of the over-recovery balance of $21 million as of November 30, 2016, to most customers beginning April 2017 through June 2017. This settlement was developed concurrently with the stipulation and settlement agreement in the 2016 transmission cost recovery factor rider amendment discussed below, and the terms and conditions in both settlements are interdependent. The fuel reconciliation settlement was approved by the PUCT in March 2017 and the refunds were made.

In June 2017, Entergy Texas filed an application for a fuel refund of approximately $30.7 million for the months of December 2016 through April 2017. For most customers, the refunds flowed through bills for the months of July 2017 through September 2017. The fuel refund was approved by the PUCT in August 2017.

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.

Retail Rate Proceedings

Filings with the APSC (Entergy Arkansas)

Retail Rates

2015 Base Rate Filing

In April 2015, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. The filing notified the APSC of Entergy Arkansas’s intent to implement a forward test year formula rate plan pursuant to Arkansas legislation passed in 2015, and requested a retail rate increase of $268.4 million, with a net increase in revenue of $167 million. The filing requested a 10.2% return on common equity. In December 2015, Entergy Arkansas, the APSC staff, and certain of the intervenors in the rate case filed with the APSC a joint motion for approval of a settlement of the case that proposed a retail rate increase of approximately $225 million with a net increase in revenue of approximately $133 million; an authorized return on common equity of 9.75%; and a formula rate plan tariff that provides a +/- 50 basis point band around the 9.75% allowed return on common equity. A significant portion of the rate increase is related to Entergy Arkansas’s acquisition in March 2016 of Union Power Station Power Block 2 for a base purchase price of $237 million. The settlement agreement also provided for amortization over a 10-year period of $7.7 million of previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance. In February 2016 the APSC approved the settlement with one exception that reduced the retail rate increase proposed in the settlement by $5 million. The settling parties agreed to the APSC modifications in February 2016. The new rates were effective February 24, 2016 and began billing with the first billing cycle of April 2016. In March 2016, Entergy Arkansas made a compliance filing regarding the new rates that included an interim base rate adjustment surcharge, effective with the first billing cycle of April 2016, to recover the incremental revenue requirement for the period February 24, 2016 through March 31, 2016. The interim base rate adjustment surcharge was designed to recover a total of $21.1 million over the nine-month period from April 2016 through December 2016.

2016 Formula Rate Plan Filing

In July 2016, Entergy Arkansas filed with the APSC its 2016 formula rate plan filing showing Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2017 test period to be below the formula rate plan bandwidth. The filing requested a $67.7 million revenue requirement increase to achieve Entergy Arkansas’s target earned return on common equity of 9.75%. In October 2016, Entergy Arkansas filed with the APSC revised formula rate plan attachments with an updated request for a $54.4 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors, as well as three additional adjustments identified as appropriate by Entergy Arkansas. In November 2016 a hearing was held and the APSC issued an order directing the parties to brief certain issues. In December 2016 the APSC approved a settlement agreement and the $54.4 million revenue requirement increase with approximately $25 million of the $54.4 million revenue requirement subject to possible future adjustment and refund to customers with interest. The APSC requested supplemental information for some of Entergy Arkansas’s requested nuclear expenditures. In December 2016 the APSC approved Entergy Arkansas’s formula rate plan compliance tariff, and the rates became effective with the first billing cycle of January 2017. In April 2017, Entergy Arkansas filed a motion consented to by all parties requesting that it be permitted to submit the supplemental information requested by the APSC in conjunction with its 2017 formula rate plan filing, which was subsequently made in July 2017 and is discussed below. In May 2017 the APSC approved the joint motion and proposal to review Entergy Arkansas’s supplemental information on a concurrent schedule with the 2017 formula rate plan filing. In October 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement resolving all issues in the proceeding and providing for recovery of the 2017 and 2018 nuclear costs. In December 2017 the APSC approved the settlement agreement and recovery of the 2017 and 2018 nuclear costs.

2017 Formula Rate Plan Filing

In July 2017, Entergy Arkansas filed with the APSC its 2017 formula rate plan filing showing Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2018 test period to be below the formula rate plan bandwidth.  The filing projected a $129.7 million revenue requirement increase to achieve Entergy Arkansas’s target earned return on common equity of 9.75%.  Entergy Arkansas’s formula rate plan is subject to a four percent annual revenue constraint and the projected annual revenue requirement increase exceeded the four percent, resulting in a proposed increase for the 2017 formula rate plan of $70.9 million. In October 2017, Entergy Arkansas filed with the APSC revised formula rate plan attachments that projected a $126.2 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors. The revised formula rate plan filing included a proposed $71.1 million revenue requirement increase based on a revision to the four percent constraint calculation. In October 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement resolving all issues in the proceeding and providing for recovery of the 2017 and 2018 nuclear costs. In December 2017 the APSC approved the settlement agreement and the $71.1 million revenue requirement increase, as well as Entergy Arkansas’s formula rate plan compliance tariff, and the rates became effective with the first billing cycle of January 2018.

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 shows 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 includes 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 includes a projected $73.4 millionrevenue 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 exceeds the constraint, the resulting increase is 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, which included additional actual revenues for 2018. 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 certain 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. An additional schedule was issued by the APSC for briefing other contested issues, the outcome of which did not affect the 2018 filing but could affect future Entergy Arkansas formula rate plan filings. That briefing was completed in February 2019, and the APSC has not indicated when a decision on those issues can be expected.

Similar to the 2018 filing, the formula rate plan filing that will be made in 2019 to set the formula rates for the 2020 calendar year will include a netting adjustment that will compare projected costs and sales for 2018 that were approved in the 2017 formula rate plan filing to actual 2018 costs and sales data. In the fourth quarter 2018, Entergy Arkansas recorded a provision of $35.1 million that reflects the estimate of the historical year netting adjustment that will be included in the 2019 filing to reflect the change in formula rate plan revenues associated with actual 2018 results when compared to the allowed rate of return on equity. 

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. Entergy Arkansas also filed a notice with the Missouri Public Service Commission in December 2017 out of an abundance of caution, although Entergy Arkansas does not serve any retail customers in Missouri. In April 2018 the Missouri Public Service Commission approved Entergy Arkansas’s filing. 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

2015 Formula Rate Plan Filing

In May 2016, Entergy Louisiana filed its formula rate plan evaluation report for its 2015 calendar year operations. The evaluation report reflected an earned return on common equity of 9.07%. As such, no adjustment to base formula rate plan revenue was required. The following other adjustments, however, were required under the formula rate plan: an increase in the legacy Entergy Louisiana additional capacity mechanism of $14.2 million; a separate increase in legacy Entergy Louisiana revenue of $10 million primarily to reflect the effects of the termination of the System Agreement; an increase in the legacy Entergy Gulf States Louisiana additional capacity mechanism of $0.5 million; a decrease in legacy Entergy Gulf States Louisiana revenue of $58.7 million primarily to reflect the effects of the termination of the System Agreement; and an increase of $11 million to the MISO cost recovery mechanism. Rates were implemented with the first billing cycle of September 2016, subject to refund. Following implementation of the as-filed rates in September 2016, there were several interim updates to Entergy Louisiana’s formula rate plan, including the one submitted in December 2016, reflecting implementation of the settlement of the Waterford 3 replacement steam generator project prudence review described below. In June 2017 the LPSC staff and Entergy Louisiana filed a joint report of proceedings, which was accepted by the LPSC in June 2017, finalizing the results of the May 2016 evaluation report, interim updates, and corresponding proceedings with no changes to rates already implemented.

2016 Formula Rate Plan Filing

In May 2017, Entergy Louisiana filed its formula rate plan evaluation report for its 2016 calendar year operations. The evaluation report reflected an earned return on common equity of 9.84%. As such, no adjustment to base formula rate plan revenue was required. Adjustments, however, were required under the formula rate plan; the 2016 formula rate plan evaluation report showed a decrease in formula rate plan revenue of approximately $16.9 million, comprised of a decrease in legacy Entergy Louisiana formula rate plan revenue of $3.5 million, a decrease in legacy Entergy Gulf States Louisiana formula rate plan revenue of $9.7 million, and a decrease in incremental formula rate plan revenue of $3.7 million. Additionally, the formula rate plan evaluation report called for a decrease of $40.5 million in the MISO cost recovery revenue requirement from $46.8 million to $6.3 million. Rates reflecting these adjustments were implemented with the first billing cycle of September 2017, subject to refund. In September 2017 the LPSC issued its report indicating that no changes to Entergy Louisiana’s original formula rate plan evaluation report were required but reserved for several issues, including Entergy Louisiana’s September 2017 update to its formula rate plan evaluation report.  In July 2018, Entergy Louisiana and the LPSC staff filed an unopposed joint report setting forth a correction to the annualization calculation, the effect of which was a net $3.5 million revenue requirement reduction and indicating that there are no outstanding issues with the 2016 formula rate plan report, the supplemental report, or the interim updates.  In September 2018 the LPSC approved the unopposed joint report.

Formula Rate Plan Extension Through 2019 Test Year

In August 2017, Entergy Louisiana filed a request with the LPSC seeking to extend its formula rate plan for three years (2017-2019) with limited modifications of its terms.  Those modifications include: a one-time resetting of base rates to the midpoint of the band at Entergy Louisiana’s authorized return on equity of 9.95% for the 2017 test year; narrowing of the formula rate plan bandwidth from a total of 160 basis points to 80 basis points; and a forward-looking mechanism that would allow Entergy Louisiana to recover certain transmission-related costs contemporaneously with when those projects begin delivering benefits to customers.  In April 2018 the LPSC approved an unopposed joint motion filed by Entergy Louisiana and the LPSC staff that settled the matter. The settlement extended the formula rate plan for three years, providing for rates through at least August 2021. In addition to retaining the major features of the traditional formula rate plan, substantive features of the extended formula rate plan include:

• a mid-point reset of formula rate plan revenues to a 9.95% earned return on common equity for the 2017 test year and for the St. Charles Power Station when it enters commercial operation;

• a 9.8% target earned return on common equity for the 2018 and 2019 test years;

• narrowing of the common equity bandwidth to plus or minus 60 basis points around the target earned return on common equity;

• a cap on potential revenue increase of $35 million for the 2018 evaluation period, and $70 million for the cumulative 2018 and 2019 evaluation periods, on formula rate plan cost of service rate increases (the cap excludes rate changes associated with the transmission recovery mechanism described below and rate changes associated with additional capacity);

• a framework for the flow back of certain tax benefits created by the Tax Act to customers, as described in “Regulatory activity regarding the Tax Cuts and Jobs Act” above; and

• a transmission recovery mechanism providing for the opportunity to recover certain transmission-related expenditures in excess of $100 million annually for projects placed in service up to one month prior to rate change outside of sharing that is designed to operate in a fashion similar to the additional capacity mechanism.

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.

Waterford 3 Replacement Steam Generator Project

Following the completion of the Waterford 3 replacement steam generator project, the LPSC undertook a prudence review in connection with a filing made by Entergy Louisiana in April 2013 with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs. In July 2014 the LPSC staff filed testimony recommending potential project and replacement power cost disallowances of up to $71 million, citing a need for further explanation or documentation from Entergy Louisiana.  An intervenor filed testimony recommending disallowance of $141 million of incremental project costs, claiming the steam generator fabricator was imprudent.  Entergy Louisiana provided further documentation and explanation requested by the LPSC staff. An evidentiary hearing was held in December 2014. Entergy Louisiana believed that the replacement steam generator costs were prudently incurred and applicable legal principles supported their recovery in rates.  Nevertheless, Entergy Louisiana recorded a write-off of $16 million of Waterford 3’s plant balance in December 2014 because of the uncertainty at the time associated with the resolution of the prudence review. In December 2015 the ALJ issued a proposed recommendation, which was subsequently finalized, concluding that Entergy Louisiana prudently managed the Waterford 3 replacement steam generator project, including the selection, use, and oversight of contractors, and could not reasonably have anticipated the damage to the steam generators. Nevertheless, the ALJ concluded that Entergy Louisiana was liable for the conduct of its contractor and subcontractor and, therefore, recommended a disallowance of $67 million in capital costs. Additionally, the ALJ concluded that Entergy Louisiana did not sufficiently justify the incurrence of $2 million in replacement power costs during the replacement outage. Although the ALJ’s recommendation had not yet been considered by the LPSC, after considering the progress of the proceeding in light of the ALJ recommendation, Entergy Louisiana recorded in the fourth quarter 2015 approximately $77 million in charges, including a $45 million asset write-off and a $32 million regulatory charge, to reflect that a portion of the assets associated with the Waterford 3 replacement steam generator project was no longer probable of recovery. Entergy Louisiana maintained that the ALJ’s recommendation contained significant factual and legal errors.

In October 2016 the parties reached a settlement in this matter. The settlement was approved by the LPSC in December 2016. The settlement effectively provided for an agreed-upon disallowance of $67 million of plant, which had been previously written off by Entergy Louisiana, as discussed above. The refund to customers of approximately $71 million as a result of the settlement approved by the LPSC was made to customers in January 2017. Of the $71 million of refunds, $68 million was credited to customers through Entergy Louisiana’s formula rate plan, outside of sharing, and $3 million through its fuel adjustment clause. Entergy Louisiana had previously recorded a provision of $48 million for this refund. The previously-recorded provision included the cumulative revenues recorded through December 2016 related to the $67 million of disallowed plant. An additional regulatory charge of $23 million was recorded in fourth quarter 2016 to reflect the effects of the settlement. The settlement also provided that Entergy Louisiana could retain the value associated with potential service credits agreed to by the project contractor, to the extent they are realized in the future. Following a review by the parties, an unopposed joint report of proceedings was filed by the LPSC staff and Entergy Louisiana in May 2017 and the LPSC accepted the joint report of proceedings resolving the matter.

Union Power Station and Deactivation or Retirement Decisions for Entergy Louisiana Plants

In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC for approval of the acquisition and cost recovery of two power blocks of the Union Power Station for an expected base purchase price of approximately $237 million per power block, subject to adjustments. In September 2015, Entergy Gulf States Louisiana agreed to settlement terms with all parties for Entergy Gulf States Louisiana’s purchase of the two power blocks. In October 2015 the LPSC voted unanimously to approve the uncontested settlement which finds, among other things, that acquisition of Power Blocks 3 and 4 is in the public interest and, therefore, prudent. The business combination of Entergy Gulf States Louisiana and Entergy Louisiana received regulatory approval and closed in October 2015 making Entergy Louisiana the named purchaser of Power Blocks 3 and 4 of the Union Power Station. In March 2016, Entergy Louisiana acquired Power Blocks 3 and 4 of Union Power Station for an aggregate purchase price of approximately $475 million and implemented rates to collect the estimated first-year revenue requirement with the first billing cycle of March 2016.

As a term of the LPSC-approved settlement authorizing the purchase of Power Blocks 3 and 4 of the Union Power Station, Entergy Louisiana agreed to make a filing with the LPSC to review its decisions to deactivate Ninemile 3 and Willow Glen 2 and 4 and its decision to retire Little Gypsy 1.  In January 2016, Entergy Louisiana made its compliance filing with the LPSC. Entergy Louisiana, LPSC staff, and intervenors participated in a technical conference in March 2016 where Entergy Louisiana presented information on its deactivation/retirement decisions for these four units in addition to information on the current deactivation decisions for the ten-year planning horizon. Parties requested further proceedings on the prudence of the decision to deactivate Willow Glen 2 and 4.  No party contested the prudence of the decision to deactivate Willow Glen 2 and 4 or suggested reactivation of these units; however, issues were raised related to Entergy Louisiana’s decision to give up its transmission service rights in MISO for Willow Glen 2 and 4 rather than placing the units into suspended status for the three-year term permitted by MISO. In March 2018 the LPSC adopted the ALJ’s recommended order finding that Entergy Louisiana did not demonstrate that its decision to permanently surrender transmission rights for the mothballed (not retired) Willow Glen 2 and 4 units was reasonable and that Entergy Louisiana should hold customers harmless from increased transmission expenses should those units be reactivated. Because no party or the LPSC suggested that Willow Glen 2 and 4 should be reactivated and because the cost to return those units to service far exceeded the revenue the units were expected to generate in MISO, Entergy Louisiana retired Willow Glen 2 and 4 in March 2018. Entergy Louisiana submitted a compliance filing regarding retirement of Willow Glen 2 and 4, and the LPSC closed the proceeding.

Retail Rates - Gas

2016 Rate Stabilization Plan Filing

In January 2017, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2016. The filing of the evaluation report for test year 2016 reflected an earned return on common equity of 6.37%. In April 2017 the LPSC approved a joint report of proceedings and Entergy Louisiana submitted a revised evaluation report reflecting a $1.2 million annual increase in revenue with rates implemented with the first billing cycle of May 2017.

2017 Rate Stabilization Plan Filing

In January 2018, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2017.  The filing of the evaluation report for the test year 2017 reflected an earned return on common equity of 9.06%.  This earned return is below the earnings sharing band of the rate stabilization plan and results in a rate increase of $0.1 million.  Due to the enactment in late-December 2017 of the Tax Cuts and Jobs Act, Entergy Louisiana did not have adequate time to reflect the effects of this tax legislation in the rate stabilization plan.  In April 2018, Entergy Louisiana filed a supplemental evaluation report for the test year ended September 2017, reflecting the effects of the Tax Act, including a proposal to use the unprotected excess accumulated deferred income taxes to offset approximately $1.4 million of storm restoration deferred operation and maintenance costs incurred by Entergy Louisiana in connection with the August 2016 flooding disaster in its gas service area. The supplemental filing reflects an earned return on common equity of 10.79%. As-filed rates from the supplemental filing were implemented, subject to refund, with customers receiving a cost reduction of approximately $0.7 million effective with bills rendered on and after the first billing cycle of May 2018, as well as a $0.2 million reduction in the gas infrastructure rider effective with bills rendered on and after the first billing cycle of July 2018. The proceeding is currently in its discovery phase. A procedural schedule has not been established.

2018 Rate Stabilization Plan Filing

In January 2019, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2018. The filing of the evaluation report for the test year 2018 reflected an earned return on common equity of 2.69%. This earned return is below the earning sharing band of the gas rate stabilization plan and results in a rate increase of $2.8 million. Entergy Louisiana will make a compliance filing in April 2019 and rates will be implemented during the first billing cycle of May 2019.

Filings with the MPSC (Entergy Mississippi)

Formula Rate Plan Filings

In March 2016, Entergy Mississippi submitted its formula rate plan 2016 test year filing showing Entergy Mississippi’s projected earned return for the 2016 calendar year to be below the formula rate plan bandwidth. The filing showed a $32.6 million rate increase was necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 9.96%, within the formula rate plan bandwidth. In June 2016 the MPSC approved Entergy Mississippi’s joint stipulation with the Mississippi Public Utilities Staff. The joint stipulation provided for a total revenue increase of $23.7 million. The revenue increase included a $19.4 million increase through the formula rate plan, resulting in a return on common equity point of adjustment of 10.07%. The revenue increase also included $4.3 million in incremental ad valorem tax expenses to be collected through an updated ad valorem tax adjustment rider. The revenue increase and ad valorem tax adjustment rider were effective with the July 2016 bills.

In March 2017, Entergy Mississippi submitted its formula rate plan 2017 test year filing and 2016 look-back filing showing Entergy Mississippi’s earned return for the historical 2016 calendar year and projected earned return for the 2017 calendar year to be within the formula rate plan bandwidth, resulting in no change in rates. In June 2017, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a stipulation that confirmed that Entergy Mississippi’s earned returns for both the 2016 look-back filing and 2017 test year were within the respective formula rate plan bandwidths. In June 2017 the MPSC approved the stipulation, which resulted in no change in rates.

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.

Entergy Mississippi’s formula rate plan includes a look-back evaluation report filing in March 2019 that will compare actual 2018 results to the performance-adjusted allowed return on rate base.  In fourth quarter 2018, Entergy Mississippi recorded a provision of $9.3 million that reflects the estimate of the difference between the 2018 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 October 2018, Entergy Mississippi proposed revisions to its formula rate plan that would provide for a mechanism, the interim capacity rate adjustment mechanism, in the formula rate plan 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 additions, such as the Sunflower Solar Facility, that are approved by the MPSC.

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

As a provision of the settlement agreement approved by the City Council in May 2015 providing for the transfer from Entergy Louisiana to Entergy New Orleans of certain assets that supported the provision of service to Entergy Louisiana’s customers in Algiers, it was agreed that, with limited exceptions, no action may be taken with respect to Entergy New Orleans’s base rates until rates are implemented from a base rate case that must be filed for its electric and gas operations in 2018. This provision eliminated the formula rate plan applicable to Algiers operations. The limited exceptions included continued implementation of the then-remaining two years of the four-year phased-in rate increase for the Algiers area and certain exceptional cost increases or decreases in the base revenue requirement. An additional provision of the settlement agreement allowed for continued recovery of the revenue requirement associated with the capacity and energy from Ninemile 6 received by Entergy New Orleans under a power purchase agreement with Entergy Louisiana (Algiers PPA). The settlement authorized Entergy New Orleans to recover the remaining revenue requirement related to the Algiers PPA through base rates charged to Algiers customers. The settlement also provided for continued implementation of the Algiers MISO recovery rider.

In addition to the Algiers PPA, Entergy New Orleans has a separate power purchase agreement with Entergy Louisiana for 20% of the capacity and energy from Ninemile 6 (Ninemile PPA), which commenced operation in December 2014. Initially, recovery of the non-fuel costs associated with the Ninemile PPA was authorized through a special Ninemile 6 rider billed only to Entergy New Orleans customers outside of Algiers.

In August 2015, Entergy New Orleans filed an application with the City Council seeking authorization to proceed with the purchase of Union Power Block 1, with an expected base purchase price of approximately $237 million, subject to adjustments, and seeking approval of the recovery of the associated costs. In November 2015 the City Council issued written resolutions and an order approving an agreement in principle between Entergy New Orleans and City Council advisors providing that the purchase of Union Power Block 1 and related assets by Entergy New Orleans is prudent and in the public interest. The City Council authorized expansion of the terms of the purchased power and capacity acquisition cost recovery rider to recover the non-fuel purchased power expense from Ninemile 6, the revenue requirement associated with the purchase of Power Block 1 of the Union Power Station, and a credit to customers of $400 thousand monthly beginning June 2016 in recognition of the decrease in other operation and maintenance expenses that would result with the deactivation of Michoud Units 2 and 3. In March 2016, Entergy New Orleans purchased Power Block 1 of the Union Power Station for approximately $237 million and initiated recovery of these costs with March 2016 bills. In July 2016, Entergy New Orleans and the City Council Utility Committee agreed to a temporary increase in the Michoud credit to customers to a total of $1.4 million monthly for August 2016 through December 2016.

A 2008 rate case settlement included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs.  The rate settlement provided an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provided a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs. In January 2015 the City Council approved funding for the Energy Smart program from April 2015 through March 2017 using the remainder of the approximately $12.8 million of 2014 rough production cost equalization funds, with any remaining costs being recovered through the fuel adjustment clause. This funding methodology was modified in November 2015 when the City Council directed Entergy New Orleans to use a combination of guaranteed customer savings related to a prior agreement with the City Council and rough production cost equalization funds to cover program costs prior to recovering any costs through the fuel adjustment clause. In April 2017 the City Council approved an implementation plan for the Energy Smart program from April 2017 through December 2019. The City Council directed that the $11.8 million balance reported for Energy Smart funds be used to continue funding the program for Entergy New Orleans’s legacy customers and that the Energy Smart Algiers program continue to be funded through the Algiers fuel adjustment clause, until additional customer funding is required for the legacy customers. In September 2017, Entergy New Orleans filed a supplemental plan and proposed several options for an interim cost recovery mechanism necessary to recover program costs during the period between when existing funds directed to Energy Smart programs are depleted and when new rates from the 2018 combined rate case, which includes a cost recovery mechanism for Energy Smart funding, take effect (estimated to be August 2019). In December 2017 the City Council approved an energy efficiency cost recovery rider as an interim funding mechanism for Energy Smart, subject to verification that no additional funding sources exist. In June 2018 the City Council also approved a resolution recommending that Entergy New Orleans allocate approximately $13.5 million of benefits resulting from the Tax Act to Energy Smart. Entergy New Orleans is seeking approval of a permanent and stable source of funding for Energy Smart as part of its base rate case filed in September 2018.

In September 2018, Entergy New Orleans filed an electric and gas base rate case with the City Council. The filing requests 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 requests 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 includes a proposed gas rate decrease of $142 thousand. Entergy New Orleans’s rates reflect 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 ending 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’s request for a change in rates is based on the projected twelve months ending December 31, 2018.

The filing’s major provisions include: (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 have recommended, among other things, overall rate reductions of approximately $33 million in electric rates and $3.8 million in gas rates. Certain intervenors have recommended overall rate reductions of up to approximately $49 million in electric rates and $5 million in gas rates. The procedural schedule calls for an evidentiary hearing to be held in June 2019.

Internal Restructuring

In July 2016, Entergy New Orleans filed an application with the City Council seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy New Orleans, Inc. to a new entity, which would ultimately be owned by an existing Entergy subsidiary holding company. In May 2017 the City Council adopted a resolution approving the proposed internal restructuring pursuant to an agreement in principle with the City Council advisors and certain intervenors. Pursuant to the agreement in principle, Entergy New Orleans would credit retail customers $10 million in 2017, $1.4 million in the first quarter of the year after the transaction closes, and $117,500 each month in the second year after the transaction closes until such time as new base rates go into effect as a result of the then-anticipated 2018 base rate case (which has subsequently been filed). Entergy New Orleans began crediting retail customers in June 2017. In June 2017 the FERC approved the transaction and, pursuant to the agreement in principle, Entergy New Orleans will provide additional credits to retail customers of $5 million in each of the years 2018, 2019, and 2020.

In November 2017, Entergy New Orleans undertook a multi-step restructuring, including the following:

• Entergy New Orleans, Inc. redeemed its outstanding preferred stock at a price of approximately $21 million, which included a call premium of approximately $819,000, plus any accumulated and unpaid dividends.

• Entergy New Orleans, Inc. converted from a Louisiana corporation to a Texas corporation.

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

• Entergy New Orleans, Inc. contributed the membership interests in Entergy New Orleans 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 New Orleans Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.

In December 2017, Entergy New Orleans, Inc. changed its name to Entergy Utility Group, Inc., and Entergy New Orleans Power then changed its name to Entergy New Orleans, LLC. Entergy New Orleans, LLC holds substantially all of the assets, and has assumed substantially all of the liabilities, of Entergy New Orleans, Inc. The restructuring was accounted for as a transaction between entities under common control.

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 electricity 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), 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 June 2017, Entergy Texas filed an application to amend its DCRF rider by increasing the total collection from $8.65 million to approximately $19 million. In July 2017, Entergy Texas, the PUCT staff, and the two other parties in the proceeding entered into an unopposed stipulation and settlement agreement resulting in an amended DCRF annual revenue requirement of $18.3 million. In September 2017 the PUCT issued its final order approving the unopposed stipulation and settlement agreement. The amended DCRF rider rates became effective for usage on and after September 1, 2017. DCRF rates were set to zero upon implementation of new base rates on October 17, 2018, as described above in the discussion of the 2018 base rate case.

Transmission Cost Recovery Factor (TCRF) Rider

In September 2015, Entergy Texas filed for a TCRF rider requesting a $13 million increase, incremental to base rates. Testimony was filed in November 2015, with the PUCT staff and other parties proposing various disallowances involving, among other things, MISO charges, vegetation management costs, and bad debt expenses that would reduce the requested increase by approximately $2 million. In addition to those recommended disallowances, a number of parties recommended that Entergy Texas’s request be reduced by an additional $3.4 million to account for load growth since base rates were last set. In February 2016 a State Office of Administrative Hearings ALJ issued a proposal for decision recommending that the PUCT disallow approximately $2 million from Entergy Texas’s $13 million request, but recommending that the PUCT not accept the load growth offset. In June 2016 the PUCT indicated that it would take up in a future rulemaking project the issue of whether a load growth adjustment should apply to a TCRF. In July 2016 the PUCT issued an order generally accepting the proposal for decision but declining to adjust the TCRF baseline in two instances as recommended by the ALJ, which resulted in a total annual allowance of approximately $10.5 million. The PUCT also ordered its staff and Entergy Texas to track all spare autotransformer transfers going forward so that it could address the appropriate accounting treatment and prudence of such transfers in Entergy Texas’s next base rate case. Entergy Texas implemented the TCRF rider beginning with September 2016 bills.

In September 2016, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The proposed amended TCRF rider was designed to collect approximately $29.5 million annually from Entergy Texas’s retail customers. This amount included the approximately $10.5 million annually that Entergy Texas was previously authorized to collect through the TCRF rider, as discussed above. In December 2016, concurrent with the 2016 fuel reconciliation stipulation and settlement agreement discussed above, Entergy Texas and the PUCT staff reached a settlement agreeing to the amended TCRF annual revenue requirement of $29.5 million. As discussed above, the terms of the two settlements are interdependent. The PUCT approved the settlement and issued a final order in March 2017. Entergy Texas implemented the amended TCRF rider beginning with bills covering usage on and after March 20, 2017. TCRF rates were set to zero upon implementation of new base rates on October 17, 2018, as described above in the 2018 base rate case discussion.

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. The proceeding is currently ongoing at the PUCT.

Advanced Metering Infrastructure (AMI) Filings

Entergy Arkansas

In September 2016, Entergy Arkansas filed an application seeking a finding from the APSC that Entergy Arkansas’s deployment of AMI is in the public interest. Entergy Arkansas proposed to replace existing meters with advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Arkansas’s modernized power grid. The filing included an estimate of implementation costs for AMI of $208 million. The filing identified a number of quantified and unquantified benefits, and Entergy Arkansas provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal net benefit to customers of $406 million. Entergy Arkansas also sought to continue to include in rate base the remaining book value of existing meters, which was approximately $57 million at December 31, 2015, that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Arkansas proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Deployment of the communications network began in 2018. Entergy Arkansas proposed to include the AMI deployment costs and the quantified benefits in future formula rate plan filings, and the 2018 costs were approved in the 2017 formula rate plan filing. In August 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement. In October 2017 the APSC issued an order finding that Entergy Arkansas’s AMI deployment is in the public interest and approving the settlement agreement subject to a minor modification. Entergy Arkansas expects to recover the undepreciated balance of its existing meters through a regulatory asset to be amortized over 15 years.

Entergy Louisiana

In November 2016, Entergy Louisiana filed an application seeking a finding from the LPSC that Entergy Louisiana’s deployment of advanced electric and gas metering infrastructure is in the public interest. Entergy Louisiana proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Louisiana’s modernized power grid. The filing included an estimate of implementation costs for AMI of $330 million. The filing identified a number of quantified and unquantified benefits, and Entergy Louisiana provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $607 million. Entergy Louisiana also sought to continue to include in rate base the remaining book value, approximately $92 million at December 31, 2015, of the existing electric meters and also to depreciate those assets using current depreciation rates. Entergy Louisiana proposed a 15-year useful life for the new advanced meters, the three-year deployment of which began in 2019. Deployment of the communications network began in 2018. Entergy Louisiana proposed to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022. The parties reached an uncontested stipulation permitting implementation of Entergy Louisiana’s proposed AMI system, with modifications to the proposed customer charge. In July 2017 the LPSC approved the stipulation. Entergy Louisiana expects to recover the undepreciated balance of its existing meters through a regulatory asset to be amortized at current depreciation rates.

Entergy Mississippi

In November 2016, Entergy Mississippi filed an application seeking an order from the MPSC granting a certificate of public convenience and necessity and finding that Entergy Mississippi’s deployment of AMI is in the public interest. Entergy Mississippi proposed to replace existing meters with advanced meters that enable two-way data communication; to design and build a secure and reliable network to support such communications; and to implement support systems. AMI is intended to serve as the foundation of Entergy Mississippi’s modernized power grid. The filing included an estimate of implementation costs for AMI of $132 million. The filing identified a number of quantified and unquantified benefits, and Entergy Mississippi provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal benefit to customers of $496 million over a 15-year period, which when netted against the costs of AMI results in $183 million of net customer benefits. Entergy Mississippi also sought to continue to include in rate base the remaining book value, approximately $56 million at December 31, 2015, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Mississippi proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019, subject to approval by the MPSC. Deployment of the communications network began in 2018. Entergy Mississippi proposed to include the AMI deployment costs and the quantified benefits in existing rate mechanisms, primarily through future formula rate plan filings and/or future energy cost recovery rider schedule re-determinations, as applicable. In May 2017 the Mississippi Public Utilities Staff and Entergy Mississippi entered into and filed a joint stipulation supporting Entergy Mississippi’s filing, and the MPSC issued an order approving the filing without material changes, finding that Entergy Mississippi’s deployment of AMI is in the public interest and granting a certificate of public convenience and necessity. The MPSC order also confirmed that Entergy Mississippi shall continue to include in rate base the remaining book value of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. In June 2018, as part of the order approving the joint stipulation between the Mississippi Public Utilities Staff and Entergy Mississippi addressing Entergy Mississippi’s 2018 formula rate plan evaluation report and the ratemaking effects of the Tax Act, the MPSC approved the acceleration of the recovery of substantially all of Entergy Mississippi’s existing customer meters in anticipation of AMI deployment.

Entergy New Orleans

In October 2016, Entergy New Orleans filed an application seeking a finding from the City Council that Entergy New Orleans’s deployment of advanced electric and gas metering infrastructure is in the public interest.  Entergy New Orleans proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems.  AMI is intended to serve as the foundation of Entergy New Orleans’s modernized power grid.  The filing included an estimate of implementation costs for AMI of $75 million. The filing identified a number of quantified and unquantified benefits, and Entergy New Orleans provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $101 million.  Entergy New Orleans also sought to continue to include in rate base the remaining book value, approximately $21 million at December 31, 2015, of the existing electric meters and also to depreciate those assets using current depreciation rates.  Entergy New Orleans proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which began in 2019.  Deployment of the information technology infrastructure began in 2017 and deployment of the communications network began in 2018.  Entergy New Orleans proposed to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022.  The City Council’s advisors filed testimony in May 2017 recommending the adoption of AMI subject to certain modifications, including the denial of Entergy New Orleans’s proposed customer charge as a cost recovery mechanism. In January 2018 a settlement was reached between the City Council’s advisors and Entergy New Orleans. In February 2018 the City Council approved the settlement, which deferred cost recovery to the 2018 Entergy New Orleans rate case, but also stated that an adjustment for 2018-2019 AMI costs can be filed in the rate case and that, for all subsequent AMI costs, the mechanism to be approved in the 2018 rate case will allow for the timely recovery of such costs. In April 2018 the City Council adopted a resolution directing Entergy New Orleans to explore the options for accelerating the deployment of AMI. In June 2018 the City Council approved a one-year acceleration of AMI in its service area for an incremental $4.4 million.

Entergy Texas

In April 2017 the Texas legislature enacted legislation that extends statutory support for AMI deployment to Entergy Texas and directs that if Entergy Texas elects to deploy AMI, it shall do so as rapidly as practicable. In July 2017, Entergy Texas filed an application seeking an order from the PUCT approving Entergy Texas’s deployment of AMI. Entergy Texas proposed to replace existing meters with advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Texas’s modernized power grid. The filing included an estimate of implementation costs for AMI of $132 million. The filing identified a number of quantified and unquantified benefits, with Entergy Texas showing that its AMI deployment is expected to produce nominal net operational cost savings to customers of $33 million. Entergy Texas also sought to continue to include in rate base the remaining book value, approximately $41 million at December 31, 2016, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Texas proposed a seven-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Entergy Texas also proposed a surcharge tariff to recover the reasonable and necessary costs it has and will incur under the deployment plan for the full deployment of advanced meters. Further, Entergy Texas sought approval of fees that would be charged to customers who choose to opt out of receiving service through an advanced meter and instead receive electric service with a non-standard meter. In October 2017, Entergy Texas and other parties entered into and filed an unopposed stipulation and settlement agreement, permitting deployment of AMI with limited modifications. The PUCT approved the stipulation and settlement agreement in December 2017. Entergy Texas implemented the AMI surcharge tariff beginning with January 2018 bills. As of December 31, 2018, Entergy Texas has a regulatory liability related to the collection of the surcharge from customers. Consistent with the approval, deployment of the communications network began in 2018 and deployment of the advanced meters will begin in March 2019. Entergy Texas expects to recover the remaining net book value of its existing meters through a regulatory asset to be amortized at current depreciation rates.

System Agreement Cost Equalization Proceedings

Prior to its final termination in 2016, the Utility operating companies historically engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement.  Entergy Arkansas terminated its participation in the System Agreement in December 2013. Entergy Mississippi terminated its participation in the System Agreement in November 2015. The System Agreement terminated with respect to its remaining participants in August 2016.

Although the System Agreement has terminated, certain of the Utility operating companies’ retail regulators continue to pursue litigation involving the System Agreement at the FERC and in federal courts.  The proceedings include challenges to the allocation of costs as defined by the System Agreement and other matters.

In June 2005 the FERC issued a decision in System Agreement litigation that had been commenced by the LPSC, and essentially affirmed its decision in a December 2005 order on rehearing.  The decision included, among other things:

• The FERC’s conclusion that the System Agreement no longer roughly equalized total production costs among the Utility operating companies.

• In order to reach rough production cost equalization, the FERC imposed a bandwidth remedy by which each company’s total annual production costs would have to be within +/- 11% of Entergy System average total annual production costs.

• In calculating the production costs for this purpose under the FERC’s order, output from the Vidalia hydroelectric power plant would not reflect the actual Vidalia price for the year but be priced at that year’s average price paid by Entergy Louisiana for the exchange of electric energy under Service Schedule MSS-3 of the System Agreement, thereby reducing the amount of Vidalia costs reflected in the comparison of the Utility operating companies’ total production costs.

• The remedy ordered by the FERC in 2005 required no refunds and became effective based on calendar year 2006 production costs with the first reallocation payments made in 2007.

The FERC’s decision reallocated total production costs of the Utility operating companies whose relative total production costs expressed as a percentage of Entergy System average production costs are outside an upper or lower bandwidth.  This was accomplished by payments from Utility operating companies whose production costs were more than 11% below Entergy System average production costs to Utility operating companies whose production costs were more than the Entergy System average production cost, with payments going first to those Utility operating companies whose total production costs were farthest above the Entergy System average.

The LPSC, APSC, MPSC, and the Arkansas Electric Energy Consumers appealed the FERC’s December 2005 decision to the United States Court of Appeals for the D.C. Circuit.  Entergy and the City of New Orleans intervened in the various appeals.  The D.C. Circuit issued its decision in April 2008.  The D.C. Circuit concluded that the FERC’s orders had failed to adequately explain both its conclusion that it was prohibited from ordering refunds for the 20-month period from September 13, 2001 - May 2, 2003 and its determination to implement the bandwidth remedy commencing on January 1, 2006, rather than June 1, 2005.  The D.C. Circuit remanded the case to the FERC for further proceedings on those two issues.

In October 2011 the FERC issued an order addressing the D.C. Circuit remand on the two issues.  On the first issue, the FERC concluded that it did have the authority to order refunds, but decided that it would exercise its equitable discretion and not require refunds for the 20-month period from September 13, 2001 - May 2, 2003.  Because the ruling on refunds relied on findings in the interruptible load proceeding, which is discussed in a separate section below, the FERC concluded that this refund ruling will be held in abeyance pending the outcome of the rehearing requests in the interruptible load proceeding.  On the second issue, the FERC reversed its prior decision and ordered that the prospective bandwidth remedy begin on June 1, 2005 (the date of its initial order in the proceeding) rather than January 1, 2006, as it had previously ordered.  Pursuant to the October 2011 order, Entergy was required to calculate bandwidth payments for the period June - December 2005 utilizing the bandwidth formula tariff prescribed by the FERC that was filed in a December 2006 compliance filing and accepted by the FERC in an April 2007 order.  

In March 2015, in light of a December 2014 decision by the D.C. Circuit in the interruptible load proceeding, Entergy filed with the FERC a motion to establish a briefing schedule on refund issues and an initial brief addressing refund issues. The initial brief argued that the FERC, in response to the D.C. Circuit decision, should clarify its policy on refunds and find that refunds are not required in this proceeding. In October 2015 the FERC issued three orders related to the commencement of the remedy on June 1, 2005 and the inclusion of interest for the period June 1, 2005 through December 31, 2005. Specifically, the FERC rejected Entergy’s request for rehearing of its decision to include interest for the seven-month period. The FERC also rejected Entergy’s request for rehearing of the order rejecting the compliance filing with regard to the issue of interest. Finally, the FERC set for hearing and settlement procedures the 2014 compliance filing that included the bandwidth calculation for the seven months June 1, 2005 through December 31, 2005. In setting the compliance filing for hearing, the FERC rejected the APSC’s protest that Entergy Arkansas should not be subject to the filing because Entergy Arkansas would be making the payments during a period following its exit from the System Agreement. In January 2018 the D.C. Circuit affirmed the FERC decision that Entergy Arkansas was subject to the filing.

In December 2011, Entergy filed with the FERC its compliance filing that provided the payments and receipts among the Utility operating companies pursuant to the FERC’s October 2011 order.  The APSC, the LPSC, the PUCT, and other parties intervened in the December 2011 compliance filing proceeding, and the APSC and the LPSC also filed protests. The filing showed the following payments/receipts among the Utility operating companies:

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$156
Entergy Louisiana	($75)
Entergy Mississippi	($33)
Entergy New Orleans	($5)
Entergy Texas	($43)

Entergy Arkansas made its payment in January 2012.  In February 2012, Entergy Arkansas filed for an interim adjustment to its production cost allocation rider requesting that the $156 million be collected from customers over the 22-month period from March 2012 through December 2013.  In March 2012 the APSC issued an order stating that the payment can be recovered from retail customers through the production cost allocation rider, subject to refund.  The LPSC and the APSC requested rehearing of the FERC’s October 2011 order.  

In February 2014 the FERC issued a rehearing order addressing its October 2011 order. The FERC denied the LPSC’s request for rehearing on the issues of whether the bandwidth remedy should be made effective earlier than June 1, 2005, and whether refunds should be ordered for the 20-month refund effective period. The FERC granted the LPSC’s rehearing request on the issue of interest on the bandwidth payments/receipts for the June - December 2005 period, requiring that interest be accrued from June 1, 2006 until the date those bandwidth payments/receipts are made. Also in February 2014 the FERC issued an order rejecting the December 2011 compliance filing that calculated the bandwidth payments/receipts for the June - December 2005 period. The FERC order required a new compliance filing that calculates the bandwidth payments/receipts for the June - December 2005 period based on monthly data for the seven individual months including interest pursuant to the February 2014 rehearing order. Entergy sought rehearing of the February 2014 order with respect to the FERC’s determinations regarding interest. In April 2014 the LPSC filed a petition for review of the FERC’s October 2011 and February 2014 orders with the U.S. Court of Appeals for the D.C. Circuit. In August 2017 the D.C. Circuit issued a decision denying the LPSC’s appeal of the FERC’s October 2011 and February 2014 orders. On the issue of the FERC’s implementation of the prospective remedy as of June 2005 and whether the bandwidth remedy should be extended for an additional 17 months in years 2004-2005, the D.C. Circuit affirmed the FERC’s implementation of the remedy and denied the LPSC’s appeal. On the issue of whether the operating companies should be required to issue refunds for the 20-month period from September 2001 to May 2003, the D.C. Circuit granted the FERC’s request for agency reconsideration and remanded that issue back to the FERC for further proceedings as requested by all parties to the appeal. In response to the D.C. Circuit’s remand, various parties filed briefs with the FERC addressing whether the FERC should require the Utility operating companies to issue refunds for the 20-month refund period from September 2001 to May 2003. The LPSC has argued in favor of such remands and Entergy has opposed the LPSC’s request. The briefing was completed in September 2018 and the matter is pending before the FERC.

In April and May 2014, Entergy filed with the FERC an updated compliance filing that provided the payments and receipts among the Utility operating companies pursuant to the FERC’s February 2014 orders.  The filing showed the following net payments and receipts, including interest, among the Utility operating companies:

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$68
Entergy Louisiana	($10)
Entergy Mississippi	($11)
Entergy New Orleans	$2
Entergy Texas	($49)

These payments were made in May 2014. The LPSC, City Council, and APSC filed protests.

The hearing on the bandwidth calculation for the seven months June 1, 2005 through December 31, 2005 occurred in July 2016. The presiding judge issued an initial decision in November 2016. In the initial decision, the presiding judge agreed with the Utility operating companies’ position that: (1) interest on the bandwidth payments for the 2005 test period should be accrued from June 1, 2006 until the date that the bandwidth payments for that calculation are paid, which is consistent with how the Utility operating companies performed the calculation; and (2) a portion of Entergy Louisiana’s 2001-vintage Louisiana state net operating loss accumulated deferred income tax that results from the Vidalia tax deduction should be excluded from the 2005 test period bandwidth calculation. Various participants filed briefs on exceptions and/or briefs opposing exceptions related to the initial decision, including the LPSC, the APSC, the FERC trial staff, and Entergy Services. In May 2018 the FERC issued an order affirming the initial decision and ordered a comprehensive recalculation of the bandwidth payments/receipts for the seven months June 1, 2005 through December 31, 2005 and a recalculation of the 2006 and 2007 test years as a result of limited revisions. Entergy filed the comprehensive recalculation of the bandwidth payments/receipts for the seven months June 1, 2005 through December 31, 2005 and the 2006 and 2007 test years in July 2018. The filing shows the additional following payments and receipts among the Utility operating companies:

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	($4)
Entergy Louisiana	($23)
Entergy Mississippi	$16
Entergy New Orleans	$5
Entergy Texas	$6

These payments were made in July 2018. In January 2019 the FERC denied the LPSC’s request for rehearing of the May 2018 order.

Rough Production Cost Equalization Rates

Each May from 2007 through 2016 Entergy filed with the FERC the rates to implement the FERC’s orders in the System Agreement proceeding.  These filings showed the following payments/receipts among the Utility operating companies were necessary to achieve rough production cost equalization as defined by the FERC’s orders:

	Payments (Receipts)
	2007			2008			2009			2010			2011			2012			2013			2014
	(In Millions)
Entergy Arkansas		$252			$252			$390			$41			$77			$41			$—			$—
Entergy Louisiana		($211	)		($160	)		($247	)		($22	)		($12	)		($41	)		$—			$—
Entergy Mississippi		($41	)		($20	)		($24	)		($19	)		($40	)		$—			$—			$—
Entergy New Orleans		$—			($7	)		$—			$—			($25	)		$—			($15	)		($15	)
Entergy Texas		($30	)		($65	)		($119	)		$—			$—			$—			$15			$15

The Utility operating companies recorded accounts payable or accounts receivable to reflect the rough production cost equalization payments and receipts required to implement the FERC’s remedy.  When accounts payable were recorded, a corresponding regulatory asset was recorded for the right to collect the payments from customers. When accounts receivable were recorded, a corresponding regulatory liability was recorded for the obligations to pass the receipts on to customers.  No payments were required in 2016 or 2015 to implement the FERC’s remedy based on calendar year 2015 production costs and 2014 production costs, respectively. The System Agreement terminated in August 2016.

The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas.  Entergy Texas recovered its 2013 rough production cost equalization payment over three years beginning April 2014. Entergy Texas included its 2014 rough production cost equalization payment as a component of an interim fuel refund made in 2014. Management believes that any changes in the allocation of production costs resulting from the FERC’s decision and related retail proceedings should result in similar rate changes for retail customers, subject to specific circumstances that have caused trapped costs.

The following rough production cost equalization rate proceedings are still ongoing or were ongoing during the period 2016-2018.

2010 Rate Filing Based on Calendar Year 2009 Production Costs

In May 2010, Entergy filed with the FERC the 2010 rates in accordance with the FERC’s orders in the System Agreement proceeding, and supplemented the filing in September 2010.  Several parties intervened in the proceeding at the FERC, including the LPSC and the City Council, which also filed protests.  In July 2010 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2010, subject to refund.  After an abeyance of the proceeding schedule, a hearing was held in March 2014 and in December 2015 the FERC issued an order. Among other things, the December 2015 order directed Entergy to submit a compliance filing. In January 2016 the LPSC, the APSC, and Entergy filed requests for rehearing of the FERC’s December 2015 order. In February 2016, Entergy submitted the compliance filing ordered in the December 2015 order.  The result of the true-up payments and receipts for the recalculation of production costs resulted in the following payments/receipts among the Utility operating companies:

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$2
Entergy Louisiana	$6
Entergy Mississippi	($4)
Entergy New Orleans	($1)
Entergy Texas	($3)

In September 2016 the FERC accepted the February 2016 compliance filing subject to a further compliance filing made in November 2016. The further compliance filing was required as a result of an order issued in September 2016 ruling on the January 2016 rehearing requests filed by the LPSC, the APSC, and Entergy. In the order addressing the rehearing requests, the FERC granted the LPSC’s rehearing request and directed that interest be calculated on the payment/receipt amounts. The FERC also granted the APSC’s and Entergy’s rehearing request and ordered the removal of both securitized asset accumulated deferred income taxes and contra-securitization accumulated deferred income taxes from the calculation. In November 2016, Entergy submitted its compliance filing in response to the FERC’s order on rehearing. The compliance filing included a revised calculation of the bandwidth true-up payments and receipts based on 2009 test year data and interest calculations. The LPSC protested the interest calculations. In November 2017 the FERC issued an order rejecting the November 2016 compliance filing. The FERC determined that the payments detailed in the November 2016 compliance filing did not include adequate interest for the payments from Entergy Arkansas to Entergy Louisiana because it did not include interest on the principal portion of the payment that was made in February 2016. In December 2017, Entergy recalculated the interest pursuant to the November 2017 order. As a result of the recalculations, Entergy Arkansas owed very minor payments to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.

2011 Rate Filing Based on Calendar Year 2010 Production Costs

In May 2011, Entergy filed with the FERC the 2011 rates in accordance with the FERC’s orders in the System Agreement proceeding.  Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest.  In July 2011 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2011, subject to refund. After an abeyance of the proceeding schedule, in December 2014 the FERC consolidated the 2011 rate filing with the 2012, 2013, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

2012 Rate Filing Based on Calendar Year 2011 Production Costs

In May 2012, Entergy filed with the FERC the 2012 rates in accordance with the FERC’s orders in the System Agreement proceeding.  Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest.  In August 2012 the FERC accepted Entergy’s proposed rates for filing, effective June 2012, subject to refund. After an abeyance of the proceeding schedule, in December 2014 the FERC consolidated the 2012 rate filing with the 2011, 2013, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

2013 Rate Filing Based on Calendar Year 2012 Production Costs

In May 2013, Entergy filed with the FERC the 2013 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest. The City Council intervened and filed comments related to including the outcome of a related FERC proceeding in the 2013 cost equalization calculation. In August 2013 the FERC issued an order accepting the 2013 rates, effective June 1, 2013, subject to refund. After an abeyance of the proceeding schedule, in December 2014 the FERC consolidated the 2013 rate filing with the 2011, 2012, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

2014 Rate Filing Based on Calendar Year 2013 Production Costs

In May 2014, Entergy filed with the FERC the 2014 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest. The City Council intervened and filed comments. In December 2014 the FERC issued an order accepting the 2014 rates, effective June 1, 2014, subject to refund, set the proceeding for hearing procedures, and consolidated the 2014 rate filing with the 2011, 2012, and 2013 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

Consolidated 2011, 2012, 2013, and 2014 Rate Filing Proceedings

As discussed above, in December 2014 the FERC consolidated the 2011, 2012, 2013, and 2014 rate filings for settlement and hearing procedures. In May 2015, Entergy filed direct testimony in the consolidated rate filings and the LPSC filed direct testimony concerning its complaint proceeding that is consolidated with the rate filings, challenging certain components of the pending bandwidth calculations for prior years. Hearings occurred in November 2015, and the ALJ issued an initial decision in July 2016. In the initial decision, the ALJ generally agreed with Entergy’s bandwidth calculations with one exception on the accounting related to the Waterford 3 sale/leaseback. In March 2018 the FERC issued an order affirming the initial decision. In April 2018 the LPSC requested rehearing of the FERC’s March 2018 order affirming the ALJ’s initial decision. Entergy filed in May 2018 the bandwidth true-up payments and receipts for the 2011-2014 rate filings (table does not net to zero due to rounding):

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$3
Entergy Louisiana	$3
Entergy Mississippi	($1)
Entergy New Orleans	$1
Entergy Texas	($5)

These payments were made in May 2018. The LPSC request for rehearing is pending.

Utility Operating Company Termination of System Agreement Participation

Entergy Arkansas and Entergy Mississippi ceased participating in the System Agreement effective December 18, 2013 and November 7, 2015, respectively. Entergy Louisiana, Entergy New Orleans, and Entergy Texas terminated participation in the System Agreement on August 31, 2016, which resulted in the termination of the System Agreement in its entirety pursuant to a settlement agreement approved by the FERC in December 2015.

In December 2013 the FERC set one issue for hearing involving whether and how the benefits associated with settlement with Union Pacific regarding certain coal delivery issues should be allocated among Entergy Arkansas and the other Utility operating companies post-termination of the System Agreement. In December 2014 a FERC ALJ issued an initial decision finding that Entergy Arkansas would realize benefits after December 18, 2013 from the 2008 settlement agreement between Entergy Services, Entergy Arkansas, and Union Pacific, related to certain coal delivery issues. In March 2016 the FERC issued an opinion affirming the December 2014 initial decision with regard to the determination that there were benefits related to the Union Pacific settlement, which were realized post-Entergy Arkansas’s December 2013 withdrawal from the System Agreement, that should be shared with the other Utility operating companies utilizing the methodology proposed by the MPSC and trued-up to actual coal volumes purchased. In May 2016, Entergy made a compliance filing that provided the calculation of Union Pacific settlement benefits utilizing the methodology adopted by the initial decision, trued-up for the actual volumes of coal purchased. The payments were made in May 2016. In August 2016 the FERC issued an order accepting Entergy’s compliance filing. Also in August 2016 the APSC filed a petition for review of the FERC’s March 2016 and August 2016 orders with the U.S. Court of Appeals for the D.C. Circuit. In June 2018 the D.C. Circuit denied the APSC’s petition.

Interruptible Load Proceeding

In April 2007 the U.S. Court of Appeals for the D.C. Circuit issued its opinion in the LPSC’s appeal of the FERC’s March 2004 and April 2005 orders related to the treatment under the System Agreement of the Utility operating companies’ interruptible loads.  In its opinion the D.C. Circuit concluded that the FERC: (1) acted arbitrarily and capriciously by allowing the Utility operating companies to phase-in the effects of the elimination of the interruptible load over a 12-month period of time; (2) failed to adequately explain why refunds could not be ordered under Section 206(c) of the Federal Power Act; and (3) exercised appropriately its discretion to defer addressing the cost of sulfur dioxide allowances until a later time.  The D.C. Circuit remanded the matter to the FERC for a more considered determination on the issue of refunds.  The FERC issued its order on remand in September 2007, in which it directed Entergy to make a compliance filing removing all interruptible load from the computation of peak load responsibility commencing April 1, 2004 and to issue any necessary refunds to reflect this change.  In addition, the order directed the Utility operating companies to make refunds for the period May 1995 through July 1996.  In November 2007 the Utility operating companies filed a refund report describing the refunds to be issued pursuant to the FERC’s orders.  The LPSC filed a protest to the refund report in December 2007.  The refunds were made in October 2008 by the Utility operating companies that owed refunds to the Utility operating companies that were due refunds under the decision.  The APSC and the Utility operating companies appealed the FERC decisions to the D.C. Circuit.

Following the filing of petitioners’ initial briefs, the FERC filed a motion requesting the D.C. Circuit hold the appeal of the FERC’s decisions ordering refunds in the interruptible load proceeding in abeyance and remand the record to the FERC.  The D.C. Circuit granted the FERC’s unopposed motion in June 2009.  In December 2009 the FERC established a paper hearing to determine whether the FERC had the authority and, if so, whether it would be appropriate to order refunds resulting from changes in the treatment of interruptible load in the allocation of capacity costs by the Utility operating companies.  In August 2010 the FERC issued an order stating that it has the authority and refunds are appropriate.  The APSC, the MPSC, and Entergy requested rehearing of the FERC’s decision.  In June 2011 the FERC issued an order granting rehearing in part and denying rehearing in part, in which the FERC determined to invoke its discretion to deny refunds.  The FERC held that in this case where “the Entergy system as a whole collected the proper level of revenue, but, as was later established, incorrectly allocated peak load responsibility among the various Entergy operating companies….the Commission will apply here our usual practice in such cases, invoking our equitable discretion to not order refunds, notwithstanding our authority to do so.”  The LPSC requested rehearing of the FERC’s June 2011 decision.  In July 2011 the refunds made in the fourth quarter 2008 described above were reversed. In October 2011 the FERC issued an “Order Establishing Paper Hearing” inviting parties that oppose refunds to file briefs within 30 days addressing the LPSC’s argument that FERC precedent supports refunds under the circumstances present in this proceeding.  Parties that favor refunds were then invited to file reply briefs within 21 days of the date that the initial briefs were due.  

In March 2013 the FERC issued an order denying the LPSC’s request for rehearing of the FERC’s June 2011 order wherein the FERC concluded it would exercise its discretion and not order refunds in the interruptible load proceeding. Based on its review of the LPSC’s request for rehearing and the briefs filed as part of the paper hearing established in October 2011, the FERC affirmed its earlier ruling and declined to order refunds under the circumstances of the case. In May 2013 the LPSC filed a petition for review with the U.S. Court of Appeals for the D.C. Circuit seeking review of FERC orders in the interruptible load proceeding that concluded that the FERC would exercise its discretion and not order refunds in the proceeding. Oral argument was held on the appeal in the D.C. Circuit in September 2014. In December 2014 the D.C. Circuit issued an order on the LPSC’s appeal and remanded the case back to the FERC. The D.C. Circuit rejected the LPSC’s argument that there is a presumption in favor of refunds, but it held that the FERC had not adequately explained its decision to deny refunds and directed the FERC “to consider the relevant factors and weigh them against one another.” In March 2015, Entergy filed with the FERC an initial brief on remand to address the December 2014 decision by the D.C. Circuit. The initial brief on remand argued that the FERC, in response to the D.C. Circuit decision, should clarify its policy on refunds and find that refunds are not required in the interruptible load proceeding.

In April 2016 the FERC issued an order on remand that addressed the December 2014 decision by the D.C. Circuit in the interruptible load proceeding. The order on remand affirmed the FERC’s denial of refunds for the 15-month refund effective period. The FERC explained and clarified its policies regarding refunds and concluded that the evidence in the record demonstrated that the relevant equitable factors favored not requiring refunds in this case. The FERC also noted that, under Section 206(c) of the Federal Power Act, in a Section 206 proceeding involving two or more electric utility companies of a registered holding company system, the FERC may order refunds only if it determines the refunds would not cause the registered holding company to experience any reduction in revenues resulting from an inability of an electric utility company in the system to recover the resulting increase in costs. The FERC stated it was not able to find that the Entergy system would not experience a reduction in revenues if refunds were awarded in this proceeding, which further supported the denial of refunds. In May 2016 the LPSC filed a request for rehearing of the FERC’s April 2016 order. In September 2016 the FERC issued an order denying the LPSC’s request for rehearing and reaffirming its denial of refunds for the 15-month refund effective period. The LPSC appealed the April and September 2016 orders to the U.S. Court of Appeals for the D.C. Circuit. In March 2018 the D.C. Circuit issued an order denying the LPSC’s appeal and affirming the FERC’s decision that it would be inequitable to award refunds in the proceeding. In April 2018 the LPSC sought rehearing en banc of the D.C. Circuit’s order denying the LPSC’s appeal. In May 2018 the D.C. Circuit denied the LPSC’s rehearing request. In August 2018 the LPSC filed with the Supreme Court of the United States a petition for a writ of certiorari to review the judgment of the D.C. Circuit. In November 2018 the Supreme Court of the United States denied the LPSC’s petition for a writ of certiorari to review the judgment of the D.C. Circuit, effectively terminating the interruptible load proceeding.

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’s 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’s appeal and held all of the appeals in abeyance pending final resolution of the related proceeding before the FERC.

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 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. 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.

Complaints Against System Energy

Return on Equity 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 the FERC to institute 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. System Energy is recording a provision against revenue for the potential outcome of this proceeding. In September 2017 the FERC established a refund effective date of January 23, 2017, consolidated the return on equity complaint with the proceeding described in Unit Power Sales Agreement below, 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 effective date 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 System Energy’s return on equity, with a refund effective date of April 2018. The portion of the LPSC’s complaint dealing with return on equity was subsequently consolidated with the APSC and MPSC complaint for hearing. The consolidated hearing has been scheduled for September 2019, and the parties are required to address 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 complaint, and System Energy submitted a response to the amended complaint in October 2018. In January 2019 the FERC set the amended complaint for settlement and hearing proceedings.

Grand Gulf Sale-leaseback Renewal Complaint

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 2018. The hearing has been scheduled for November 2019.

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 proposed amendments would result in lower charges to the Utility operating companies that buy capacity and energy from System Energy under the Unit Power Sales Agreement. The proposed changes are 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. System Energy requested that the FERC accept the amendments effective October 1, 2017.

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 propose 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. The FERC also consolidated the Unit Power Sales Agreement amendment proceeding with the proceeding described in“Return on Equity Complaints” above, and directed the parties to engage in settlement proceedings before an ALJ. 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.  The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages.  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.

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.  In February 2012, Entergy Louisiana sold 500,000 of its Class A preferred membership units in Entergy Holdings Company LLC, a wholly-owned Entergy subsidiary, to a third party in exchange for $51 million plus accrued but unpaid distributions on the units.  The 500,000 preferred membership units are mandatorily redeemable in January 2112.

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. As of April 30, 2016, Entergy Mississippi’s storm damage provision balance was less than $10 million, therefore Entergy Mississippi resumed billing the monthly storm damage provision effective with June 2016 bills. As of September 30, 2016, however, Entergy Mississippi’s storm damage provision balance exceeded $15 million. Accordingly the storm damage provision was reset to zero beginning with November 2016 bills. As of July 31, 2017, the balance in Entergy Mississippi’s accumulated storm damage provision was again less than $10 million, therefore Entergy Mississippi resumed billing the monthly storm damage provision effective with September 2017 bills. As of June 30, 2018, Entergy Mississippi’s storm damage provision balance exceeded $15 million. Accordingly the storm damage provision was reset to zero beginning with August 2018 bills.

Entergy New Orleans

In August 2012, Hurricane Isaac caused extensive damage to Entergy New Orleans’s service area. In January 2015 the City Council issued a resolution approving the terms of a joint agreement in principle filed by Entergy New Orleans, Entergy Louisiana, and the City Council Advisors determining, among other things, that Entergy New Orleans’s prudently-incurred storm recovery costs were $49.3 million, of which $31.7 million, net of reimbursements from the storm reserve escrow account, remained recoverable from Entergy New Orleans’s electric customers. The resolution also directed Entergy New Orleans to file an application to securitize the unrecovered City Council-approved storm recovery costs of $31.7 million pursuant to the Louisiana Electric Utility Storm Recovery Securitization Act (Louisiana Act 64). In addition, the resolution found that it was reasonable for Entergy New Orleans to include in the principal amount of its potential securitization the costs to fund and replenish Entergy New Orleans’s storm reserve in an amount that achieved the City Council-approved funding level of $75 million. In January 2015, in compliance with that directive, Entergy New Orleans filed with the City Council an application requesting that the City Council grant a financing order authorizing the financing of Entergy New Orleans’s storm costs, storm reserves, and issuance costs pursuant to Louisiana Act 64. In May 2015 the parties entered into an agreement in principle and the City Council issued a financing order authorizing Entergy New Orleans to issue storm recovery bonds in the aggregate amount of $98.7 million, including $31.8 million for recovery of Entergy New Orleans’s Hurricane Isaac storm recovery costs, including carrying costs, $63.9 million to fund and replenish Entergy New Orleans’s storm reserve, and approximately $3 million for estimated up-front financing costs associated with the securitization. See Note 5 to the financial statements for discussion of the issuance of the securitization bonds in July 2015.

New Nuclear Generation Development Costs

Entergy Louisiana

Entergy Louisiana and Entergy Gulf States Louisiana were developing a project option for new nuclear generation at River Bend.  In March 2010, Entergy Louisiana and Entergy Gulf States Louisiana filed with the LPSC seeking approval to continue the limited development activities necessary to preserve an option to construct a new unit at River Bend.  At its June 2012 meeting the LPSC voted to uphold an ALJ recommendation that the request of Entergy Louisiana and Entergy Gulf States Louisiana be declined on the basis that the LPSC’s rule on new nuclear development does not apply to activities to preserve an option to develop and on the further grounds that the companies improperly engaged in advanced preparation activities prior to certification.  The LPSC directed that Entergy Louisiana and Entergy Gulf States Louisiana be permitted to seek recovery of these costs in their upcoming rate case filings that were subsequently filed in February 2013. In the resolution of the rate case proceeding the LPSC provided for an eight-year amortization of costs incurred in connection with the potential development of new nuclear generation at River Bend, without carrying costs, beginning in December 2014, provided, however, that amortization of these costs shall not result in a future rate increase. As of December 31, 2018, Entergy Louisiana has a regulatory asset of $28.5 million on its balance sheet related to these new nuclear generation development costs.

System Energy [Member]

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, 2018 and 2017:

Other Regulatory Assets

Entergy

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$2,611.5		$2,642.3
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	814.3		746.0
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 – Storm Cost Recovery Filings with Retail Regulators) (Note 5)	452.7		558.9
Removal costs - recovered through depreciation rates (Note 9)	375.8		436.5
Opportunity Sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding)	116.3		109.8
Unamortized loss on reacquired debt - recovered over term of debt	74.5		82.9
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy)	52.1		73.7
Retail rate deferrals - recovered through rate riders as rates are redetermined by retail regulators	39.0		86.4
New nuclear generation development costs (Note 2 - New Nuclear Generation Development Costs) (b)	29.0		36.4
Transition to competition costs - recovered over a 15-year period through February 2021	26.7		37.7
Other	154.6		125.1
Entergy Total		$4,746.5		$4,935.7

Entergy Arkansas

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$747.2		$757.0
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	381.7		345.2
Removal costs - recovered through depreciation rates (Note 9)	138.3		176.9
Opportunity sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding)	116.3		109.8
Storm damage costs - recovered either through securitization or retail rates (Note 5 - Entergy Arkansas Securitization Bonds)	60.7		76.2
Unamortized loss on reacquired debt - recovered over term of debt	21.2		24.3
Retail rate deferrals - recovered through rate riders as rates are redetermined annually	20.5		28.2
ANO Fukushima and Flood Barrier costs - recovered through retail rates through February 2026 (Note 2 - Retail Rate Proceedings) (b)	12.6		14.4
Other	36.5		35.4
Entergy Arkansas Total		$1,535.0		$1,567.4

Entergy Louisiana

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (a)		$711.8		$724.6
Asset Retirement Obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	232.9		218.6
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy)	49.8		71.4
New nuclear generation development costs - recovery through formula rate plan December 2014 through November 2022 (Note 2 - New Nuclear Generation Development Costs) (b)	28.5		35.8
Unamortized loss on reacquired debt - recovered over term of debt	22.5		24.7
Storm damage costs - recovered through retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)	17.9		14.3
Business combination external costs deferral - recovery through formula rate plan December 2015 through November 2025 (b)	12.4		14.1
River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC)	11.0		12.9
Other	18.3		29.4
Entergy Louisiana Total		$1,105.1		$1,145.8

Entergy Mississippi

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$215.9		$218.7
Removal costs - recovered through depreciation rates (Note 9)	63.5		91.6
Attorney General litigation costs (Note 2 - Mississippi Attorney General Complaint) (b)	23.6		9.3
Retail rate deferrals - recovered through rate riders as rates are redetermined annually	16.6		49.4
Unamortized loss on reacquired debt - recovered over term of debt	16.2		17.6
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a)	7.2		7.6
Other	—		3.7
Entergy Mississippi Total		$343.0		$397.9

Entergy New Orleans

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$96.2		$102.8
Storm damage costs, including hurricane costs - recovered through retail rates and securitization (Note 2 - Storm Cost Recovery Filings with Retail Regulators)	70.4		82.3
Removal costs - recovered through depreciation rates (Note 9)	49.3		44.8
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a)	4.5		4.3
Unamortized loss on reacquired debt - recovered over term of debt	2.6		3.0
Rate case costs - recovered over a 6-year period through September 2021 (Note 2 - Retail Rate Proceedings)	1.9		2.6
Retail rate deferrals - recovered through rate riders as rates are redetermined monthly or annually	—		4.4
Other	4.9		7.2
Entergy New Orleans Total		$229.8		$251.4

Entergy Texas

	2018		2017
	(In Millions)
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 5 - Entergy Texas Securitization Bonds)		$303.6		$386.1
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)	171.8		169.2
Removal costs - recovered through depreciation rates (Note 9)	50.9		55.2
Transition to competition costs - recovered over a 15-year period through February 2021	26.7		37.7
Neches and Sabine costs - recovered over a ten-year period through September 2028 (Note 2 - Retail Rate Proceedings) (b)	23.6		—
Unamortized loss on reacquired debt - recovered over term of debt	8.2		8.7
Other	13.2		4.5
Entergy Texas Total		$598.0		$661.4

System Energy

	2018		2017
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Other Postretirement Benefits) (a)		$179.3		$202.7
Asset retirement obligation - recovery dependent upon timing of decommissioning (Note 9) (a)	186.9		169.1
Removal costs - recovered through depreciation rates (Note 9)	76.4		67.9
Unamortized loss on reacquired debt - recovered over term of debt	3.8		4.6
System Energy Total		$446.4		$444.3

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

(b) Does not earn a return on investment.

Other Regulatory Liabilities

Entergy

	2018		2017
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)		$815.9		$989.3
Vidalia purchased power agreement (Note 8) (b)	139.7		151.6
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) (b)	111.1		124.8
Income tax rate change - returned to electric and gas customers through retail rates (Note 2 - Retail Rate Proceedings)	74.7		—
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions)	67.9		67.9
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination)	50.8		65.8
Grand Gulf over-recovery - will be refunded through rate riders as rates are redetermined annually	48.6		—
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)	44.4		—
Internal restructuring guaranteed customer credits (Note 2 - Retail Rate Proceedings)	39.6		—
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)	39.1		36.7
Excess decommissioning recovery for Willow Glen - (Note 14 - Dispositions)	31.9		—
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement	25.0		32.1
Removal costs - returned to customers through depreciation rates (Note 9)	18.8		32.4
Other	68.4		43.5
Entergy Total		$1,620.3		$1,588.5

Entergy Arkansas

	2018		2017
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)		$297.2		$354.0
Internal restructuring guaranteed customer credits (Note 2 - Retail Rate Proceedings)	39.6		—
Future formula rate plan revenue reductions (Note 2 - Retail Rate Proceedings)	35.1		—
Grand Gulf over-recovery - will be refunded through rate riders as rates are redetermined annually	26.0		—
Other	4.8		9.6
Entergy Arkansas Total		$402.7		$363.6

Entergy Louisiana

	2018		2017
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)		$274.1		$323.7
Vidalia purchased power agreement (Note 8) (b)	139.7		151.6
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) (b)	111.1		124.8
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination)	50.8		65.8
Income tax rate change - returned to electric customers through retail rates September 2018 through August 2019 (Note 2 - Retail Rate Proceedings)	49.9		—
Asset Retirement Obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)	39.1		36.7
Excess decommissioning recovery for Willow Glen - (Note 14 - Dispositions)	31.9		—
Removal costs - returned to customers through depreciation rates (Note 9)	18.8		32.4
Other	33.4		26.1
Entergy Louisiana Total		$748.8		$761.1

Entergy Mississippi

	2018		2017
	(In Millions)
Grand Gulf Over-Recovery - returned to customers through rate riders when rates are redetermined annually		$22.6		$—
Future formula rate plan revenue reductions (Note 2 - Retail Rate Proceedings)	9.3		—
Other	1.7		0.9
Entergy Mississippi Total		$33.6		$0.9

Entergy Texas

	2018		2017
	(In Millions)
Income tax rate change - refunded through a rate rider (Note 2 - Retail Rate Proceedings)		$23.1		$—
Advanced metering system surcharge (Note 2 - Advanced Metering Infrastructure (AMI) Filings)	16.5		—
Transition to competition costs - returned to customers through rate riders when rates are redetermined periodically	4.2		4.8
Other	4.1		2.1
Entergy Texas Total		$47.9		$6.9

System Energy

	2018		2017
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 17) (a)		$244.6		$311.6
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions)	67.9		67.9
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
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement	25.0		32.1
System Energy Total		$381.9		$456.0

(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 $25.0 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 will be 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 to be 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 existing formula rate plan rider for its customers to realize the remaining benefits of the Tax Act. Entergy Arkansas’s formula rate plan rider includes a netting adjustment that compares 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.

Entergy Louisiana

In a 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 will be 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. Entergy Mississippi’s formula rate plan includes a look-back evaluation report filing in March 2019 that will compare actual 2018 results to the allowed return on rate base. The stipulation approved in June 2018 provides 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 any true-up to be 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. In November 2018, Entergy Mississippi’s annual redetermination of the annual factor to be applied under the power management rider included an insignificant true-up to the amount of unprotected excess accumulated deferred income taxes. In January 2019 the MPSC approved the proposed power management cost factor effective for February 2019 bills.

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. In both a memorandum issued prior to the open meeting when the order was discussed and during the discussions at the open meeting regarding the order, the PUCT indicated that it would consider utility earnings in determining the treatment of the liability and the effects of the Tax Act. 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. Entergy Texas also stated that it would be inappropriate for the PUCT to require a refund of the reduction in income tax expense in 2018 resulting from the Act on a retroactive basis and without a comprehensive review of Entergy Texas’s cost of service and earned return on equity.

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 will 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 will 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 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 larger customers and over a period of four years for other customers.

System Energy

In a filing made with the FERC in March 2018, Entergy proposed revisions to the Unit Power Sales Agreement, among other agreements, to reflect the effects of the Tax Act. In the filing System Energy proposed to return all of its 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 are ongoing.

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, 2018 and 2017 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.

	2018			2017
	(In Millions)
Entergy Arkansas (a)		$86.5			$130.4
Entergy Louisiana (b)		$136.7			$96.7
Entergy Mississippi		$8.0			$32.4
Entergy New Orleans (b)		$2.8			($3.7	)
Entergy Texas		($19.7	)		($67.3	)

(a) Includes $67.3 million in 2018 and $67.1 million in 2017 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

Production Cost Allocation Rider

The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings, which are discussed in the “System Agreement Cost Equalization Proceedings” section below.

In May 2016, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected recovery of the production cost allocation rider true-up adjustment of the 2014 and 2015 unrecovered retail balance in the amount of $1.9 million. Additionally, the redetermined rates reflected the recovery of a $1.9 million System Agreement bandwidth remedy payment resulting from a compliance filing pursuant to the FERC’s December 2015 order related to test year 2009 production costs. The rates for the 2016 production cost allocation rider update were effective July 2016 through June 2017.

In May 2017, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected a credit amount of $0.3 million resulting from a compliance filing pursuant to the FERC’s September 2016 order. Additionally, the redetermined rate reflected recovery of the production cost allocation rider true-up adjustment of the 2016 unrecovered retail balance in the amount of $0.3 million. Because of the small effect of the 2017 production cost allocation rider update, Entergy Arkansas proposed to reduce the effective period of the update to one month, July 2017. After the one month collection period, rates were set to zero for all rate classes for the period August 2017 through June 2018.

In May 2018, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected recovery of the 2017 under-recovered retail balance and a $2.8 million payment by Entergy Arkansas associated with a compliance filing pursuant to a March 2018 FERC order related to 2010 production costs. The rates for the 2018 production cost allocation rider update are effective July 2018 through June 2019.

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.

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 December 2011 the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates.  The audit included a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 2005 through 2009.  In March 2016 the LPSC staff consultant issued its audit report. In its report, the LPSC staff consultant recommended that Entergy Louisiana refund approximately $8.6 million, plus interest, to customers and realign the recovery of approximately $12.7 million from Entergy Gulf States Louisiana’s fuel adjustment clause to base rates. In September 2016 the LPSC staff filed testimony stating that it was no longer recommending a disallowance of $3.4 million of the $8.6 million discussed above, but otherwise maintained the positions from its report. Subsequently, the parties entered into a settlement, which was approved by the LPSC in November 2016. The settlement recognized the dry cask storage recovery method issue, which was addressed in the separate proceeding approved by the LPSC in October 2017, provided for a refund of $5 million, which was made to legacy Entergy Gulf States Louisiana customers in December 2016, and resolved all other issues raised in the audit.

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 is evaluating the staff’s recommended disallowance.

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 consultant issued its audit report. In its report, the LPSC staff consultant recommended 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 is evaluating the staff’s recommended disallowance.

In June 2016 the LPSC staff provided notice of audits of Entergy Louisiana’s fuel adjustment clause filings and purchased gas adjustment clause filings. In recognition of the business combination that occurred in 2015, the audit notice was issued to Entergy Louisiana and will also include a review of charges to legacy Entergy Gulf States Louisiana customers prior to the business combination. The audit includes 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. Discovery commenced in March 2017. No report of audit has been issued.

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.  Discovery commenced in September 2018.  No report of audit has been issued.

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 November 2015, 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 a projected over-recovery balance of $48 million projected through January 31, 2016. In January 2016 the MPSC approved the redetermined annual factor effective February 1, 2016. The MPSC further ordered, however, that due to the significant change in natural gas price forecasts since Entergy Mississippi’s filing in November 2015 Entergy Mississippi should file a revised fuel factor with the MPSC no later than February 1, 2016. Pursuant to that order, Entergy Mississippi submitted a revised fuel factor. Additionally, because Entergy Mississippi’s projected over-recovery balance for the period ending January 31, 2016 was $68 million, in February 2016, Entergy Mississippi filed for another interim adjustment to the energy cost factor effective April 2016 to flow through to customers the projected over-recovery balance over a six-month period. That interim adjustment was approved by the MPSC in February 2016 effective for April 2016 bills.

In November 2016, 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 less than $2 million as of September 30, 2016. In January 2017 the MPSC approved the annual factor effective with February 2017 bills. Also 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 its order, the MPSC expressly reserved the right to review and determine the recoverability of any and all purchased power expenditures made during fiscal year 2016. The MPSC hired independent auditors to conduct an annual operations audit and a financial audit. The independent auditors issued their audit reports in December 2017. The audit reports included several recommendations for action by Entergy Mississippi but did not recommend any cost disallowances. In January 2018 the MPSC certified the audit reports to the Mississippi Legislature. In November 2017 the Public Utilities Staff separately engaged a consultant to review the outage at the Grand Gulf Nuclear Station that began in 2016. The review is currently in progress.

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. Entergy Mississippi proposed a two-tiered energy cost factor designed to promote overall rate stability throughout 2018 particularly during the summer months. 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.

Mississippi Attorney General Complaint

The Mississippi Attorney General filed a complaint in state court in December 2008 against Entergy Corporation, Entergy Mississippi, Entergy Services, and Entergy Power alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution.  The complaint is wide ranging and relates to tariffs and procedures under which Entergy Mississippi purchases power not generated in Mississippi to meet electricity demand.  Entergy believes the complaint is unfounded.  In December 2008 the defendant Entergy companies removed the Attorney General’s lawsuit to U.S. District Court in Jackson, Mississippi. In June 2010 the MPSC authorized the deferral of certain legal expenses associated with this litigation until it is resolved. As of December 31, 2018, Entergy Mississippi has a regulatory asset of $23.6 million for these deferred legal expenses. Pre-trial and settlement conferences were held in October 2018. In October 2018 the District Court rescheduled the trial to April 2019.

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 July 2015 certain parties filed briefs in a PUCT proceeding asserting that Entergy Texas should refund to retail customers an additional $10.9 million in bandwidth remedy payments Entergy Texas received related to calendar year 2006 production costs.  In October 2015 an ALJ issued a proposal for decision recommending that the additional bandwidth remedy payments be refunded to retail customers. In January 2016 the PUCT issued its order affirming the ALJ’s recommendation, and Entergy Texas filed a motion for rehearing of the PUCT’s decision, which the PUCT denied. In March 2016, Entergy Texas filed a complaint in Federal District Court for the Western District of Texas and a petition in the Travis County (State) District Court appealing the PUCT’s decision. The pending appeals did not stay the PUCT’s decision. In April 2016, Entergy Texas filed with the PUCT an application to refund to customers approximately $56.2 million. The refund resulted from (i) $41.8 million of fuel cost recovery over-collections through February 2016, (ii) the $10.9 million in bandwidth remedy payments, discussed above, that Entergy Texas received related to calendar year 2006 production costs, and (iii) $3.5 million in bandwidth remedy payments that Entergy Texas received related to 2006-2008 production costs. In June 2016, Entergy Texas filed an unopposed settlement agreement that added additional over-recovered fuel costs for the months of March and April 2016. The settlement resulted in a $68 million refund. The ALJ approved the refund on an interim basis and it was made to most customers over a four-month period beginning with the first billing cycle of July 2016. In July 2016 the PUCT issued an order approving the interim refund. The federal appeal of the PUCT’s January 2016 decision was heard in December 2016, and the Federal District Court granted Entergy Texas’s requested relief. In January 2017 the PUCT and an intervenor filed petitions for appeal of the Federal District Court ruling to the U.S. Court of Appeals for the Fifth Circuit. Oral argument was held before the Fifth Circuit in February 2018. In April 2018 the Fifth Circuit reversed the decision of the Federal District Court, reinstating the original PUCT decision. In October 2018, Entergy Texas filed notice of nonsuit in its appeal to the Travis County District Court regarding the PUCT’s January 2016 decision.

In July 2016, Entergy Texas filed an application to reconcile its fuel and purchased power costs for the period April 1, 2013 through March 31, 2016. During the reconciliation period, Entergy Texas incurred approximately $1.77 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 over-recovery balance of approximately $19.3 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning April 2016. Entergy Texas also noted, however, that the estimated $19.3 million over collection was being refunded to customers as a portion of the interim fuel refund beginning with the first billing cycle of July 2016, discussed above. Entergy Texas also requested a prudence finding for each of the fuel-related contracts and arrangements entered into or modified during the reconciliation period that have not been reviewed by the PUCT in a prior proceeding. In December 2016, Entergy Texas entered into a stipulation and settlement agreement resulting in a $6 million disallowance not associated with any particular issue raised and a refund of the over-recovery balance of $21 million as of November 30, 2016, to most customers beginning April 2017 through June 2017. This settlement was developed concurrently with the stipulation and settlement agreement in the 2016 transmission cost recovery factor rider amendment discussed below, and the terms and conditions in both settlements are interdependent. The fuel reconciliation settlement was approved by the PUCT in March 2017 and the refunds were made.

In June 2017, Entergy Texas filed an application for a fuel refund of approximately $30.7 million for the months of December 2016 through April 2017. For most customers, the refunds flowed through bills for the months of July 2017 through September 2017. The fuel refund was approved by the PUCT in August 2017.

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.

Retail Rate Proceedings

Filings with the APSC (Entergy Arkansas)

Retail Rates

2015 Base Rate Filing

In April 2015, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. The filing notified the APSC of Entergy Arkansas’s intent to implement a forward test year formula rate plan pursuant to Arkansas legislation passed in 2015, and requested a retail rate increase of $268.4 million, with a net increase in revenue of $167 million. The filing requested a 10.2% return on common equity. In December 2015, Entergy Arkansas, the APSC staff, and certain of the intervenors in the rate case filed with the APSC a joint motion for approval of a settlement of the case that proposed a retail rate increase of approximately $225 million with a net increase in revenue of approximately $133 million; an authorized return on common equity of 9.75%; and a formula rate plan tariff that provides a +/- 50 basis point band around the 9.75% allowed return on common equity. A significant portion of the rate increase is related to Entergy Arkansas’s acquisition in March 2016 of Union Power Station Power Block 2 for a base purchase price of $237 million. The settlement agreement also provided for amortization over a 10-year period of $7.7 million of previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance. In February 2016 the APSC approved the settlement with one exception that reduced the retail rate increase proposed in the settlement by $5 million. The settling parties agreed to the APSC modifications in February 2016. The new rates were effective February 24, 2016 and began billing with the first billing cycle of April 2016. In March 2016, Entergy Arkansas made a compliance filing regarding the new rates that included an interim base rate adjustment surcharge, effective with the first billing cycle of April 2016, to recover the incremental revenue requirement for the period February 24, 2016 through March 31, 2016. The interim base rate adjustment surcharge was designed to recover a total of $21.1 million over the nine-month period from April 2016 through December 2016.

2016 Formula Rate Plan Filing

In July 2016, Entergy Arkansas filed with the APSC its 2016 formula rate plan filing showing Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2017 test period to be below the formula rate plan bandwidth. The filing requested a $67.7 million revenue requirement increase to achieve Entergy Arkansas’s target earned return on common equity of 9.75%. In October 2016, Entergy Arkansas filed with the APSC revised formula rate plan attachments with an updated request for a $54.4 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors, as well as three additional adjustments identified as appropriate by Entergy Arkansas. In November 2016 a hearing was held and the APSC issued an order directing the parties to brief certain issues. In December 2016 the APSC approved a settlement agreement and the $54.4 million revenue requirement increase with approximately $25 million of the $54.4 million revenue requirement subject to possible future adjustment and refund to customers with interest. The APSC requested supplemental information for some of Entergy Arkansas’s requested nuclear expenditures. In December 2016 the APSC approved Entergy Arkansas’s formula rate plan compliance tariff, and the rates became effective with the first billing cycle of January 2017. In April 2017, Entergy Arkansas filed a motion consented to by all parties requesting that it be permitted to submit the supplemental information requested by the APSC in conjunction with its 2017 formula rate plan filing, which was subsequently made in July 2017 and is discussed below. In May 2017 the APSC approved the joint motion and proposal to review Entergy Arkansas’s supplemental information on a concurrent schedule with the 2017 formula rate plan filing. In October 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement resolving all issues in the proceeding and providing for recovery of the 2017 and 2018 nuclear costs. In December 2017 the APSC approved the settlement agreement and recovery of the 2017 and 2018 nuclear costs.

2017 Formula Rate Plan Filing

In July 2017, Entergy Arkansas filed with the APSC its 2017 formula rate plan filing showing Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2018 test period to be below the formula rate plan bandwidth.  The filing projected a $129.7 million revenue requirement increase to achieve Entergy Arkansas’s target earned return on common equity of 9.75%.  Entergy Arkansas’s formula rate plan is subject to a four percent annual revenue constraint and the projected annual revenue requirement increase exceeded the four percent, resulting in a proposed increase for the 2017 formula rate plan of $70.9 million. In October 2017, Entergy Arkansas filed with the APSC revised formula rate plan attachments that projected a $126.2 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors. The revised formula rate plan filing included a proposed $71.1 million revenue requirement increase based on a revision to the four percent constraint calculation. In October 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement resolving all issues in the proceeding and providing for recovery of the 2017 and 2018 nuclear costs. In December 2017 the APSC approved the settlement agreement and the $71.1 million revenue requirement increase, as well as Entergy Arkansas’s formula rate plan compliance tariff, and the rates became effective with the first billing cycle of January 2018.

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 shows 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 includes 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 includes a projected $73.4 millionrevenue 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 exceeds the constraint, the resulting increase is 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, which included additional actual revenues for 2018. 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 certain 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. An additional schedule was issued by the APSC for briefing other contested issues, the outcome of which did not affect the 2018 filing but could affect future Entergy Arkansas formula rate plan filings. That briefing was completed in February 2019, and the APSC has not indicated when a decision on those issues can be expected.

Similar to the 2018 filing, the formula rate plan filing that will be made in 2019 to set the formula rates for the 2020 calendar year will include a netting adjustment that will compare projected costs and sales for 2018 that were approved in the 2017 formula rate plan filing to actual 2018 costs and sales data. In the fourth quarter 2018, Entergy Arkansas recorded a provision of $35.1 million that reflects the estimate of the historical year netting adjustment that will be included in the 2019 filing to reflect the change in formula rate plan revenues associated with actual 2018 results when compared to the allowed rate of return on equity. 

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. Entergy Arkansas also filed a notice with the Missouri Public Service Commission in December 2017 out of an abundance of caution, although Entergy Arkansas does not serve any retail customers in Missouri. In April 2018 the Missouri Public Service Commission approved Entergy Arkansas’s filing. 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

2015 Formula Rate Plan Filing

In May 2016, Entergy Louisiana filed its formula rate plan evaluation report for its 2015 calendar year operations. The evaluation report reflected an earned return on common equity of 9.07%. As such, no adjustment to base formula rate plan revenue was required. The following other adjustments, however, were required under the formula rate plan: an increase in the legacy Entergy Louisiana additional capacity mechanism of $14.2 million; a separate increase in legacy Entergy Louisiana revenue of $10 million primarily to reflect the effects of the termination of the System Agreement; an increase in the legacy Entergy Gulf States Louisiana additional capacity mechanism of $0.5 million; a decrease in legacy Entergy Gulf States Louisiana revenue of $58.7 million primarily to reflect the effects of the termination of the System Agreement; and an increase of $11 million to the MISO cost recovery mechanism. Rates were implemented with the first billing cycle of September 2016, subject to refund. Following implementation of the as-filed rates in September 2016, there were several interim updates to Entergy Louisiana’s formula rate plan, including the one submitted in December 2016, reflecting implementation of the settlement of the Waterford 3 replacement steam generator project prudence review described below. In June 2017 the LPSC staff and Entergy Louisiana filed a joint report of proceedings, which was accepted by the LPSC in June 2017, finalizing the results of the May 2016 evaluation report, interim updates, and corresponding proceedings with no changes to rates already implemented.

2016 Formula Rate Plan Filing

In May 2017, Entergy Louisiana filed its formula rate plan evaluation report for its 2016 calendar year operations. The evaluation report reflected an earned return on common equity of 9.84%. As such, no adjustment to base formula rate plan revenue was required. Adjustments, however, were required under the formula rate plan; the 2016 formula rate plan evaluation report showed a decrease in formula rate plan revenue of approximately $16.9 million, comprised of a decrease in legacy Entergy Louisiana formula rate plan revenue of $3.5 million, a decrease in legacy Entergy Gulf States Louisiana formula rate plan revenue of $9.7 million, and a decrease in incremental formula rate plan revenue of $3.7 million. Additionally, the formula rate plan evaluation report called for a decrease of $40.5 million in the MISO cost recovery revenue requirement from $46.8 million to $6.3 million. Rates reflecting these adjustments were implemented with the first billing cycle of September 2017, subject to refund. In September 2017 the LPSC issued its report indicating that no changes to Entergy Louisiana’s original formula rate plan evaluation report were required but reserved for several issues, including Entergy Louisiana’s September 2017 update to its formula rate plan evaluation report.  In July 2018, Entergy Louisiana and the LPSC staff filed an unopposed joint report setting forth a correction to the annualization calculation, the effect of which was a net $3.5 million revenue requirement reduction and indicating that there are no outstanding issues with the 2016 formula rate plan report, the supplemental report, or the interim updates.  In September 2018 the LPSC approved the unopposed joint report.

Formula Rate Plan Extension Through 2019 Test Year

In August 2017, Entergy Louisiana filed a request with the LPSC seeking to extend its formula rate plan for three years (2017-2019) with limited modifications of its terms.  Those modifications include: a one-time resetting of base rates to the midpoint of the band at Entergy Louisiana’s authorized return on equity of 9.95% for the 2017 test year; narrowing of the formula rate plan bandwidth from a total of 160 basis points to 80 basis points; and a forward-looking mechanism that would allow Entergy Louisiana to recover certain transmission-related costs contemporaneously with when those projects begin delivering benefits to customers.  In April 2018 the LPSC approved an unopposed joint motion filed by Entergy Louisiana and the LPSC staff that settled the matter. The settlement extended the formula rate plan for three years, providing for rates through at least August 2021. In addition to retaining the major features of the traditional formula rate plan, substantive features of the extended formula rate plan include:

• a mid-point reset of formula rate plan revenues to a 9.95% earned return on common equity for the 2017 test year and for the St. Charles Power Station when it enters commercial operation;

• a 9.8% target earned return on common equity for the 2018 and 2019 test years;

• narrowing of the common equity bandwidth to plus or minus 60 basis points around the target earned return on common equity;

• a cap on potential revenue increase of $35 million for the 2018 evaluation period, and $70 million for the cumulative 2018 and 2019 evaluation periods, on formula rate plan cost of service rate increases (the cap excludes rate changes associated with the transmission recovery mechanism described below and rate changes associated with additional capacity);

• a framework for the flow back of certain tax benefits created by the Tax Act to customers, as described in “Regulatory activity regarding the Tax Cuts and Jobs Act” above; and

• a transmission recovery mechanism providing for the opportunity to recover certain transmission-related expenditures in excess of $100 million annually for projects placed in service up to one month prior to rate change outside of sharing that is designed to operate in a fashion similar to the additional capacity mechanism.

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.

Waterford 3 Replacement Steam Generator Project

Following the completion of the Waterford 3 replacement steam generator project, the LPSC undertook a prudence review in connection with a filing made by Entergy Louisiana in April 2013 with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs. In July 2014 the LPSC staff filed testimony recommending potential project and replacement power cost disallowances of up to $71 million, citing a need for further explanation or documentation from Entergy Louisiana.  An intervenor filed testimony recommending disallowance of $141 million of incremental project costs, claiming the steam generator fabricator was imprudent.  Entergy Louisiana provided further documentation and explanation requested by the LPSC staff. An evidentiary hearing was held in December 2014. Entergy Louisiana believed that the replacement steam generator costs were prudently incurred and applicable legal principles supported their recovery in rates.  Nevertheless, Entergy Louisiana recorded a write-off of $16 million of Waterford 3’s plant balance in December 2014 because of the uncertainty at the time associated with the resolution of the prudence review. In December 2015 the ALJ issued a proposed recommendation, which was subsequently finalized, concluding that Entergy Louisiana prudently managed the Waterford 3 replacement steam generator project, including the selection, use, and oversight of contractors, and could not reasonably have anticipated the damage to the steam generators. Nevertheless, the ALJ concluded that Entergy Louisiana was liable for the conduct of its contractor and subcontractor and, therefore, recommended a disallowance of $67 million in capital costs. Additionally, the ALJ concluded that Entergy Louisiana did not sufficiently justify the incurrence of $2 million in replacement power costs during the replacement outage. Although the ALJ’s recommendation had not yet been considered by the LPSC, after considering the progress of the proceeding in light of the ALJ recommendation, Entergy Louisiana recorded in the fourth quarter 2015 approximately $77 million in charges, including a $45 million asset write-off and a $32 million regulatory charge, to reflect that a portion of the assets associated with the Waterford 3 replacement steam generator project was no longer probable of recovery. Entergy Louisiana maintained that the ALJ’s recommendation contained significant factual and legal errors.

In October 2016 the parties reached a settlement in this matter. The settlement was approved by the LPSC in December 2016. The settlement effectively provided for an agreed-upon disallowance of $67 million of plant, which had been previously written off by Entergy Louisiana, as discussed above. The refund to customers of approximately $71 million as a result of the settlement approved by the LPSC was made to customers in January 2017. Of the $71 million of refunds, $68 million was credited to customers through Entergy Louisiana’s formula rate plan, outside of sharing, and $3 million through its fuel adjustment clause. Entergy Louisiana had previously recorded a provision of $48 million for this refund. The previously-recorded provision included the cumulative revenues recorded through December 2016 related to the $67 million of disallowed plant. An additional regulatory charge of $23 million was recorded in fourth quarter 2016 to reflect the effects of the settlement. The settlement also provided that Entergy Louisiana could retain the value associated with potential service credits agreed to by the project contractor, to the extent they are realized in the future. Following a review by the parties, an unopposed joint report of proceedings was filed by the LPSC staff and Entergy Louisiana in May 2017 and the LPSC accepted the joint report of proceedings resolving the matter.

Union Power Station and Deactivation or Retirement Decisions for Entergy Louisiana Plants

In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC for approval of the acquisition and cost recovery of two power blocks of the Union Power Station for an expected base purchase price of approximately $237 million per power block, subject to adjustments. In September 2015, Entergy Gulf States Louisiana agreed to settlement terms with all parties for Entergy Gulf States Louisiana’s purchase of the two power blocks. In October 2015 the LPSC voted unanimously to approve the uncontested settlement which finds, among other things, that acquisition of Power Blocks 3 and 4 is in the public interest and, therefore, prudent. The business combination of Entergy Gulf States Louisiana and Entergy Louisiana received regulatory approval and closed in October 2015 making Entergy Louisiana the named purchaser of Power Blocks 3 and 4 of the Union Power Station. In March 2016, Entergy Louisiana acquired Power Blocks 3 and 4 of Union Power Station for an aggregate purchase price of approximately $475 million and implemented rates to collect the estimated first-year revenue requirement with the first billing cycle of March 2016.

As a term of the LPSC-approved settlement authorizing the purchase of Power Blocks 3 and 4 of the Union Power Station, Entergy Louisiana agreed to make a filing with the LPSC to review its decisions to deactivate Ninemile 3 and Willow Glen 2 and 4 and its decision to retire Little Gypsy 1.  In January 2016, Entergy Louisiana made its compliance filing with the LPSC. Entergy Louisiana, LPSC staff, and intervenors participated in a technical conference in March 2016 where Entergy Louisiana presented information on its deactivation/retirement decisions for these four units in addition to information on the current deactivation decisions for the ten-year planning horizon. Parties requested further proceedings on the prudence of the decision to deactivate Willow Glen 2 and 4.  No party contested the prudence of the decision to deactivate Willow Glen 2 and 4 or suggested reactivation of these units; however, issues were raised related to Entergy Louisiana’s decision to give up its transmission service rights in MISO for Willow Glen 2 and 4 rather than placing the units into suspended status for the three-year term permitted by MISO. In March 2018 the LPSC adopted the ALJ’s recommended order finding that Entergy Louisiana did not demonstrate that its decision to permanently surrender transmission rights for the mothballed (not retired) Willow Glen 2 and 4 units was reasonable and that Entergy Louisiana should hold customers harmless from increased transmission expenses should those units be reactivated. Because no party or the LPSC suggested that Willow Glen 2 and 4 should be reactivated and because the cost to return those units to service far exceeded the revenue the units were expected to generate in MISO, Entergy Louisiana retired Willow Glen 2 and 4 in March 2018. Entergy Louisiana submitted a compliance filing regarding retirement of Willow Glen 2 and 4, and the LPSC closed the proceeding.

Retail Rates - Gas

2016 Rate Stabilization Plan Filing

In January 2017, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2016. The filing of the evaluation report for test year 2016 reflected an earned return on common equity of 6.37%. In April 2017 the LPSC approved a joint report of proceedings and Entergy Louisiana submitted a revised evaluation report reflecting a $1.2 million annual increase in revenue with rates implemented with the first billing cycle of May 2017.

2017 Rate Stabilization Plan Filing

In January 2018, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2017.  The filing of the evaluation report for the test year 2017 reflected an earned return on common equity of 9.06%.  This earned return is below the earnings sharing band of the rate stabilization plan and results in a rate increase of $0.1 million.  Due to the enactment in late-December 2017 of the Tax Cuts and Jobs Act, Entergy Louisiana did not have adequate time to reflect the effects of this tax legislation in the rate stabilization plan.  In April 2018, Entergy Louisiana filed a supplemental evaluation report for the test year ended September 2017, reflecting the effects of the Tax Act, including a proposal to use the unprotected excess accumulated deferred income taxes to offset approximately $1.4 million of storm restoration deferred operation and maintenance costs incurred by Entergy Louisiana in connection with the August 2016 flooding disaster in its gas service area. The supplemental filing reflects an earned return on common equity of 10.79%. As-filed rates from the supplemental filing were implemented, subject to refund, with customers receiving a cost reduction of approximately $0.7 million effective with bills rendered on and after the first billing cycle of May 2018, as well as a $0.2 million reduction in the gas infrastructure rider effective with bills rendered on and after the first billing cycle of July 2018. The proceeding is currently in its discovery phase. A procedural schedule has not been established.

2018 Rate Stabilization Plan Filing

In January 2019, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2018. The filing of the evaluation report for the test year 2018 reflected an earned return on common equity of 2.69%. This earned return is below the earning sharing band of the gas rate stabilization plan and results in a rate increase of $2.8 million. Entergy Louisiana will make a compliance filing in April 2019 and rates will be implemented during the first billing cycle of May 2019.

Filings with the MPSC (Entergy Mississippi)

Formula Rate Plan Filings

In March 2016, Entergy Mississippi submitted its formula rate plan 2016 test year filing showing Entergy Mississippi’s projected earned return for the 2016 calendar year to be below the formula rate plan bandwidth. The filing showed a $32.6 million rate increase was necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 9.96%, within the formula rate plan bandwidth. In June 2016 the MPSC approved Entergy Mississippi’s joint stipulation with the Mississippi Public Utilities Staff. The joint stipulation provided for a total revenue increase of $23.7 million. The revenue increase included a $19.4 million increase through the formula rate plan, resulting in a return on common equity point of adjustment of 10.07%. The revenue increase also included $4.3 million in incremental ad valorem tax expenses to be collected through an updated ad valorem tax adjustment rider. The revenue increase and ad valorem tax adjustment rider were effective with the July 2016 bills.

In March 2017, Entergy Mississippi submitted its formula rate plan 2017 test year filing and 2016 look-back filing showing Entergy Mississippi’s earned return for the historical 2016 calendar year and projected earned return for the 2017 calendar year to be within the formula rate plan bandwidth, resulting in no change in rates. In June 2017, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a stipulation that confirmed that Entergy Mississippi’s earned returns for both the 2016 look-back filing and 2017 test year were within the respective formula rate plan bandwidths. In June 2017 the MPSC approved the stipulation, which resulted in no change in rates.

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.

Entergy Mississippi’s formula rate plan includes a look-back evaluation report filing in March 2019 that will compare actual 2018 results to the performance-adjusted allowed return on rate base.  In fourth quarter 2018, Entergy Mississippi recorded a provision of $9.3 million that reflects the estimate of the difference between the 2018 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 October 2018, Entergy Mississippi proposed revisions to its formula rate plan that would provide for a mechanism, the interim capacity rate adjustment mechanism, in the formula rate plan 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 additions, such as the Sunflower Solar Facility, that are approved by the MPSC.

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

As a provision of the settlement agreement approved by the City Council in May 2015 providing for the transfer from Entergy Louisiana to Entergy New Orleans of certain assets that supported the provision of service to Entergy Louisiana’s customers in Algiers, it was agreed that, with limited exceptions, no action may be taken with respect to Entergy New Orleans’s base rates until rates are implemented from a base rate case that must be filed for its electric and gas operations in 2018. This provision eliminated the formula rate plan applicable to Algiers operations. The limited exceptions included continued implementation of the then-remaining two years of the four-year phased-in rate increase for the Algiers area and certain exceptional cost increases or decreases in the base revenue requirement. An additional provision of the settlement agreement allowed for continued recovery of the revenue requirement associated with the capacity and energy from Ninemile 6 received by Entergy New Orleans under a power purchase agreement with Entergy Louisiana (Algiers PPA). The settlement authorized Entergy New Orleans to recover the remaining revenue requirement related to the Algiers PPA through base rates charged to Algiers customers. The settlement also provided for continued implementation of the Algiers MISO recovery rider.

In addition to the Algiers PPA, Entergy New Orleans has a separate power purchase agreement with Entergy Louisiana for 20% of the capacity and energy from Ninemile 6 (Ninemile PPA), which commenced operation in December 2014. Initially, recovery of the non-fuel costs associated with the Ninemile PPA was authorized through a special Ninemile 6 rider billed only to Entergy New Orleans customers outside of Algiers.

In August 2015, Entergy New Orleans filed an application with the City Council seeking authorization to proceed with the purchase of Union Power Block 1, with an expected base purchase price of approximately $237 million, subject to adjustments, and seeking approval of the recovery of the associated costs. In November 2015 the City Council issued written resolutions and an order approving an agreement in principle between Entergy New Orleans and City Council advisors providing that the purchase of Union Power Block 1 and related assets by Entergy New Orleans is prudent and in the public interest. The City Council authorized expansion of the terms of the purchased power and capacity acquisition cost recovery rider to recover the non-fuel purchased power expense from Ninemile 6, the revenue requirement associated with the purchase of Power Block 1 of the Union Power Station, and a credit to customers of $400 thousand monthly beginning June 2016 in recognition of the decrease in other operation and maintenance expenses that would result with the deactivation of Michoud Units 2 and 3. In March 2016, Entergy New Orleans purchased Power Block 1 of the Union Power Station for approximately $237 million and initiated recovery of these costs with March 2016 bills. In July 2016, Entergy New Orleans and the City Council Utility Committee agreed to a temporary increase in the Michoud credit to customers to a total of $1.4 million monthly for August 2016 through December 2016.

A 2008 rate case settlement included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs.  The rate settlement provided an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provided a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs. In January 2015 the City Council approved funding for the Energy Smart program from April 2015 through March 2017 using the remainder of the approximately $12.8 million of 2014 rough production cost equalization funds, with any remaining costs being recovered through the fuel adjustment clause. This funding methodology was modified in November 2015 when the City Council directed Entergy New Orleans to use a combination of guaranteed customer savings related to a prior agreement with the City Council and rough production cost equalization funds to cover program costs prior to recovering any costs through the fuel adjustment clause. In April 2017 the City Council approved an implementation plan for the Energy Smart program from April 2017 through December 2019. The City Council directed that the $11.8 million balance reported for Energy Smart funds be used to continue funding the program for Entergy New Orleans’s legacy customers and that the Energy Smart Algiers program continue to be funded through the Algiers fuel adjustment clause, until additional customer funding is required for the legacy customers. In September 2017, Entergy New Orleans filed a supplemental plan and proposed several options for an interim cost recovery mechanism necessary to recover program costs during the period between when existing funds directed to Energy Smart programs are depleted and when new rates from the 2018 combined rate case, which includes a cost recovery mechanism for Energy Smart funding, take effect (estimated to be August 2019). In December 2017 the City Council approved an energy efficiency cost recovery rider as an interim funding mechanism for Energy Smart, subject to verification that no additional funding sources exist. In June 2018 the City Council also approved a resolution recommending that Entergy New Orleans allocate approximately $13.5 million of benefits resulting from the Tax Act to Energy Smart. Entergy New Orleans is seeking approval of a permanent and stable source of funding for Energy Smart as part of its base rate case filed in September 2018.

In September 2018, Entergy New Orleans filed an electric and gas base rate case with the City Council. The filing requests 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 requests 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 includes a proposed gas rate decrease of $142 thousand. Entergy New Orleans’s rates reflect 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 ending 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’s request for a change in rates is based on the projected twelve months ending December 31, 2018.

The filing’s major provisions include: (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 have recommended, among other things, overall rate reductions of approximately $33 million in electric rates and $3.8 million in gas rates. Certain intervenors have recommended overall rate reductions of up to approximately $49 million in electric rates and $5 million in gas rates. The procedural schedule calls for an evidentiary hearing to be held in June 2019.

Internal Restructuring

In July 2016, Entergy New Orleans filed an application with the City Council seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy New Orleans, Inc. to a new entity, which would ultimately be owned by an existing Entergy subsidiary holding company. In May 2017 the City Council adopted a resolution approving the proposed internal restructuring pursuant to an agreement in principle with the City Council advisors and certain intervenors. Pursuant to the agreement in principle, Entergy New Orleans would credit retail customers $10 million in 2017, $1.4 million in the first quarter of the year after the transaction closes, and $117,500 each month in the second year after the transaction closes until such time as new base rates go into effect as a result of the then-anticipated 2018 base rate case (which has subsequently been filed). Entergy New Orleans began crediting retail customers in June 2017. In June 2017 the FERC approved the transaction and, pursuant to the agreement in principle, Entergy New Orleans will provide additional credits to retail customers of $5 million in each of the years 2018, 2019, and 2020.

In November 2017, Entergy New Orleans undertook a multi-step restructuring, including the following:

• Entergy New Orleans, Inc. redeemed its outstanding preferred stock at a price of approximately $21 million, which included a call premium of approximately $819,000, plus any accumulated and unpaid dividends.

• Entergy New Orleans, Inc. converted from a Louisiana corporation to a Texas corporation.

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

• Entergy New Orleans, Inc. contributed the membership interests in Entergy New Orleans 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 New Orleans Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.

In December 2017, Entergy New Orleans, Inc. changed its name to Entergy Utility Group, Inc., and Entergy New Orleans Power then changed its name to Entergy New Orleans, LLC. Entergy New Orleans, LLC holds substantially all of the assets, and has assumed substantially all of the liabilities, of Entergy New Orleans, Inc. The restructuring was accounted for as a transaction between entities under common control.

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 electricity 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), 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 June 2017, Entergy Texas filed an application to amend its DCRF rider by increasing the total collection from $8.65 million to approximately $19 million. In July 2017, Entergy Texas, the PUCT staff, and the two other parties in the proceeding entered into an unopposed stipulation and settlement agreement resulting in an amended DCRF annual revenue requirement of $18.3 million. In September 2017 the PUCT issued its final order approving the unopposed stipulation and settlement agreement. The amended DCRF rider rates became effective for usage on and after September 1, 2017. DCRF rates were set to zero upon implementation of new base rates on October 17, 2018, as described above in the discussion of the 2018 base rate case.

Transmission Cost Recovery Factor (TCRF) Rider

In September 2015, Entergy Texas filed for a TCRF rider requesting a $13 million increase, incremental to base rates. Testimony was filed in November 2015, with the PUCT staff and other parties proposing various disallowances involving, among other things, MISO charges, vegetation management costs, and bad debt expenses that would reduce the requested increase by approximately $2 million. In addition to those recommended disallowances, a number of parties recommended that Entergy Texas’s request be reduced by an additional $3.4 million to account for load growth since base rates were last set. In February 2016 a State Office of Administrative Hearings ALJ issued a proposal for decision recommending that the PUCT disallow approximately $2 million from Entergy Texas’s $13 million request, but recommending that the PUCT not accept the load growth offset. In June 2016 the PUCT indicated that it would take up in a future rulemaking project the issue of whether a load growth adjustment should apply to a TCRF. In July 2016 the PUCT issued an order generally accepting the proposal for decision but declining to adjust the TCRF baseline in two instances as recommended by the ALJ, which resulted in a total annual allowance of approximately $10.5 million. The PUCT also ordered its staff and Entergy Texas to track all spare autotransformer transfers going forward so that it could address the appropriate accounting treatment and prudence of such transfers in Entergy Texas’s next base rate case. Entergy Texas implemented the TCRF rider beginning with September 2016 bills.

In September 2016, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The proposed amended TCRF rider was designed to collect approximately $29.5 million annually from Entergy Texas’s retail customers. This amount included the approximately $10.5 million annually that Entergy Texas was previously authorized to collect through the TCRF rider, as discussed above. In December 2016, concurrent with the 2016 fuel reconciliation stipulation and settlement agreement discussed above, Entergy Texas and the PUCT staff reached a settlement agreeing to the amended TCRF annual revenue requirement of $29.5 million. As discussed above, the terms of the two settlements are interdependent. The PUCT approved the settlement and issued a final order in March 2017. Entergy Texas implemented the amended TCRF rider beginning with bills covering usage on and after March 20, 2017. TCRF rates were set to zero upon implementation of new base rates on October 17, 2018, as described above in the 2018 base rate case discussion.

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. The proceeding is currently ongoing at the PUCT.

Advanced Metering Infrastructure (AMI) Filings

Entergy Arkansas

In September 2016, Entergy Arkansas filed an application seeking a finding from the APSC that Entergy Arkansas’s deployment of AMI is in the public interest. Entergy Arkansas proposed to replace existing meters with advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Arkansas’s modernized power grid. The filing included an estimate of implementation costs for AMI of $208 million. The filing identified a number of quantified and unquantified benefits, and Entergy Arkansas provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal net benefit to customers of $406 million. Entergy Arkansas also sought to continue to include in rate base the remaining book value of existing meters, which was approximately $57 million at December 31, 2015, that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Arkansas proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Deployment of the communications network began in 2018. Entergy Arkansas proposed to include the AMI deployment costs and the quantified benefits in future formula rate plan filings, and the 2018 costs were approved in the 2017 formula rate plan filing. In August 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement. In October 2017 the APSC issued an order finding that Entergy Arkansas’s AMI deployment is in the public interest and approving the settlement agreement subject to a minor modification. Entergy Arkansas expects to recover the undepreciated balance of its existing meters through a regulatory asset to be amortized over 15 years.

Entergy Louisiana

In November 2016, Entergy Louisiana filed an application seeking a finding from the LPSC that Entergy Louisiana’s deployment of advanced electric and gas metering infrastructure is in the public interest. Entergy Louisiana proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Louisiana’s modernized power grid. The filing included an estimate of implementation costs for AMI of $330 million. The filing identified a number of quantified and unquantified benefits, and Entergy Louisiana provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $607 million. Entergy Louisiana also sought to continue to include in rate base the remaining book value, approximately $92 million at December 31, 2015, of the existing electric meters and also to depreciate those assets using current depreciation rates. Entergy Louisiana proposed a 15-year useful life for the new advanced meters, the three-year deployment of which began in 2019. Deployment of the communications network began in 2018. Entergy Louisiana proposed to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022. The parties reached an uncontested stipulation permitting implementation of Entergy Louisiana’s proposed AMI system, with modifications to the proposed customer charge. In July 2017 the LPSC approved the stipulation. Entergy Louisiana expects to recover the undepreciated balance of its existing meters through a regulatory asset to be amortized at current depreciation rates.

Entergy Mississippi

In November 2016, Entergy Mississippi filed an application seeking an order from the MPSC granting a certificate of public convenience and necessity and finding that Entergy Mississippi’s deployment of AMI is in the public interest. Entergy Mississippi proposed to replace existing meters with advanced meters that enable two-way data communication; to design and build a secure and reliable network to support such communications; and to implement support systems. AMI is intended to serve as the foundation of Entergy Mississippi’s modernized power grid. The filing included an estimate of implementation costs for AMI of $132 million. The filing identified a number of quantified and unquantified benefits, and Entergy Mississippi provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal benefit to customers of $496 million over a 15-year period, which when netted against the costs of AMI results in $183 million of net customer benefits. Entergy Mississippi also sought to continue to include in rate base the remaining book value, approximately $56 million at December 31, 2015, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Mississippi proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019, subject to approval by the MPSC. Deployment of the communications network began in 2018. Entergy Mississippi proposed to include the AMI deployment costs and the quantified benefits in existing rate mechanisms, primarily through future formula rate plan filings and/or future energy cost recovery rider schedule re-determinations, as applicable. In May 2017 the Mississippi Public Utilities Staff and Entergy Mississippi entered into and filed a joint stipulation supporting Entergy Mississippi’s filing, and the MPSC issued an order approving the filing without material changes, finding that Entergy Mississippi’s deployment of AMI is in the public interest and granting a certificate of public convenience and necessity. The MPSC order also confirmed that Entergy Mississippi shall continue to include in rate base the remaining book value of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. In June 2018, as part of the order approving the joint stipulation between the Mississippi Public Utilities Staff and Entergy Mississippi addressing Entergy Mississippi’s 2018 formula rate plan evaluation report and the ratemaking effects of the Tax Act, the MPSC approved the acceleration of the recovery of substantially all of Entergy Mississippi’s existing customer meters in anticipation of AMI deployment.

Entergy New Orleans

In October 2016, Entergy New Orleans filed an application seeking a finding from the City Council that Entergy New Orleans’s deployment of advanced electric and gas metering infrastructure is in the public interest.  Entergy New Orleans proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems.  AMI is intended to serve as the foundation of Entergy New Orleans’s modernized power grid.  The filing included an estimate of implementation costs for AMI of $75 million. The filing identified a number of quantified and unquantified benefits, and Entergy New Orleans provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $101 million.  Entergy New Orleans also sought to continue to include in rate base the remaining book value, approximately $21 million at December 31, 2015, of the existing electric meters and also to depreciate those assets using current depreciation rates.  Entergy New Orleans proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which began in 2019.  Deployment of the information technology infrastructure began in 2017 and deployment of the communications network began in 2018.  Entergy New Orleans proposed to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022.  The City Council’s advisors filed testimony in May 2017 recommending the adoption of AMI subject to certain modifications, including the denial of Entergy New Orleans’s proposed customer charge as a cost recovery mechanism. In January 2018 a settlement was reached between the City Council’s advisors and Entergy New Orleans. In February 2018 the City Council approved the settlement, which deferred cost recovery to the 2018 Entergy New Orleans rate case, but also stated that an adjustment for 2018-2019 AMI costs can be filed in the rate case and that, for all subsequent AMI costs, the mechanism to be approved in the 2018 rate case will allow for the timely recovery of such costs. In April 2018 the City Council adopted a resolution directing Entergy New Orleans to explore the options for accelerating the deployment of AMI. In June 2018 the City Council approved a one-year acceleration of AMI in its service area for an incremental $4.4 million.

Entergy Texas

In April 2017 the Texas legislature enacted legislation that extends statutory support for AMI deployment to Entergy Texas and directs that if Entergy Texas elects to deploy AMI, it shall do so as rapidly as practicable. In July 2017, Entergy Texas filed an application seeking an order from the PUCT approving Entergy Texas’s deployment of AMI. Entergy Texas proposed to replace existing meters with advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Texas’s modernized power grid. The filing included an estimate of implementation costs for AMI of $132 million. The filing identified a number of quantified and unquantified benefits, with Entergy Texas showing that its AMI deployment is expected to produce nominal net operational cost savings to customers of $33 million. Entergy Texas also sought to continue to include in rate base the remaining book value, approximately $41 million at December 31, 2016, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Texas proposed a seven-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Entergy Texas also proposed a surcharge tariff to recover the reasonable and necessary costs it has and will incur under the deployment plan for the full deployment of advanced meters. Further, Entergy Texas sought approval of fees that would be charged to customers who choose to opt out of receiving service through an advanced meter and instead receive electric service with a non-standard meter. In October 2017, Entergy Texas and other parties entered into and filed an unopposed stipulation and settlement agreement, permitting deployment of AMI with limited modifications. The PUCT approved the stipulation and settlement agreement in December 2017. Entergy Texas implemented the AMI surcharge tariff beginning with January 2018 bills. As of December 31, 2018, Entergy Texas has a regulatory liability related to the collection of the surcharge from customers. Consistent with the approval, deployment of the communications network began in 2018 and deployment of the advanced meters will begin in March 2019. Entergy Texas expects to recover the remaining net book value of its existing meters through a regulatory asset to be amortized at current depreciation rates.

System Agreement Cost Equalization Proceedings

Prior to its final termination in 2016, the Utility operating companies historically engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement.  Entergy Arkansas terminated its participation in the System Agreement in December 2013. Entergy Mississippi terminated its participation in the System Agreement in November 2015. The System Agreement terminated with respect to its remaining participants in August 2016.

Although the System Agreement has terminated, certain of the Utility operating companies’ retail regulators continue to pursue litigation involving the System Agreement at the FERC and in federal courts.  The proceedings include challenges to the allocation of costs as defined by the System Agreement and other matters.

In June 2005 the FERC issued a decision in System Agreement litigation that had been commenced by the LPSC, and essentially affirmed its decision in a December 2005 order on rehearing.  The decision included, among other things:

• The FERC’s conclusion that the System Agreement no longer roughly equalized total production costs among the Utility operating companies.

• In order to reach rough production cost equalization, the FERC imposed a bandwidth remedy by which each company’s total annual production costs would have to be within +/- 11% of Entergy System average total annual production costs.

• In calculating the production costs for this purpose under the FERC’s order, output from the Vidalia hydroelectric power plant would not reflect the actual Vidalia price for the year but be priced at that year’s average price paid by Entergy Louisiana for the exchange of electric energy under Service Schedule MSS-3 of the System Agreement, thereby reducing the amount of Vidalia costs reflected in the comparison of the Utility operating companies’ total production costs.

• The remedy ordered by the FERC in 2005 required no refunds and became effective based on calendar year 2006 production costs with the first reallocation payments made in 2007.

The FERC’s decision reallocated total production costs of the Utility operating companies whose relative total production costs expressed as a percentage of Entergy System average production costs are outside an upper or lower bandwidth.  This was accomplished by payments from Utility operating companies whose production costs were more than 11% below Entergy System average production costs to Utility operating companies whose production costs were more than the Entergy System average production cost, with payments going first to those Utility operating companies whose total production costs were farthest above the Entergy System average.

The LPSC, APSC, MPSC, and the Arkansas Electric Energy Consumers appealed the FERC’s December 2005 decision to the United States Court of Appeals for the D.C. Circuit.  Entergy and the City of New Orleans intervened in the various appeals.  The D.C. Circuit issued its decision in April 2008.  The D.C. Circuit concluded that the FERC’s orders had failed to adequately explain both its conclusion that it was prohibited from ordering refunds for the 20-month period from September 13, 2001 - May 2, 2003 and its determination to implement the bandwidth remedy commencing on January 1, 2006, rather than June 1, 2005.  The D.C. Circuit remanded the case to the FERC for further proceedings on those two issues.

In October 2011 the FERC issued an order addressing the D.C. Circuit remand on the two issues.  On the first issue, the FERC concluded that it did have the authority to order refunds, but decided that it would exercise its equitable discretion and not require refunds for the 20-month period from September 13, 2001 - May 2, 2003.  Because the ruling on refunds relied on findings in the interruptible load proceeding, which is discussed in a separate section below, the FERC concluded that this refund ruling will be held in abeyance pending the outcome of the rehearing requests in the interruptible load proceeding.  On the second issue, the FERC reversed its prior decision and ordered that the prospective bandwidth remedy begin on June 1, 2005 (the date of its initial order in the proceeding) rather than January 1, 2006, as it had previously ordered.  Pursuant to the October 2011 order, Entergy was required to calculate bandwidth payments for the period June - December 2005 utilizing the bandwidth formula tariff prescribed by the FERC that was filed in a December 2006 compliance filing and accepted by the FERC in an April 2007 order.  

In March 2015, in light of a December 2014 decision by the D.C. Circuit in the interruptible load proceeding, Entergy filed with the FERC a motion to establish a briefing schedule on refund issues and an initial brief addressing refund issues. The initial brief argued that the FERC, in response to the D.C. Circuit decision, should clarify its policy on refunds and find that refunds are not required in this proceeding. In October 2015 the FERC issued three orders related to the commencement of the remedy on June 1, 2005 and the inclusion of interest for the period June 1, 2005 through December 31, 2005. Specifically, the FERC rejected Entergy’s request for rehearing of its decision to include interest for the seven-month period. The FERC also rejected Entergy’s request for rehearing of the order rejecting the compliance filing with regard to the issue of interest. Finally, the FERC set for hearing and settlement procedures the 2014 compliance filing that included the bandwidth calculation for the seven months June 1, 2005 through December 31, 2005. In setting the compliance filing for hearing, the FERC rejected the APSC’s protest that Entergy Arkansas should not be subject to the filing because Entergy Arkansas would be making the payments during a period following its exit from the System Agreement. In January 2018 the D.C. Circuit affirmed the FERC decision that Entergy Arkansas was subject to the filing.

In December 2011, Entergy filed with the FERC its compliance filing that provided the payments and receipts among the Utility operating companies pursuant to the FERC’s October 2011 order.  The APSC, the LPSC, the PUCT, and other parties intervened in the December 2011 compliance filing proceeding, and the APSC and the LPSC also filed protests. The filing showed the following payments/receipts among the Utility operating companies:

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$156
Entergy Louisiana	($75)
Entergy Mississippi	($33)
Entergy New Orleans	($5)
Entergy Texas	($43)

Entergy Arkansas made its payment in January 2012.  In February 2012, Entergy Arkansas filed for an interim adjustment to its production cost allocation rider requesting that the $156 million be collected from customers over the 22-month period from March 2012 through December 2013.  In March 2012 the APSC issued an order stating that the payment can be recovered from retail customers through the production cost allocation rider, subject to refund.  The LPSC and the APSC requested rehearing of the FERC’s October 2011 order.  

In February 2014 the FERC issued a rehearing order addressing its October 2011 order. The FERC denied the LPSC’s request for rehearing on the issues of whether the bandwidth remedy should be made effective earlier than June 1, 2005, and whether refunds should be ordered for the 20-month refund effective period. The FERC granted the LPSC’s rehearing request on the issue of interest on the bandwidth payments/receipts for the June - December 2005 period, requiring that interest be accrued from June 1, 2006 until the date those bandwidth payments/receipts are made. Also in February 2014 the FERC issued an order rejecting the December 2011 compliance filing that calculated the bandwidth payments/receipts for the June - December 2005 period. The FERC order required a new compliance filing that calculates the bandwidth payments/receipts for the June - December 2005 period based on monthly data for the seven individual months including interest pursuant to the February 2014 rehearing order. Entergy sought rehearing of the February 2014 order with respect to the FERC’s determinations regarding interest. In April 2014 the LPSC filed a petition for review of the FERC’s October 2011 and February 2014 orders with the U.S. Court of Appeals for the D.C. Circuit. In August 2017 the D.C. Circuit issued a decision denying the LPSC’s appeal of the FERC’s October 2011 and February 2014 orders. On the issue of the FERC’s implementation of the prospective remedy as of June 2005 and whether the bandwidth remedy should be extended for an additional 17 months in years 2004-2005, the D.C. Circuit affirmed the FERC’s implementation of the remedy and denied the LPSC’s appeal. On the issue of whether the operating companies should be required to issue refunds for the 20-month period from September 2001 to May 2003, the D.C. Circuit granted the FERC’s request for agency reconsideration and remanded that issue back to the FERC for further proceedings as requested by all parties to the appeal. In response to the D.C. Circuit’s remand, various parties filed briefs with the FERC addressing whether the FERC should require the Utility operating companies to issue refunds for the 20-month refund period from September 2001 to May 2003. The LPSC has argued in favor of such remands and Entergy has opposed the LPSC’s request. The briefing was completed in September 2018 and the matter is pending before the FERC.

In April and May 2014, Entergy filed with the FERC an updated compliance filing that provided the payments and receipts among the Utility operating companies pursuant to the FERC’s February 2014 orders.  The filing showed the following net payments and receipts, including interest, among the Utility operating companies:

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$68
Entergy Louisiana	($10)
Entergy Mississippi	($11)
Entergy New Orleans	$2
Entergy Texas	($49)

These payments were made in May 2014. The LPSC, City Council, and APSC filed protests.

The hearing on the bandwidth calculation for the seven months June 1, 2005 through December 31, 2005 occurred in July 2016. The presiding judge issued an initial decision in November 2016. In the initial decision, the presiding judge agreed with the Utility operating companies’ position that: (1) interest on the bandwidth payments for the 2005 test period should be accrued from June 1, 2006 until the date that the bandwidth payments for that calculation are paid, which is consistent with how the Utility operating companies performed the calculation; and (2) a portion of Entergy Louisiana’s 2001-vintage Louisiana state net operating loss accumulated deferred income tax that results from the Vidalia tax deduction should be excluded from the 2005 test period bandwidth calculation. Various participants filed briefs on exceptions and/or briefs opposing exceptions related to the initial decision, including the LPSC, the APSC, the FERC trial staff, and Entergy Services. In May 2018 the FERC issued an order affirming the initial decision and ordered a comprehensive recalculation of the bandwidth payments/receipts for the seven months June 1, 2005 through December 31, 2005 and a recalculation of the 2006 and 2007 test years as a result of limited revisions. Entergy filed the comprehensive recalculation of the bandwidth payments/receipts for the seven months June 1, 2005 through December 31, 2005 and the 2006 and 2007 test years in July 2018. The filing shows the additional following payments and receipts among the Utility operating companies:

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	($4)
Entergy Louisiana	($23)
Entergy Mississippi	$16
Entergy New Orleans	$5
Entergy Texas	$6

These payments were made in July 2018. In January 2019 the FERC denied the LPSC’s request for rehearing of the May 2018 order.

Rough Production Cost Equalization Rates

Each May from 2007 through 2016 Entergy filed with the FERC the rates to implement the FERC’s orders in the System Agreement proceeding.  These filings showed the following payments/receipts among the Utility operating companies were necessary to achieve rough production cost equalization as defined by the FERC’s orders:

	Payments (Receipts)
	2007			2008			2009			2010			2011			2012			2013			2014
	(In Millions)
Entergy Arkansas		$252			$252			$390			$41			$77			$41			$—			$—
Entergy Louisiana		($211	)		($160	)		($247	)		($22	)		($12	)		($41	)		$—			$—
Entergy Mississippi		($41	)		($20	)		($24	)		($19	)		($40	)		$—			$—			$—
Entergy New Orleans		$—			($7	)		$—			$—			($25	)		$—			($15	)		($15	)
Entergy Texas		($30	)		($65	)		($119	)		$—			$—			$—			$15			$15

The Utility operating companies recorded accounts payable or accounts receivable to reflect the rough production cost equalization payments and receipts required to implement the FERC’s remedy.  When accounts payable were recorded, a corresponding regulatory asset was recorded for the right to collect the payments from customers. When accounts receivable were recorded, a corresponding regulatory liability was recorded for the obligations to pass the receipts on to customers.  No payments were required in 2016 or 2015 to implement the FERC’s remedy based on calendar year 2015 production costs and 2014 production costs, respectively. The System Agreement terminated in August 2016.

The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas.  Entergy Texas recovered its 2013 rough production cost equalization payment over three years beginning April 2014. Entergy Texas included its 2014 rough production cost equalization payment as a component of an interim fuel refund made in 2014. Management believes that any changes in the allocation of production costs resulting from the FERC’s decision and related retail proceedings should result in similar rate changes for retail customers, subject to specific circumstances that have caused trapped costs.

The following rough production cost equalization rate proceedings are still ongoing or were ongoing during the period 2016-2018.

2010 Rate Filing Based on Calendar Year 2009 Production Costs

In May 2010, Entergy filed with the FERC the 2010 rates in accordance with the FERC’s orders in the System Agreement proceeding, and supplemented the filing in September 2010.  Several parties intervened in the proceeding at the FERC, including the LPSC and the City Council, which also filed protests.  In July 2010 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2010, subject to refund.  After an abeyance of the proceeding schedule, a hearing was held in March 2014 and in December 2015 the FERC issued an order. Among other things, the December 2015 order directed Entergy to submit a compliance filing. In January 2016 the LPSC, the APSC, and Entergy filed requests for rehearing of the FERC’s December 2015 order. In February 2016, Entergy submitted the compliance filing ordered in the December 2015 order.  The result of the true-up payments and receipts for the recalculation of production costs resulted in the following payments/receipts among the Utility operating companies:

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$2
Entergy Louisiana	$6
Entergy Mississippi	($4)
Entergy New Orleans	($1)
Entergy Texas	($3)

In September 2016 the FERC accepted the February 2016 compliance filing subject to a further compliance filing made in November 2016. The further compliance filing was required as a result of an order issued in September 2016 ruling on the January 2016 rehearing requests filed by the LPSC, the APSC, and Entergy. In the order addressing the rehearing requests, the FERC granted the LPSC’s rehearing request and directed that interest be calculated on the payment/receipt amounts. The FERC also granted the APSC’s and Entergy’s rehearing request and ordered the removal of both securitized asset accumulated deferred income taxes and contra-securitization accumulated deferred income taxes from the calculation. In November 2016, Entergy submitted its compliance filing in response to the FERC’s order on rehearing. The compliance filing included a revised calculation of the bandwidth true-up payments and receipts based on 2009 test year data and interest calculations. The LPSC protested the interest calculations. In November 2017 the FERC issued an order rejecting the November 2016 compliance filing. The FERC determined that the payments detailed in the November 2016 compliance filing did not include adequate interest for the payments from Entergy Arkansas to Entergy Louisiana because it did not include interest on the principal portion of the payment that was made in February 2016. In December 2017, Entergy recalculated the interest pursuant to the November 2017 order. As a result of the recalculations, Entergy Arkansas owed very minor payments to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.

2011 Rate Filing Based on Calendar Year 2010 Production Costs

In May 2011, Entergy filed with the FERC the 2011 rates in accordance with the FERC’s orders in the System Agreement proceeding.  Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest.  In July 2011 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2011, subject to refund. After an abeyance of the proceeding schedule, in December 2014 the FERC consolidated the 2011 rate filing with the 2012, 2013, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

2012 Rate Filing Based on Calendar Year 2011 Production Costs

In May 2012, Entergy filed with the FERC the 2012 rates in accordance with the FERC’s orders in the System Agreement proceeding.  Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest.  In August 2012 the FERC accepted Entergy’s proposed rates for filing, effective June 2012, subject to refund. After an abeyance of the proceeding schedule, in December 2014 the FERC consolidated the 2012 rate filing with the 2011, 2013, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

2013 Rate Filing Based on Calendar Year 2012 Production Costs

In May 2013, Entergy filed with the FERC the 2013 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest. The City Council intervened and filed comments related to including the outcome of a related FERC proceeding in the 2013 cost equalization calculation. In August 2013 the FERC issued an order accepting the 2013 rates, effective June 1, 2013, subject to refund. After an abeyance of the proceeding schedule, in December 2014 the FERC consolidated the 2013 rate filing with the 2011, 2012, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

2014 Rate Filing Based on Calendar Year 2013 Production Costs

In May 2014, Entergy filed with the FERC the 2014 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest. The City Council intervened and filed comments. In December 2014 the FERC issued an order accepting the 2014 rates, effective June 1, 2014, subject to refund, set the proceeding for hearing procedures, and consolidated the 2014 rate filing with the 2011, 2012, and 2013 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

Consolidated 2011, 2012, 2013, and 2014 Rate Filing Proceedings

As discussed above, in December 2014 the FERC consolidated the 2011, 2012, 2013, and 2014 rate filings for settlement and hearing procedures. In May 2015, Entergy filed direct testimony in the consolidated rate filings and the LPSC filed direct testimony concerning its complaint proceeding that is consolidated with the rate filings, challenging certain components of the pending bandwidth calculations for prior years. Hearings occurred in November 2015, and the ALJ issued an initial decision in July 2016. In the initial decision, the ALJ generally agreed with Entergy’s bandwidth calculations with one exception on the accounting related to the Waterford 3 sale/leaseback. In March 2018 the FERC issued an order affirming the initial decision. In April 2018 the LPSC requested rehearing of the FERC’s March 2018 order affirming the ALJ’s initial decision. Entergy filed in May 2018 the bandwidth true-up payments and receipts for the 2011-2014 rate filings (table does not net to zero due to rounding):

	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$3
Entergy Louisiana	$3
Entergy Mississippi	($1)
Entergy New Orleans	$1
Entergy Texas	($5)

These payments were made in May 2018. The LPSC request for rehearing is pending.

Utility Operating Company Termination of System Agreement Participation

Entergy Arkansas and Entergy Mississippi ceased participating in the System Agreement effective December 18, 2013 and November 7, 2015, respectively. Entergy Louisiana, Entergy New Orleans, and Entergy Texas terminated participation in the System Agreement on August 31, 2016, which resulted in the termination of the System Agreement in its entirety pursuant to a settlement agreement approved by the FERC in December 2015.

In December 2013 the FERC set one issue for hearing involving whether and how the benefits associated with settlement with Union Pacific regarding certain coal delivery issues should be allocated among Entergy Arkansas and the other Utility operating companies post-termination of the System Agreement. In December 2014 a FERC ALJ issued an initial decision finding that Entergy Arkansas would realize benefits after December 18, 2013 from the 2008 settlement agreement between Entergy Services, Entergy Arkansas, and Union Pacific, related to certain coal delivery issues. In March 2016 the FERC issued an opinion affirming the December 2014 initial decision with regard to the determination that there were benefits related to the Union Pacific settlement, which were realized post-Entergy Arkansas’s December 2013 withdrawal from the System Agreement, that should be shared with the other Utility operating companies utilizing the methodology proposed by the MPSC and trued-up to actual coal volumes purchased. In May 2016, Entergy made a compliance filing that provided the calculation of Union Pacific settlement benefits utilizing the methodology adopted by the initial decision, trued-up for the actual volumes of coal purchased. The payments were made in May 2016. In August 2016 the FERC issued an order accepting Entergy’s compliance filing. Also in August 2016 the APSC filed a petition for review of the FERC’s March 2016 and August 2016 orders with the U.S. Court of Appeals for the D.C. Circuit. In June 2018 the D.C. Circuit denied the APSC’s petition.

Interruptible Load Proceeding

In April 2007 the U.S. Court of Appeals for the D.C. Circuit issued its opinion in the LPSC’s appeal of the FERC’s March 2004 and April 2005 orders related to the treatment under the System Agreement of the Utility operating companies’ interruptible loads.  In its opinion the D.C. Circuit concluded that the FERC: (1) acted arbitrarily and capriciously by allowing the Utility operating companies to phase-in the effects of the elimination of the interruptible load over a 12-month period of time; (2) failed to adequately explain why refunds could not be ordered under Section 206(c) of the Federal Power Act; and (3) exercised appropriately its discretion to defer addressing the cost of sulfur dioxide allowances until a later time.  The D.C. Circuit remanded the matter to the FERC for a more considered determination on the issue of refunds.  The FERC issued its order on remand in September 2007, in which it directed Entergy to make a compliance filing removing all interruptible load from the computation of peak load responsibility commencing April 1, 2004 and to issue any necessary refunds to reflect this change.  In addition, the order directed the Utility operating companies to make refunds for the period May 1995 through July 1996.  In November 2007 the Utility operating companies filed a refund report describing the refunds to be issued pursuant to the FERC’s orders.  The LPSC filed a protest to the refund report in December 2007.  The refunds were made in October 2008 by the Utility operating companies that owed refunds to the Utility operating companies that were due refunds under the decision.  The APSC and the Utility operating companies appealed the FERC decisions to the D.C. Circuit.

Following the filing of petitioners’ initial briefs, the FERC filed a motion requesting the D.C. Circuit hold the appeal of the FERC’s decisions ordering refunds in the interruptible load proceeding in abeyance and remand the record to the FERC.  The D.C. Circuit granted the FERC’s unopposed motion in June 2009.  In December 2009 the FERC established a paper hearing to determine whether the FERC had the authority and, if so, whether it would be appropriate to order refunds resulting from changes in the treatment of interruptible load in the allocation of capacity costs by the Utility operating companies.  In August 2010 the FERC issued an order stating that it has the authority and refunds are appropriate.  The APSC, the MPSC, and Entergy requested rehearing of the FERC’s decision.  In June 2011 the FERC issued an order granting rehearing in part and denying rehearing in part, in which the FERC determined to invoke its discretion to deny refunds.  The FERC held that in this case where “the Entergy system as a whole collected the proper level of revenue, but, as was later established, incorrectly allocated peak load responsibility among the various Entergy operating companies….the Commission will apply here our usual practice in such cases, invoking our equitable discretion to not order refunds, notwithstanding our authority to do so.”  The LPSC requested rehearing of the FERC’s June 2011 decision.  In July 2011 the refunds made in the fourth quarter 2008 described above were reversed. In October 2011 the FERC issued an “Order Establishing Paper Hearing” inviting parties that oppose refunds to file briefs within 30 days addressing the LPSC’s argument that FERC precedent supports refunds under the circumstances present in this proceeding.  Parties that favor refunds were then invited to file reply briefs within 21 days of the date that the initial briefs were due.  

In March 2013 the FERC issued an order denying the LPSC’s request for rehearing of the FERC’s June 2011 order wherein the FERC concluded it would exercise its discretion and not order refunds in the interruptible load proceeding. Based on its review of the LPSC’s request for rehearing and the briefs filed as part of the paper hearing established in October 2011, the FERC affirmed its earlier ruling and declined to order refunds under the circumstances of the case. In May 2013 the LPSC filed a petition for review with the U.S. Court of Appeals for the D.C. Circuit seeking review of FERC orders in the interruptible load proceeding that concluded that the FERC would exercise its discretion and not order refunds in the proceeding. Oral argument was held on the appeal in the D.C. Circuit in September 2014. In December 2014 the D.C. Circuit issued an order on the LPSC’s appeal and remanded the case back to the FERC. The D.C. Circuit rejected the LPSC’s argument that there is a presumption in favor of refunds, but it held that the FERC had not adequately explained its decision to deny refunds and directed the FERC “to consider the relevant factors and weigh them against one another.” In March 2015, Entergy filed with the FERC an initial brief on remand to address the December 2014 decision by the D.C. Circuit. The initial brief on remand argued that the FERC, in response to the D.C. Circuit decision, should clarify its policy on refunds and find that refunds are not required in the interruptible load proceeding.

In April 2016 the FERC issued an order on remand that addressed the December 2014 decision by the D.C. Circuit in the interruptible load proceeding. The order on remand affirmed the FERC’s denial of refunds for the 15-month refund effective period. The FERC explained and clarified its policies regarding refunds and concluded that the evidence in the record demonstrated that the relevant equitable factors favored not requiring refunds in this case. The FERC also noted that, under Section 206(c) of the Federal Power Act, in a Section 206 proceeding involving two or more electric utility companies of a registered holding company system, the FERC may order refunds only if it determines the refunds would not cause the registered holding company to experience any reduction in revenues resulting from an inability of an electric utility company in the system to recover the resulting increase in costs. The FERC stated it was not able to find that the Entergy system would not experience a reduction in revenues if refunds were awarded in this proceeding, which further supported the denial of refunds. In May 2016 the LPSC filed a request for rehearing of the FERC’s April 2016 order. In September 2016 the FERC issued an order denying the LPSC’s request for rehearing and reaffirming its denial of refunds for the 15-month refund effective period. The LPSC appealed the April and September 2016 orders to the U.S. Court of Appeals for the D.C. Circuit. In March 2018 the D.C. Circuit issued an order denying the LPSC’s appeal and affirming the FERC’s decision that it would be inequitable to award refunds in the proceeding. In April 2018 the LPSC sought rehearing en banc of the D.C. Circuit’s order denying the LPSC’s appeal. In May 2018 the D.C. Circuit denied the LPSC’s rehearing request. In August 2018 the LPSC filed with the Supreme Court of the United States a petition for a writ of certiorari to review the judgment of the D.C. Circuit. In November 2018 the Supreme Court of the United States denied the LPSC’s petition for a writ of certiorari to review the judgment of the D.C. Circuit, effectively terminating the interruptible load proceeding.

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’s 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’s appeal and held all of the appeals in abeyance pending final resolution of the related proceeding before the FERC.

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 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. 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.

Complaints Against System Energy

Return on Equity 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 the FERC to institute 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. System Energy is recording a provision against revenue for the potential outcome of this proceeding. In September 2017 the FERC established a refund effective date of January 23, 2017, consolidated the return on equity complaint with the proceeding described in Unit Power Sales Agreement below, 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 effective date 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 System Energy’s return on equity, with a refund effective date of April 2018. The portion of the LPSC’s complaint dealing with return on equity was subsequently consolidated with the APSC and MPSC complaint for hearing. The consolidated hearing has been scheduled for September 2019, and the parties are required to address 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 complaint, and System Energy submitted a response to the amended complaint in October 2018. In January 2019 the FERC set the amended complaint for settlement and hearing proceedings.

Grand Gulf Sale-leaseback Renewal Complaint

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 2018. The hearing has been scheduled for November 2019.

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 proposed amendments would result in lower charges to the Utility operating companies that buy capacity and energy from System Energy under the Unit Power Sales Agreement. The proposed changes are 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. System Energy requested that the FERC accept the amendments effective October 1, 2017.

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 propose 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. The FERC also consolidated the Unit Power Sales Agreement amendment proceeding with the proceeding described in“Return on Equity Complaints” above, and directed the parties to engage in settlement proceedings before an ALJ. 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.  The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages.  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.

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.  In February 2012, Entergy Louisiana sold 500,000 of its Class A preferred membership units in Entergy Holdings Company LLC, a wholly-owned Entergy subsidiary, to a third party in exchange for $51 million plus accrued but unpaid distributions on the units.  The 500,000 preferred membership units are mandatorily redeemable in January 2112.

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. As of April 30, 2016, Entergy Mississippi’s storm damage provision balance was less than $10 million, therefore Entergy Mississippi resumed billing the monthly storm damage provision effective with June 2016 bills. As of September 30, 2016, however, Entergy Mississippi’s storm damage provision balance exceeded $15 million. Accordingly the storm damage provision was reset to zero beginning with November 2016 bills. As of July 31, 2017, the balance in Entergy Mississippi’s accumulated storm damage provision was again less than $10 million, therefore Entergy Mississippi resumed billing the monthly storm damage provision effective with September 2017 bills. As of June 30, 2018, Entergy Mississippi’s storm damage provision balance exceeded $15 million. Accordingly the storm damage provision was reset to zero beginning with August 2018 bills.

Entergy New Orleans

In August 2012, Hurricane Isaac caused extensive damage to Entergy New Orleans’s service area. In January 2015 the City Council issued a resolution approving the terms of a joint agreement in principle filed by Entergy New Orleans, Entergy Louisiana, and the City Council Advisors determining, among other things, that Entergy New Orleans’s prudently-incurred storm recovery costs were $49.3 million, of which $31.7 million, net of reimbursements from the storm reserve escrow account, remained recoverable from Entergy New Orleans’s electric customers. The resolution also directed Entergy New Orleans to file an application to securitize the unrecovered City Council-approved storm recovery costs of $31.7 million pursuant to the Louisiana Electric Utility Storm Recovery Securitization Act (Louisiana Act 64). In addition, the resolution found that it was reasonable for Entergy New Orleans to include in the principal amount of its potential securitization the costs to fund and replenish Entergy New Orleans’s storm reserve in an amount that achieved the City Council-approved funding level of $75 million. In January 2015, in compliance with that directive, Entergy New Orleans filed with the City Council an application requesting that the City Council grant a financing order authorizing the financing of Entergy New Orleans’s storm costs, storm reserves, and issuance costs pursuant to Louisiana Act 64. In May 2015 the parties entered into an agreement in principle and the City Council issued a financing order authorizing Entergy New Orleans to issue storm recovery bonds in the aggregate amount of $98.7 million, including $31.8 million for recovery of Entergy New Orleans’s Hurricane Isaac storm recovery costs, including carrying costs, $63.9 million to fund and replenish Entergy New Orleans’s storm reserve, and approximately $3 million for estimated up-front financing costs associated with the securitization. See Note 5 to the financial statements for discussion of the issuance of the securitization bonds in July 2015.

New Nuclear Generation Development Costs

Entergy Louisiana

Entergy Louisiana and Entergy Gulf States Louisiana were developing a project option for new nuclear generation at River Bend.  In March 2010, Entergy Louisiana and Entergy Gulf States Louisiana filed with the LPSC seeking approval to continue the limited development activities necessary to preserve an option to construct a new unit at River Bend.  At its June 2012 meeting the LPSC voted to uphold an ALJ recommendation that the request of Entergy Louisiana and Entergy Gulf States Louisiana be declined on the basis that the LPSC’s rule on new nuclear development does not apply to activities to preserve an option to develop and on the further grounds that the companies improperly engaged in advanced preparation activities prior to certification.  The LPSC directed that Entergy Louisiana and Entergy Gulf States Louisiana be permitted to seek recovery of these costs in their upcoming rate case filings that were subsequently filed in February 2013. In the resolution of the rate case proceeding the LPSC provided for an eight-year amortization of costs incurred in connection with the potential development of new nuclear generation at River Bend, without carrying costs, beginning in December 2014, provided, however, that amortization of these costs shall not result in a future rate increase. As of December 31, 2018, Entergy Louisiana has a regulatory asset of $28.5 million on its balance sheet related to these new nuclear generation development costs.