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•	resolution of pending and future rate cases, formula rate proceedings and related negotiations, including various performance-based rate discussions, Entergy’s utility supply plan, and recovery of fuel and purchased power costs;

•	continuing long-term risks and uncertainties associated with the termination of the System Agreement in 2016, including the potential absence of federal authority to resolve certain issues among the Utility operating companies and their retail regulators;

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regulatory and operating challenges and uncertainties and economic risks associated with the Utility operating companies’ participation in MISO, including the benefits of continued MISO participation, the effect of current or projected MISO market rules and market and system conditions in the MISO markets, the allocation of MISO system transmission upgrade costs, the MISO-wide base rate of return on equity allowed or any MISO-related charges and credits required by the FERC, and the effect of planning decisions that MISO makes with respect to future transmission investments by the Utility operating companies;

•	changes in utility regulation, including with respect to retail and wholesale competition, the ability to recover net utility assets and other potential stranded costs, and the application of more stringent return on equity criteria, transmission reliability requirements or market power criteria by the FERC or the U.S. Department of Justice;

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changes in the regulation or regulatory oversight of Entergy’s nuclear generating facilities and nuclear materials and fuel, including with respect to the planned or actual shutdown and sale of each of the nuclear generating facilities owned or operated by Entergy Wholesale Commodities, and the effects of new or existing safety or environmental concerns regarding nuclear power plants and nuclear fuel;

•	resolution of pending or future applications, and related regulatory proceedings and litigation, for license modifications or other authorizations required of nuclear generating facilities and the effect of public and political opposition on these applications, regulatory proceedings, and litigation;

•	the performance of and deliverability of power from Entergy’s generation resources, including the capacity factors at Entergy’s nuclear generating facilities;

•	increases in costs and capital expenditures that could result from changing regulatory requirements, emerging operating and industry issues, and the commitment of substantial human and capital resources required for the safe and reliable operation and maintenance of Entergy’s nuclear generating facilities;

•	Entergy’s ability to develop and execute on a point of view regarding future prices of electricity, natural gas, and other energy-related commodities;

•	prices for power generated by Entergy’s merchant generating facilities and the ability to hedge, meet credit support requirements for hedges, sell power forward or otherwise reduce the market price risk associated with those facilities, including the Entergy Wholesale Commodities nuclear plants, especially in light of the planned shutdown and sale of each of these nuclear plants;

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•	the prices and availability of fuel and power Entergy must purchase for its Utility customers, and Entergy’s ability to meet credit support requirements for fuel and power supply contracts;

•	volatility and changes in markets for electricity, natural gas, uranium, emissions allowances, and other energy-related commodities, and the effect of those changes on Entergy and its customers;

•	changes in law resulting from federal or state energy legislation or legislation subjecting energy derivatives used in hedging and risk management transactions to governmental regulation;

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changes in environmental laws and regulations, agency positions or associated litigation, including requirements for reduced emissions of sulfur dioxide, nitrogen oxide, greenhouse gases, mercury, particulate matter and other regulated air emissions, heat and other regulated discharges to water, requirements for waste management and disposal and for the remediation of contaminated sites, wetlands protection and permitting, and changes in costs of compliance with environmental laws and regulations;

•	changes in laws and regulations, agency positions, or associated litigation related to protected species and associated critical habitat designations;

•	the effects of changes in federal, state, or local laws and regulations, and other governmental actions or policies, including changes in monetary, fiscal, tax, environmental, trade/tariff, domestic purchase requirements, or energy policies;

•	the effects of full or partial shutdowns of the federal government or delays in obtaining government or regulatory actions or decisions;

•	uncertainty regarding the establishment of interim or permanent sites for spent nuclear fuel and nuclear waste storage and disposal and the level of spent fuel and nuclear waste disposal fees charged by the U.S. government or other providers related to such sites;

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variations in weather and the occurrence of hurricanes and other storms and disasters, including uncertainties associated with efforts to remediate the effects of hurricanes, ice storms, or other weather events and the recovery of costs associated with restoration, including accessing funded storm reserves, federal and local cost recovery mechanisms, securitization, and insurance, as well as any related unplanned outages;

•	the risk that an incident at any nuclear generation facility in the U.S. could lead to the assessment of significant retrospective assessments and/or retrospective insurance premiums as a result of Entergy’s participation in a secondary financial protection system, a utility industry mutual insurance company, and industry self-insurance programs;

•	effects of climate change, including the potential for increases in extreme weather events and sea levels or coastal land and wetland loss;

•	changes in the quality and availability of water supplies and the related regulation of water use and diversion;

•	Entergy’s ability to manage its capital projects, including completion of projects timely and within budget and to obtain the anticipated performance or other benefits, and its operation and maintenance costs;

•	Entergy’s ability to purchase and sell assets at attractive prices and on other attractive terms;

•	the economic climate, and particularly economic conditions in Entergy’s Utility service area and the northern United States and events and circumstances that could influence economic conditions in those areas, including power prices, and the risk that anticipated load growth may not materialize;

•	federal income tax reform, including the Tax Cuts and Jobs Act and its intended and unintended consequences on financial results and future cash flows;

•	the effects of Entergy’s strategies to reduce tax payments, especially in light of federal income tax reform;

•	changes in the financial markets and regulatory requirements for the issuance of securities, particularly as they affect access to capital and Entergy’s ability to refinance existing securities, execute share repurchase programs, and fund investments and acquisitions;

•	actions of rating agencies, including changes in the ratings of debt and preferred stock, changes in general corporate ratings, and changes in the rating agencies’ ratings criteria;

•	changes in inflation and interest rates;

•	the effects of litigation and government investigations or proceedings;

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changes in technology, including (i) Entergy’s ability to implement new or emerging technologies, (ii) the impact of changes relating to new, developing, or alternative sources of generation such as distributed energy and energy storage, renewable energy, energy efficiency, demand side management and other measures that reduce load and government policies incentivizing development of the foregoing, and (iii) competition from other companies offering products and services to Entergy’s customers based on new or emerging technologies or alternative sources of generation;

•	the effects, including increased security costs, of threatened or actual terrorism, cyber-attacks or data security breaches, natural or man-made electromagnetic pulses that affect transmission or generation infrastructure, accidents, and war or a catastrophic event such as a nuclear accident or a natural gas pipeline explosion;

•	Entergy’s ability to attract and retain talented management, directors, and employees with specialized skills;

•	Entergy’s ability to attract, retain and manage an appropriately qualified workforce;

•	changes in accounting standards and corporate governance;

•	declines in the market prices of marketable securities and resulting funding requirements and the effects on benefits costs for Entergy’s defined benefit pension and other postretirement benefit plans;

•	future wage and employee benefit costs, including changes in discount rates and returns on benefit plan assets;

•	changes in decommissioning trust fund values or earnings or in the timing of, requirements for, or cost to decommission Entergy’s nuclear plant sites and the implementation of decommissioning of such sites following shutdown;

•	the decision to cease merchant power generation at all Entergy Wholesale Commodities nuclear power plants by mid-2022, including the implementation of the planned shutdowns and sales of Indian Point 2, Indian Point 3, and Palisades;

•	the effectiveness of Entergy’s risk management policies and procedures and the ability and willingness of its counterparties to satisfy their financial and performance commitments;

•	the potential for the factors listed herein to lead to the impairment of long-lived assets; and

•	Entergy and its subsidiaries’ ability to successfully execute on their business strategies, including their ability to complete strategic transactions that Entergy may undertake.

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•	The Utility business segment includes the generation, transmission, distribution, and sale of electric power in portions of Arkansas, Mississippi, Texas, and Louisiana, including the City of New Orleans; and operation of a small natural gas distribution business.

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The Entergy Wholesale Commodities business segment includes the ownership, operation, and decommissioning of nuclear power plants located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers. Entergy Wholesale Commodities also provides services to other nuclear power plant owners and owns interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. See “Entergy Wholesale Commodities Exit from the Merchant Power Business” below for discussion of the operation and planned shutdown and sale of each of the Entergy Wholesale Commodities nuclear power plants.

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

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

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•	an increase in formula rate plan revenues effective September 2018 and an interim increase in formula rate plan revenues effective June 2019 due to the inclusion of the first-year revenue requirement for the St. Charles Power Station, each at Entergy Louisiana, as approved by the LPSC;

•	an increase in formula rate plan rates effective with the first billing cycle of January 2019 at Entergy Arkansas, as approved by the APSC;

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•	a base rate increase effective October 2018 at Entergy Texas, as approved by the PUCT; and

•	an increase in formula rate plan revenues effective with the first billing cycle of July 2019 and an accrual in the fourth quarter 2019 for the interim capacity rate adjustment to the formula rate plan to recover non-fuel related costs of acquiring the Choctaw Generating Station, each at Entergy Mississippi, as approved by the MPSC.

(a)	The reduction in owned capacity is due to the shutdown of the 688 MW Pilgrim plant in May 2019.

•	an increase of $34 million in information technology costs primarily due to higher costs related to applications and infrastructure support, enhanced cyber security, and upgrades and maintenance;

•	an increase of $32 million in spending on initiatives to explore new customer products and services;

•	an increase of $21 million in compensation and benefits costs primarily due to higher incentive-based compensation accruals in 2019 as compared to prior year;

•	a $15 million gain in 2018 from the sale of Entergy Louisiana’s Willow Glen Power Station. See Note 14 to the financial statements for discussion of the sale of Willow Glen;

•	an increase of $12 million in distribution operations and asset management costs primarily due to higher advanced metering customer education costs and higher contract costs for meter reading services; and

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•	an $11 million write-off in 2019 of specific costs related to the potential construction of scrubbers at the White Bluff plant at Entergy Arkansas.

•	a decrease of $30 million in nuclear generation expenses primarily due to a lower scope of work performed in 2019 as compared to 2018;

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the effects of recording in 2019 final judgments to resolve claims in the ANO damages case and the River Bend damages case both against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $17 million of spent nuclear fuel storage costs previously recorded as other operation and maintenance expense. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation;

•	a decrease of $11 million in energy efficiency costs due to the timing of recovery from customers; and

•	a decrease of $9 million as a result of the deferral in 2019 by Entergy New Orleans of 2018 costs related to its rate case and a system conversion for Algiers customers as a result of the 2018 combined rate case resolution approved by the City Council. See Note 2 to the financial statements for further discussion of the rate case resolution.

•	additions to plant in service, including the St. Charles Power Station;

•	a reduction of approximately $26 million in depreciation expense recorded in the third quarter 2018 as part of a settlement approved by the FERC in the Unit Power Sales Agreement proceeding; and

•	new depreciation rates at Entergy Mississippi, as approved by the MPSC, and at Entergy Texas, as approved by the PUCT.

•	a regulatory charge recorded in second quarter 2018 to reflect the return of unprotected excess accumulated deferred income taxes per an agreement approved by the MPSC in June 2018 that resulted in a reduction in net utility plant of $127 million. There was no effect on net income as the regulatory charge was offset by a reduction in income tax expense in 2018;

•	regulatory charges of $73 million recorded in 2018 to reflect the effects of regulatory agreements to return the benefits of the lower income tax rate in 2018 to Entergy Louisiana customers; and

•	regulatory charges of $25 million recorded in 2018 to reflect the effects of a provision in the settlement reached in the 2018 rate case proceeding to return the benefits of the lower federal income tax rate in 2018 to Entergy Texas customers.

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•	a decrease of $75 million in nuclear generation expenditures primarily due to the absence of other operation and maintenance expenses from the Pilgrim plant, after it was shut down in May 2019 and subsequently sold. See Note 14 to the financial statements for further discussion of the sale of the Pilgrim plant; and

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a decrease of $44 million in severance and retention expenses. Severance and retention expenses were incurred in 2019 and 2018 due to management’s strategy to exit the Entergy Wholesale Commodities merchant power business. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Wholesale Commodities Exit from the Merchant Power Business” below for a discussion of management’s strategy to shut down and sell all of the remaining plants in Entergy Wholesale Commodities’ merchant nuclear fleet. See Note 13 to the financial statements for further discussion of severance and retention expenses resulting from management’s strategy to shut down and sell all of the remaining plants in Entergy Wholesale Commodities’ merchant nuclear fleet.

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

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(a)	The interest rate is the estimated interest rate as of December 31, 2019 that would have been applied to outstanding borrowings under the facility.

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

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(c)	The credit facility includes fronting commitments for the issuance of letters of credit against a portion of the borrowing capacity of the facility as follows: $5 million for Entergy Arkansas; $15 million for Entergy Louisiana; $10 million for Entergy New Orleans; and $30 million for Entergy Texas.

(d)	Borrowings under the Entergy Mississippi credit facilities may be secured by a security interest in its accounts receivable at Entergy Mississippi’s option.

(a)	As of December 31, 2019, letters of credit posted with MISO covered financial transmission right exposure of $0.2 million for Entergy Mississippi. See Note 15 to the financial statements for discussion of financial transmission rights.

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(a)	Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements.

(b)	Lease obligations are discussed in Note 10 to the financial statements.

(c)	Does not include power purchase agreements that are accounted for as leases that are included in purchase obligations.

(d)	Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. Almost all of the total are fuel and purchased power obligations.

•	Investments, including the Lake Charles Power Station, Washington Parish Energy Center, Sunflower Solar

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•	Investments in Entergy’s Utility nuclear fleet.

•	Transmission spending to enhance reliability, reduce congestion, and enable economic growth.

•	Distribution spending to enhance reliability and improve service to customers, including investment to support advanced metering.

•	Entergy Wholesale Commodities investments such as component replacements, software and security, and dry cask storage.

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•	internally generated funds;

•	cash on hand ($426 million as of December 31, 2019);

•	debt and equity issuances in the capital markets;

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

•	sales of assets.

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•	the decrease in the return of unprotected excess accumulated deferred income taxes to Utility customers. See Note 2 to the financial statements for a discussion of the regulatory activity regarding the Tax Cuts and Jobs Act;

•	an increase due to the timing of recovery of fuel and purchased power costs in 2019 as compared to the prior year. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery;

•	an increase of $109 million due to Vermont Yankee decommissioning spending in 2018, partially offset by Pilgrim decommissioning spending in 2019; and

•	a decrease of $87 million in spending on nuclear refueling outages in 2019 as compared to the prior year.

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•	an increase of $98 million in severance and retention payments in 2019 as compared to prior year. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Wholesale Commodities Exit from the Merchant Power Business” above for a discussion of management’s strategy to exit the Entergy Wholesale Commodities’ merchant power business; and

•	lower Entergy Wholesale Commodities revenues in 2019.

•	an increase of $334 million in construction expenditures in the Utility business, as discussed below;

•	the purchase of the Choctaw Generating Station in October 2019 for approximately $305 million. See Note 14 to the financial statements for further discussion of the Choctaw Generating Station purchase; and

•	a decrease of $57 million in proceeds received from the DOE in 2019 as compared to the prior year resulting from litigation regarding spent nuclear fuel storage costs that were previously capitalized. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.

•	a decrease of $174 million in nuclear fuel purchases due to variations from year to year in the timing and pricing of fuel reload requirements, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle; and

•	a decrease of $85 million primarily due to changes in collateral posted to provide credit support to secure its obligations under agreements to sell power produced by Entergy Wholesale Commodities’ power plants.

•	an increase of $211 million in transmission construction expenditures due to a higher scope of work performed in 2019 on various projects;

•	an increase of $188 million primarily due to investment in the infrastructure of the distribution system, including increased spending on advanced metering infrastructure; and

•	an increase of $91 million in storm spending in 2019.

•	a decrease of $62 million in fossil-fueled generation construction expenditures primarily due to lower spending in 2019 on self-build projects in the Utility business and a lower scope of work performed in 2019 on various projects;

•	a decrease of $39 million in nuclear construction expenditures primarily due to lower spending in 2019 on various nuclear projects; and

•	a decrease of $33 million in information technology capital expenditures primarily due to lower spending in 2019 on critical infrastructure protection.

•	long-term debt activity providing approximately $1,685 million of cash in 2019 compared to providing approximately $1,070 million in 2018;

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•	net repayments of short-term borrowings of $111 million in 2018 by the nuclear fuel company variable interest entities; and

•	an increase of $108 million in proceeds from the issuance of common stock as a result of the settlement of equity forwards in 2019 and 2018. See Note 7 to the financial statements for discussion of the equity forward sale agreements.

•	a decrease of $471 million in net issuances of commercial paper in 2019 compared to 2018;

•	an increase of $64 million in common stock dividends paid as a result of an increase in the shares outstanding and an increase in the dividend paid in 2019 compared to 2018; and

•	the issuance of $35 million aggregate liquidation value 5.375% Series A preferred stock in 2019 by Entergy Texas compared to the issuance of $73 million aggregate liquidation value 6.75% Series C preferred membership interests in 2018 by Entergy Utility Holding Company.

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•	The commodity price risk associated with the sale of electricity by the Entergy Wholesale Commodities business.

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

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

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

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(a)	Percent of planned generation output sold or purchased forward under contracts, forward physical contracts, forward financial contracts, or options that mitigate price uncertainty. Positions that are not classified as hedges are netted in the planned generation under contract.

(b)

Transaction under which power is supplied from a specific generation asset; if the asset is not operating, the seller is generally not liable to the buyer for any damages. Certain unit-contingent sales include a guarantee of availability. Availability guarantees provide for the payment to the power purchaser of contract damages, if incurred, in the event the seller fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. All of Entergy’s outstanding guarantees of availability provide for dollar limits on Entergy’s maximum liability under such guarantees.

(c)	Amount of output expected to be generated by Entergy Wholesale Commodities nuclear resources considering plant operating characteristics and outage schedules.

(d)	Assumes the planned shutdown of Indian Point 2 on April 30, 2020, planned shutdown of Indian Point 3 on April 30, 2021, and planned shutdown of Palisades on May 31, 2022. For a discussion regarding the planned shutdown of the Indian Point 2, Indian Point 3, and Palisades plants, see “Entergy Wholesale Commodities Exit from the Merchant Power Business” above.

(e)	Percent of planned qualified capacity sold to mitigate price uncertainty under physical or financial transactions.

(f)	A contract for the sale of installed capacity and related energy, priced per megawatt-hour sold.

(g)	A contract for the sale of an installed capacity product in a regional market.

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(h)	Includes assumptions on converting a portion of the portfolio to contracted with fixed price and excludes non-cash revenue from the amortization of the Palisades below-market purchased power agreement, mark-to-market activity, and service revenues.

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

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Cost Escalation Factors - Entergy’s current decommissioning cost studies include an assumption that decommissioning costs will escalate over present cost levels by factors ranging from approximately 2% to 3% annually. A 50-basis point change in this assumption could change the estimated present value of the decommissioning liabilities by approximately 6% to 18%. The timing assumption influences the significance of the effect of a change in the estimated inflation or cost escalation rate because the effect increases with the length of time assumed before decommissioning activity ends.

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Spent Fuel Disposal - Federal law requires the DOE to provide for the permanent storage of spent nuclear fuel, and legislation has been passed by Congress to develop a repository at Yucca Mountain, Nevada. The DOE has not yet begun accepting spent nuclear fuel and is in non-compliance with federal law. The DOE continues to delay meeting its obligation and Entergy’s nuclear plant owners are continuing to pursue damage claims against the DOE for its failure to provide timely spent fuel storage. Until a federal site is available, however, nuclear plant operators must provide for interim spent fuel storage on the nuclear plant site, which can require the construction and maintenance of dry cask storage sites or other facilities. The costs of developing and maintaining these facilities during the decommissioning period can have a significant effect (as much as an average of 20% to 30% of total estimated decommissioning costs). Entergy’s decommissioning studies include

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

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

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•	Future power and fuel prices - Electricity and gas prices can be very volatile. This volatility increases the imprecision inherent in the long-term forecasts of commodity prices that are a key determinant of estimated future cash flows.

•	Market value of generation assets - Valuing assets held for sale requires estimating the current market value of generation assets. While market transactions provide evidence for this valuation, these transactions are relatively infrequent, the market for such assets is volatile, and the value of individual assets is affected by factors unique to those assets.

•	Future operating costs - Entergy assumes relatively minor annual increases in operating costs. Technological or regulatory changes that have a significant effect on operations could cause a significant change in these assumptions.

•	Timing and the life of the asset - Entergy assumes an expected life of the asset. A change in the timing assumption, whether due to management decisions regarding operation of the plant, the regulatory process, or operational or other factors, could have a significant effect on the expected future cash flows and result in a significant effect on operations.

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(a)	In 2019, qualified pension cost included settlement charges of $23.5 million.

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

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

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

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We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets; and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

•	We evaluated the Corporation’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

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We read relevant regulatory orders issued by the Commissions and the FERC for the Corporation and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedence of the Commissions’ and the FERC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.

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For regulatory matters in process, we inspected the Corporation’s filings with the Commissions and the FERC, including the annual formula rate plan filings, base rate case filings, and open complaints filed with the FERC, and considered the filings with the Commissions and the FERC by intervenors that may impact the Corporation’s future rates, for any evidence that might contradict management’s assertions.

•	We obtained an analysis from management and letters from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities

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•	We tested the effectiveness of controls related to uncertain tax positions on internal restructuring transactions, including those over the recognition and measurement of the income tax benefits.

•	We evaluated the Corporation’s disclosures, and the balances recorded, related to uncertain tax positions on internal restructuring transactions.

•	We evaluated the methods and assumptions used by management to estimate the uncertain tax positions on internal restructuring transactions by testing the underlying data that served as the basis for the uncertain tax position on internal restructuring transactions.

•	With the assistance of our income tax specialists, we assessed the technical merits of the uncertain tax positions on internal restructuring transactions and management’s key estimates and judgments made by:

◦	Assessing the technical merits of the uncertain tax positions by comparing to similar cases filed with the Internal Revenue Service

◦	Evaluating the reasonableness and consistency of the probabilities applied to the uncertain tax position on internal restructuring transactions by comparing to probabilities used on similar internal restructuring transaction uncertain tax positions

◦	Considering the impact of changes or settlements in the tax environment on management’s methods and assumptions used to estimate the uncertain tax positions on internal restructuring transactions.

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•	We tested the effectiveness of controls over nuclear decommissioning, including those over the future dismantlement cost, site restoration, spent fuel management, and license termination.

•	We evaluated the Corporation’s disclosures related to the nuclear decommissioning cost estimates, including the balances recorded and changes in assumptions.

•	We evaluated management’s ability to accurately estimate the costs for nuclear decommissioning by comparing the cost estimates to actual settlements of similar asset retirement obligations at the Corporation.

•	We evaluated the methods and assumptions used by management to estimate the cost of nuclear decommissioning by:

◦	Testing the reasonableness of the underlying data that served as the basis for the estimate

◦	Comparing to management’s prior-year assumptions and testing significant changes in judgments or assumptions

◦	Comparing changes in cost estimates to other similar cost estimates recorded at the Corporation to confirm consistent assumptions and methods applied across all of the Corporation’s nuclear decommissioning cost estimates.

•	With the assistance of our environmental specialists, we:

◦	Evaluated the methods used by management to estimate the underlying costs for nuclear decommissioning

◦	Developed a range of independent estimates for the cost of nuclear decommissioning based on peer industry data and compared to management’s estimate

◦	Completed a search of environmental regulations to identify any regulatory changes that may affect the nuclear decommissioning cost estimates.

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The accompanying consolidated financial statements include the accounts of Entergy Corporation and its subsidiaries.  As required by generally accepted accounting principles in the United States of America, all intercompany transactions have been eliminated in the consolidated financial statements.  Entergy’s Registrant Subsidiaries (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy) also include their separate financial statements in this Form 10-K.  The Registrant Subsidiaries and many other Entergy subsidiaries also maintain accounts in accordance with FERC and other regulatory guidelines.  

Use of Estimates in the Preparation of Financial Statements

In conformity with generally accepted accounting principles in the United States of America, the preparation of Entergy Corporation’s consolidated financial statements and the separate financial statements of the Registrant Subsidiaries requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses, and the disclosure of contingent assets and liabilities.  Adjustments to the reported amounts of assets and liabilities may be necessary in the future to the extent that future estimates or actual results are different from the estimates used.

Revenues and Fuel Costs

See Note 19 to the financial statements for a discussion of Entergy’s and the Registrant Subsidiaries’ revenues and fuel costs.

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost less regulatory disallowances and impairments.  Depreciation is computed on the straight-line basis at rates based on the applicable estimated service lives of the various classes of property.  For the Registrant Subsidiaries, the original cost of plant retired or removed, less salvage, is charged to accumulated depreciation.  Normal maintenance, repairs, and minor replacement costs are charged to operating expenses.  Certain combined-cycle gas turbine generating units are maintained under long-term service agreements with third-party service providers. The costs under these agreements are split between operating expenses and capital additions based upon the nature of the work performed. Substantially all of the Registrant Subsidiaries’ plant is subject to mortgage liens.

Electric plant includes the portions of Grand Gulf and Waterford 3 that were sold and leased back in prior periods.  For financial reporting purposes, these sale and leaseback arrangements are reflected as financing transactions. In March 2016, Entergy Louisiana completed the first step in a two-step transaction to purchase the undivided interests in Waterford 3 that were previously being leased by acquiring a beneficial interest in the Waterford 3 leased assets. In February 2017 the leases were terminated and the leased assets transferred to Entergy Louisiana. See Note 10 to the financial statements for further discussion of Entergy Louisiana’s purchase of the Waterford 3 leased assets.

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Net property, plant, and equipment for Entergy (including property under lease and associated accumulated amortization) by business segment and functional category, as of December 31, 2019 and 2018, is shown below:

2019		Entergy				Utility				Entergy Wholesale Commodities				Parent & Other
		(In Millions)
Production
Nuclear			$7,439				$7,369				$70				$—
Other		5,253				5,139				114				—
Transmission		7,383				7,383				—				—
Distribution		8,972				8,972				—				—
Other		2,636				2,620				8				8
Construction work in progress		2,823				2,814				9				—
Nuclear fuel		677				614				63				—
Property, plant, and equipment - net			$35,183				$34,911				$264				$8

2018		Entergy				Utility				Entergy Wholesale Commodities				Parent & Other
		(In Millions)
Production
Nuclear			$7,096				$6,964				$132				$—
Other		4,171				4,069				102				—
Transmission		6,592				6,590				2				—
Distribution		8,343				8,343				—				—
Other		2,022				2,011				2				9
Construction work in progress		2,889				2,815				74				—
Nuclear fuel		861				754				107				—
Property, plant, and equipment - net			$31,974				$31,546				$419				$9

Depreciation rates on average depreciable property for Entergy approximated 2.8% in 2019, 2.8% in 2018, and 3% in 2017.  Included in these rates are the depreciation rates on average depreciable Utility property of 2.6% in 2019, 2.6% in 2018, and 2.6% in 2017, and the depreciation rates on average depreciable Entergy Wholesale Commodities property of 18.3% in 2019, 18.6% in 2018, and 22.3% in 2017. The depreciation rates for Entergy Wholesale Commodities reflect the significantly reduced remaining estimated operating lives associated with management’s strategy to shut down and sell all of the remaining plants in Entergy Wholesale Commodities’ merchant nuclear fleet. The decrease in the depreciation rate in 2018 for Entergy Wholesale Commodities is due to the decision in the third quarter 2017 to continue operating Palisades until May 31, 2022.

Entergy amortizes nuclear fuel using a units-of-production method.  Nuclear fuel amortization is included in fuel expense in the income statements. Because the values of their long-lived assets are impaired, and their remaining estimated operating lives significantly reduced, the Entergy Wholesale Commodities nuclear plants, except for Palisades, charge nuclear fuel costs directly to expense when incurred because their undiscounted cash flows are insufficient to recover the carrying amount of these capital additions.

Non-utility property - at cost (less accumulated depreciation) for Entergy is reported net of accumulated depreciation of $184 million as of December 31, 2019 and $177 million as of December 31, 2018.

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Construction expenditures included in accounts payable is $406 million as of December 31, 2019 and $311 million as of December 31, 2018.

Net property, plant, and equipment for the Registrant Subsidiaries (including property under lease and associated accumulated amortization) by company and functional category, as of December 31, 2019 and 2018, is shown below:

2019		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
		(In Millions)
Production
Nuclear			$1,611				$4,042				$—				$—				$—				$1,716
Other		785				2,789				845				192				528				—
Transmission		1,966				2,944				1,136				96				1,202				39
Distribution		2,457				3,078				1,489				505				1,443				—
Other		454				884				309				270				256				30
Construction work in progress		198				1,384				88				202				760				165
Nuclear fuel		196				268				—				—				—				150
Property, plant, and equipment - net			$7,667				$15,389				$3,867				$1,265				$4,189				$2,100

2018		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
		(In Millions)
Production
Nuclear			$1,494				$3,725				$—				$—				$—				$1,745
Other		820				2,029				509				196				515				—
Transmission		1,792				2,571				1,046				78				1,063				40
Distribution		2,329				2,882				1,342				471				1,319				—
Other		311				699				242				233				193				39
Construction work in progress		244				1,865				128				147				325				70
Nuclear fuel		221				298				—				—				—				235
Property, plant, and equipment - net			$7,211				$14,069				$3,267				$1,125				$3,415				$2,129

Depreciation rates on average depreciable property for the Registrant Subsidiaries are shown below:

	Entergy Arkansas		Entergy Louisiana		Entergy Mississippi		Entergy New Orleans		Entergy Texas		System Energy
2019	2.5%		2.4%		3.2%		3.2%		3.0%		2.1%
2018	2.5%		2.3%		3.2%		3.5%		2.7%		1.9%
2017	2.5%		2.3%		3.1%		3.5%		2.6%		2.8%

Non-utility property - at cost (less accumulated depreciation) for Entergy Louisiana is reported net of accumulated depreciation of $168.5 million as of December 31, 2019 and $161.2 million as of December 31, 2018. Non-utility property - at cost (less accumulated depreciation) for Entergy Mississippi is reported net of accumulated depreciation of $0.5 million as of December 31, 2019 and $0.5 million as of December 31, 2018.  Non-utility property

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- at cost (less accumulated depreciation) for Entergy Texas is reported net of accumulated depreciation of $4.9 million as of December 31, 2019 and $4.9 million as of December 31, 2018.

As of December 31, 2019, construction expenditures included in accounts payable are $67.9 million for Entergy Arkansas, $115.1 million for Entergy Louisiana, $34.2 million for Entergy Mississippi, $18.4 million for Entergy New Orleans, $88.1 million for Entergy Texas, and $23.2 million for System Energy. As of December 31, 2018, construction expenditures included in accounts payable are $35.7 million for Entergy Arkansas, $104.6 million for Entergy Louisiana, $13.6 million for Entergy Mississippi, $5.8 million for Entergy New Orleans, $55.6 million for Entergy Texas, and $26.3 million for System Energy.

Jointly-Owned Generating Stations

Certain Entergy subsidiaries jointly own electric generating facilities with affiliates or third parties. All parties are required to provide their own financing.  The investments, fuel expenses, and other operation and maintenance expenses associated with these generating stations are recorded by the Entergy subsidiaries to the extent of their respective undivided ownership interests.  As of December 31, 2019, the subsidiaries’ investment and accumulated depreciation in each of these generating stations were as follows:

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Generating Stations			Fuel Type		Total Megawatt Capability (a)			Ownership			Investment				Accumulated Depreciation
											(In Millions)
Utility business:
Entergy Arkansas -
Independence	Unit 1		Coal		826			31.50	%			$142				$104
Independence	Common Facilities		Coal					15.75	%			$35				$29
White Bluff	Units 1 and 2		Coal		1,638			57.00	%			$555				$380
Ouachita (b)	Common Facilities		Gas					66.67	%			$173				$153
Union (c)	Units 1 and 2 Common Facilities		Gas					50.00	%			$0.4				$0.1
Union (c)	Common Facilities		Gas					25.00	%			$29				$6
Entergy Louisiana -
Roy S. Nelson	Unit 6		Coal		525			40.25	%			$286				$207
Roy S. Nelson	Unit 6 Common Facilities		Coal					19.95	%			$20				$9
Big Cajun 2	Unit 3		Coal		576			24.15	%			$151				$124
Big Cajun 2	Unit 3 Common Facilities		Coal					8.05	%			$5				$2
Ouachita (b)	Common Facilities		Gas					33.33	%			$90				$77
Acadia	Common Facilities		Gas					50.00	%			$20				$1
Union (c)	Common Facilities		Gas					50.00	%			$57				$6
Entergy Mississippi -
Independence	Units 1 and 2 and Common Facilities		Coal		1,668			25.00	%			$271				$163
Entergy New Orleans -
Union (c)	Units 1 and 2 Common Facilities		Gas					50.00	%			$1				$0.1
Union (c)	Common Facilities		Gas					25.00	%			$29				$6
Entergy Texas -
Roy S. Nelson	Unit 6		Coal		525			29.75	%			$204				$120
Roy S. Nelson	Unit 6 Common Facilities		Coal					14.75	%			$7				$3
Big Cajun 2	Unit 3		Coal		576			17.85	%			$113				$80
Big Cajun 2	Unit 3 Common Facilities		Coal					5.95	%			$4				$1
System Energy -
Grand Gulf (d)	Unit 1		Nuclear		1,393			90.00	%			$5,071				$3,285
Entergy Wholesale Commodities:
Independence	Unit 2		Coal		842			14.37	%			$74				$53
Independence	Common Facilities		Coal					7.18	%			$17				$13
Roy S. Nelson	Unit 6		Coal		525			10.90	%			$115				$66
Roy S. Nelson	Unit 6 Common Facilities		Coal					5.40	%			$3				$1

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(a)	“Total Megawatt Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.

(b)	Ouachita Units 1 and 2 are owned 100% by Entergy Arkansas and Ouachita Unit 3 is owned 100% by Entergy Louisiana.  The investment and accumulated depreciation numbers above are only for the common facilities and not for the generating units.

(c)	Union Unit 1 is owned 100% by Entergy New Orleans, Union Unit 2 is owned 100% by Entergy Arkansas, Union Units 3 and 4 are owned 100% by Entergy Louisiana.  The investment and accumulated depreciation numbers above are only for the specified common facilities and not for the generating units.

(d)	Includes a leasehold interest held by System Energy.  System Energy’s Grand Gulf lease obligations are discussed in Note 10 to the financial statements.

Nuclear Refueling Outage Costs

Nuclear refueling outage costs are deferred during the outage and amortized over the estimated period to the next outage because these refueling outage expenses are incurred to prepare the units to operate for the next operating cycle without having to be taken off line. Because the value of their long-lived assets are impaired, and their remaining estimated operating lives significantly reduced, the Entergy Wholesale Commodities nuclear plants, except for Palisades, charge nuclear refueling outage costs directly to expense when incurred because their undiscounted cash flows are insufficient to recover the carrying amount of these costs.

Allowance for Funds Used During Construction (AFUDC)

AFUDC represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction by the Registrant Subsidiaries.  AFUDC increases both the plant balance and earnings and is realized in cash through depreciation provisions included in the rates charged to customers.

Income Taxes

Entergy Corporation and the majority of its subsidiaries file a United States consolidated federal income tax return.  In September 2019, Entergy Utility Holding Company, LLC and its regulated wholly owned subsidiaries including Entergy Arkansas, LLC, Entergy Louisiana, LLC, Entergy Mississippi, LLC, and Entergy New Orleans, LLC became eligible to and joined the Entergy Corporation consolidated federal income tax group. These changes do not affect the accrual or allocation of income taxes for the Registrant Subsidiaries.  Each tax-paying entity records income taxes as if it were a separate taxpayer and consolidating adjustments are allocated to the tax filing entities in accordance with Entergy’s intercompany income tax allocation agreements.  Deferred income taxes are recorded for temporary differences between the book and tax basis of assets and liabilities, and for certain losses and credits available for carryforward.

Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax assets will not be realized.  Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates in the period in which the tax or rate was enacted. 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 enactment of the Tax Cuts and Jobs Act in December 2017.

The benefits of investment tax credits are deferred and amortized over the average useful life of the related property, as a reduction of income tax expense, for such credits associated with rate-regulated operations in accordance with ratemaking treatment.

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Earnings (Loss) per Share

The following table presents Entergy’s basic and diluted earnings per share calculation included on the consolidated statements of operations:

	For the Years Ended December 31,
	2019								2018								2017
	(In Millions, Except Per Share Data)
					$/share								$/share								$/share
Net income attributable to Entergy Corporation		$1,241.2								$848.7								$411.6
Basic shares and earnings per average common share	195.2					$6.36			181.4					$4.68			179.7					$2.29
Average dilutive effect of:
Stock options	0.6				(0.02		)		0.3				(0.01		)		0.2				—
Other equity plans	0.8				(0.03		)		0.7				(0.02		)		0.6				(0.01		)
Equity forwards	0.4				(0.01		)		1.0				(0.02		)		—				—
Diluted shares and earnings per average common shares	197.0					$6.30			183.4					$4.63			180.5					$2.28

The calculation of diluted earnings per share excluded 173,290 options outstanding at December 31, 2019, 956,550 options outstanding at December 31, 2018, and 2,927,512 options outstanding at December 31, 2017 because they were antidilutive.

Stock-based Compensation Plans

Entergy grants stock options, restricted stock, performance units, and restricted stock unit awards to key employees of the Entergy subsidiaries under its Equity Ownership Plans, which are shareholder-approved stock-based compensation plans.  These plans are described more fully in Note 12 to the financial statements.   The cost of the stock-based compensation is charged to income over the vesting period.  Awards under Entergy’s plans generally vest over three years. Entergy accounts for forfeitures of stock-based compensation when they occur. Entergy recognizes all income tax effects related to share-based payments through the income statement.

Accounting for the Effects of Regulation

Entergy’s Utility operating companies and System Energy are rate-regulated enterprises whose rates meet three criteria specified in accounting standards.  The Utility operating companies and System Energy have rates that (i) are approved by a body (its regulator) empowered to set rates that bind customers; (ii) are cost-based; and (iii) can be charged to and collected from customers.  These criteria may also be applied to separable portions of a utility’s business, such as the generation or transmission functions, or to specific classes of customers.  Because the Utility operating companies and System Energy meet these criteria, each of them capitalizes costs that would otherwise be charged to expense if the rate actions of its regulator make it probable that those costs will be recovered in future revenue.  Such capitalized costs are reflected as regulatory assets in the accompanying financial statements.  When an enterprise concludes that recovery of a regulatory asset is no longer probable, the regulatory asset must be removed from the entity’s balance sheet.

An enterprise that ceases to meet the three criteria for all or part of its operations should report that event in its financial statements.  In general, the enterprise no longer meeting the criteria should eliminate from its balance sheet all regulatory assets and liabilities related to the applicable operations.  Additionally, if it is determined that a regulated enterprise is no longer recovering all of its costs, it is possible that an impairment may exist that could require further write-offs of plant assets.

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Entergy Louisiana does not apply regulatory accounting standards to the Louisiana retail deregulated portion of River Bend, the 30% interest in River Bend formerly owned by Cajun, or its steam business, unless specific cost recovery is provided for in tariff rates.  The Louisiana retail deregulated portion of River Bend is operated under a deregulated asset plan representing a portion (approximately 15%) of River Bend plant costs, generation, revenues, and expenses established under a 1992 LPSC order.  The plan allows Entergy Louisiana to sell the electricity from the deregulated assets to Louisiana retail customers at 4.6 cents per kWh or off-system at higher prices, with certain provisions for sharing incremental revenue above 4.6 cents per kWh between customers and shareholders.

Regulatory Asset or Liability for Income Taxes

Accounting standards for income taxes provide that a regulatory asset or liability be recorded if it is probable that the currently determinable future increase or decrease in regulatory income tax expense will be recovered from or returned to customers through future rates. There are two main sources of Entergy’s regulatory asset or liability for income taxes. There is a regulatory asset related to the ratemaking treatment of the tax effects of book depreciation for the equity component of AFUDC that has been capitalized to property, plant, and equipment but for which there is no corresponding tax basis. Equity-AFUDC is a component of property, plant, and equipment that is included in rate base when the plant is placed in service. There is a regulatory liability related to the adjustment of Entergy’s net deferred income taxes that was required by the enactment in December 2017 of a change in the federal corporate income tax rate, which is discussed in Note 2 and 3 to the financial statements.

Cash and Cash Equivalents

Entergy considers all unrestricted highly liquid debt instruments with an original maturity of three months or less at date of purchase to be cash equivalents.

Securitization Recovery Trust Accounts

The funds that Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas hold in their securitization recovery trust accounts are not classified as cash and cash equivalents or restricted cash and cash equivalents because of their nature, uses, and restrictions. These funds are classified as part of other current assets and other investments, depending on the timeframe within which the Registrant Subsidiary expects to use the funds.

Allowance for Doubtful Accounts

The allowance for doubtful accounts reflects Entergy’s best estimate of losses on the accounts receivable balances.  The allowance is based on accounts receivable agings, historical experience, and other currently available evidence.  Utility operating company customer accounts receivable are written off consistent with approved regulatory requirements.

Investments

Entergy records decommissioning trust funds on the balance sheet at their fair value. Effective January 1, 2018, with the adoption of ASU 2016-01, unrealized gains and losses on investments in equity securities held by the nuclear decommissioning trust funds are recorded in earnings as they occur rather than in other comprehensive income. Because of the ability of the Registrant Subsidiaries to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, the Registrant Subsidiaries have recorded an offsetting amount of unrealized gains/(losses) on investment securities in other regulatory liabilities/assets.  For the 30% interest in River Bend formerly owned by Cajun, Entergy Louisiana records an offsetting amount in other deferred credits for the unrealized trust earnings not currently expected to be needed to decommission the plant.  Decommissioning trust funds for the Entergy Wholesale Commodities nuclear plants do not meet the criteria for regulatory accounting treatment. Accordingly, unrealized gains/(losses) recorded on the equity securities in the trust funds are recognized in

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earnings. Unrealized gains recorded on the available-for-sale debt securities in the trust funds are recognized in the accumulated other comprehensive income component of shareholders’ equity. Unrealized losses (where cost exceeds fair market value) on the available-for-sale debt securities in the trust funds are also recorded in the accumulated other comprehensive income component of shareholders’ equity unless the unrealized loss is other than temporary and therefore recorded in earnings.  A portion of Entergy’s decommissioning trust funds are held in a wholly-owned registered investment company, and unrealized gains and losses on both the equity and debt securities held in the registered investment company are recognized in earnings. The assessment of whether an investment in an available-for-sale debt security has suffered an other-than-temporary impairment is based on whether Entergy has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs.  Further, if Entergy does not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary impairment is considered to have occurred and it is measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss).  Entergy’s trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments. See Note 16 to the financial statements for details on the decommissioning trust funds.

Equity Method Investments

Entergy owns investments that are accounted for under the equity method of accounting because Entergy’s ownership level results in significant influence, but not control, over the investee and its operations.  Entergy records its share of the investee’s comprehensive earnings and losses in income and as an increase or decrease to the investment account. Any cash distributions are charged against the investment account. Entergy discontinues the recognition of losses on equity investments when its share of losses equals or exceeds its carrying amount for an investee plus any advances made or commitments to provide additional financial support.  

Derivative Financial Instruments and Commodity Derivatives

The accounting standards for derivative instruments and hedging activities require that all derivatives be recognized at fair value on the balance sheet, either as assets or liabilities, unless they meet various exceptions including the normal purchase/normal sale criteria.  The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction. Due to regulatory treatment, an offsetting regulatory asset or liability is recorded for changes in fair value of recognized derivatives for the Registrant Subsidiaries.

Contracts for commodities that will be physically delivered in quantities expected to be used or sold in the ordinary course of business, including certain purchases and sales of power and fuel, meet the normal purchase, normal sales criteria and are not recognized on the balance sheet.  Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered.

For other contracts for commodities in which Entergy is hedging the variability of cash flows related to a variable-rate asset, liability, or forecasted transactions that qualify as cash flow hedges, the changes in the fair value of such derivative instruments are reported in other comprehensive income.  To qualify for hedge accounting, the relationship between the hedging instrument and the hedged item must be documented to include the risk management objective and strategy and, at inception and on an ongoing basis, the effectiveness of the hedge in offsetting the changes in the cash flows of the item being hedged.  Gains or losses accumulated in other comprehensive income are reclassified to earnings in the periods when the underlying transactions actually occur.  Prior to 2019, the ineffective portions of all hedges are recognized in current-period earnings. Effective January 1, 2019 with the adoption of ASU 2017-12 there will no longer be separate recognition of the ineffective portion of highly effective hedges. Changes in the fair value of derivative instruments that are not designated as cash flow hedges are recorded in current-period earnings on a mark-to-market basis.

Entergy has determined that contracts to purchase uranium do not meet the definition of a derivative under the accounting standards for derivative instruments because they do not provide for net settlement and the uranium markets

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are not sufficiently liquid to conclude that forward contracts are readily convertible to cash.  If the uranium markets do become sufficiently liquid in the future and Entergy begins to account for uranium purchase contracts as derivative instruments, the fair value of these contracts would be accounted for consistent with Entergy’s other derivative instruments. See Note 15 to the financial statements for further details on Entergy’s derivative instruments and hedging activities.

Fair Values

The estimated fair values of Entergy’s financial instruments and derivatives are determined using historical prices, bid prices, market quotes, and financial modeling.  Considerable judgment is required in developing the estimates of fair value.  Therefore, estimates are not necessarily indicative of the amounts that Entergy could realize in a current market exchange.  Gains or losses realized on financial instruments held by regulated businesses may be reflected in future rates and therefore do not affect net income.  Entergy considers the carrying amounts of most financial instruments classified as current assets and liabilities to be a reasonable estimate of their fair value because of the short maturity of these instruments.  See Note 15 to the financial statements for further discussion of fair value.

Impairment of Long-lived Assets

Entergy periodically reviews long-lived assets held in all of its business segments whenever events or changes in circumstances indicate that recoverability of these assets is uncertain.  Generally, the determination of recoverability is based on the undiscounted net cash flows expected to result from such operations and assets.  Projected net cash flows depend on the expected operating life of the assets, the future operating costs associated with the assets, the efficiency and availability of the assets and generating units, and the future market and price for energy and capacity over the remaining life of the assets. Because the values of their long-lived assets are impaired, and their remaining estimated operating lives significantly reduced, the Entergy Wholesale Commodities nuclear plants, except for Palisades, are charging additional expenditures for capital assets directly to expense when incurred because their undiscounted cash flows are insufficient to recover the carrying amount of these capital additions.  See Note 14 to the financial statements for further discussions of the impairments of the Entergy Wholesale Commodities nuclear plants.

River Bend AFUDC

The River Bend AFUDC gross-up is a regulatory asset that represents the incremental difference imputed by the LPSC between the AFUDC actually recorded by Entergy Louisiana on a net-of-tax basis during the construction of River Bend and what the AFUDC would have been on a pre-tax basis.  The imputed amount was only calculated on that portion of River Bend that the LPSC allowed in rate base and is being amortized through August 2025.

Reacquired Debt

The premiums and costs associated with reacquired debt of Entergy’s Utility operating companies and System Energy (except that portion allocable to the deregulated operations of Entergy Louisiana) are included in regulatory assets and are being amortized over the life of the related new issuances, or over the life of the original debt issuance if the debt is not refinanced, in accordance with ratemaking treatment.

Taxes Imposed on Revenue-Producing Transactions

Governmental authorities assess taxes that are both imposed on and concurrent with a specific revenue-producing transaction between a seller and a customer, including, but not limited to, sales, use, value added, and some excise taxes.  Entergy presents these taxes on a net basis, excluding them from revenues, unless required to report them differently by a regulatory authority.

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New Accounting Pronouncements

In June 2016 the FASB issued ASU No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” The ASU requires entities to record a valuation allowance on financial instruments recorded at amortized cost or classified as available-for-sale debt securities for the total credit losses expected over the life of the instrument. Increases and decreases in the valuation allowance will be recognized immediately in earnings. Entergy adopted ASU 2016-13 in the first quarter 2020. Adoption of ASU 2016-13 did not materially affect Entergy’s results of operations, financial position, or cash flows.

In September 2018 the FASB issued ASU No. 2018-15, “Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service.”  The ASU requires entities to capitalize implementation costs associated with cloud computing arrangements classified as hosting arrangements and amortize those costs over the contract term.  These costs are required to be capitalized in the same line as prepayments of the costs, and subsequently amortized in the same lines as the hosting service element of the arrangement.  Entergy adopted ASU 2018-15 in the first quarter 2020.   Entergy adopted ASU 2018-15 on a prospective basis, which will affect its statement of financial position by presenting implementation costs for hosting arrangements as prepayments rather than utility plant, and will affect its results of operations by amortizing those costs as operation and maintenance expense, rather than depreciation and amortization, over the contract term of the arrangement.

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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, 2019 and 2018:

 

Other Regulatory Assets

Entergy

	2019				2018
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$2,942.4				$2,611.5
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	920.4				814.3
Removal costs - recovered through depreciation rates (Note 9)	421.0				375.8
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 – Storm Cost Recovery Filings with Retail Regulators) (Note 5)	372.8				452.7
Retired electric and gas meters - recovered through retail rates as determined by retail regulators (Note 2 - Advanced Metering Infrastructure (AMI) Filings)	205.6				—
Opportunity Sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding) (b)	116.3				116.3
Unamortized loss on reacquired debt - recovered over term of debt	66.6				74.5
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy)	29.9				52.1
Attorney General litigation costs (Note 2 - Mississippi Attorney General Complaint) (b)	29.5				23.6
New nuclear generation development costs (Note 2 - New Nuclear Generation Development Costs) (b)	21.6				29.0
Retail rate deferrals - recovered through rate riders as rates are redetermined by retail regulators	15.7				39.0
Other	150.3				157.7
Entergy Total		$5,292.1				$4,746.5

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Entergy Arkansas

	2019				2018
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$796.5				$747.2
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	433.0				381.7
Removal costs - recovered through depreciation rates (Note 9)	168.9				138.3
Opportunity sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding) (b)	116.3				116.3
Retired electric meters - recovered over 15-year period through March 2034 (Note 2 - Advanced Metering Infrastructure (AMI) Filings)	50.4				—
Storm damage costs - recovered either through securitization or retail rates (Note 5 - Entergy Arkansas Securitization Bonds)	46.1				60.7
Unamortized loss on reacquired debt - recovered over term of debt	18.3				21.2
ANO Fukushima and Flood Barrier costs - recovered through retail rates through February 2026 (Note 2 - Retail Rate Proceedings) (b)	10.9				12.6
Retail rate deferrals - recovered through rate riders as rates are redetermined annually (b)	2.3				20.5
Other	24.2				36.5
Entergy Arkansas Total		$1,666.9				$1,535.0

Entergy Louisiana

	2019				2018
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (a)		$787.7				$711.8
Asset Retirement Obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	262.5				232.9
Retired electric meters - recovered over a 22-year period through July 2041 (Note 2 - Advanced Metering Infrastructure (AMI) Filings)	101.1				—
Storm damage costs - recovered through retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)	45.7				17.9
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy)	27.6				49.8
New nuclear generation development costs - recovery through formula rate plan December 2014 through November 2022 (Note 2 - New Nuclear Generation Development Costs) (b)	21.2				28.5
Unamortized loss on reacquired debt - recovered over term of debt	20.4				22.5
Business combination external costs deferral - recovery through formula rate plan December 2015 through November 2025 (b)	10.8				12.4
River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC)	9.1				11.0
Other	29.1				18.3
Entergy Louisiana Total		$1,315.2				$1,105.1

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Entergy Mississippi

	2019				2018
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$234.4				$215.9
Removal costs - recovered through depreciation rates (Note 9)	80.8				63.5
Attorney General litigation costs (Note 2 - Mississippi Attorney General Complaint) (b)	29.5				23.6
Unamortized loss on reacquired debt - recovered over term of debt	14.9				16.2
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a)	7.8				7.2
Retail rate deferrals - recovered through rate riders as rates are redetermined annually	7.6				16.6
Other	3.0				—
Entergy Mississippi Total		$378.0				$343.0

Entergy New Orleans

	2019				2018
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$85.9				$96.2
Storm damage costs, including hurricane costs - recovered through retail rates and securitization (Note 2 - Storm Cost Recovery Filings with Retail Regulators)	59.6				70.4
Removal costs - recovered through depreciation rates (Note 9)	52.9				49.3
Retired meters - recovered over a 12-year period through July 2031 (Note 2 - Advanced Metering Infrastructure (AMI) Filings) (b)	24.6				—
Retired plant costs - recovered over a 20-year period through July 2039 (Note 2 - Retail Rate Proceedings)	10.0				—
Rate case costs - recovered over a 3-year period through July 2022 (Note 2 - Retail Rate Proceedings)	7.0				—
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a)	4.9				4.5
Algiers customer migration costs - recovered over a 5-year period through July 2024 (Note 2 - Retail Rate Proceedings)	4.9				—
Unamortized loss on reacquired debt - recovered over term of debt	2.3				2.6
Other	7.3				6.8
Entergy New Orleans Total		$259.4				$229.8

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Entergy Texas

	2019				2018
	(In Millions)
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 5 - Entergy Texas Securitization Bonds)		$221.4				$303.6
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)	167.7				171.8
Removal costs - recovered through depreciation rates (Note 9)	42.5				50.9
Retired electric meters - recovered over 13-year period through February 2032 (Note 2 - Advanced Metering Infrastructure (AMI) Filings)	28.4				—
Neches and Sabine costs - recovered over a 10-year period through September 2028 (Note 2 - Retail Rate Proceedings)	21.2				23.6
Transition to competition costs - recovered over a 15-year period through February 2021	14.9				26.7
Unamortized loss on reacquired debt - recovered over term of debt	7.7				8.2
Other	8.8				13.2
Entergy Texas Total		$512.6				$598.0

System Energy

	2019				2018
	(In Millions)
Asset retirement obligation - recovery dependent upon timing of decommissioning (Note 9) (a)		$210.9				$186.9
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Other Postretirement Benefits) (a)	200.3				179.3
Removal costs - recovered through depreciation rates (Note 9)	75.9				76.4
Unamortized loss on reacquired debt - recovered over term of debt	3.0				3.8
System Energy Total		$490.1				$446.4

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

(b)	Does not earn a return on investment.

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Other Regulatory Liabilities

Entergy

	2019				2018
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)		$1,300.1				$815.9
Vidalia purchased power agreement (Note 8) (b)	127.3				139.7
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) (b)	97.1				111.1
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually	62.3				84.6
Grand Gulf sale-leaseback - (Note 5 - Grand Gulf Sale-Leaseback Transactions)	55.6				55.6
Future formula rate plan revenue reductions (Note 2 - Retail Rate Proceedings)	51.1				44.4
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and the FERC	44.4				44.4
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)	37.2				39.1
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates December 2015 through November 2024	35.7				50.8
Internal restructuring guaranteed customer credits (Note 2 - Retail Rate Proceedings)	33.0				39.6
Advanced metering system (AMS) surcharge - return to customers dependent upon AMS spend (Note 2 - Advanced Metering Infrastructure (AMI) Filings)	25.3				16.5
Excess decommissioning recovery for Willow Glen - (Note 14 - Dispositions)	21.2				31.9
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement	17.8				25.0
Income tax rate change - returned to electric and gas customers through retail rates (Note 2 - Retail Rate Proceedings)	13.9				74.7
Removal costs - returned to customers through depreciation rates (Note 9)	2.4				18.8
Other	36.6				28.2
Entergy Total		$1,961.0				$1,620.3

Entergy Arkansas

	2019				2018
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)		$460.3				$297.2
Future formula rate plan revenue reductions (Note 2 - Retail Rate Proceedings)	46.6				35.1
Internal restructuring guaranteed customer credits (Note 2 - Retail Rate Proceedings)	33.0				39.6
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually	19.7				30.8
Entergy Arkansas Total		$559.6				$402.7

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Entergy Louisiana

	2019				2018
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)		$436.5				$274.1
Vidalia purchased power agreement (Note 8) (b)	127.3				139.7
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) (b)	97.1				111.1
Asset Retirement Obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)	37.1				39.1
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates December 2015 through November 2024	35.7				50.8
Excess decommissioning recovery for Willow Glen - returned over one-year period through retail rates (Note 14 - Dispositions)	21.2				31.9
Removal costs - returned to customers through depreciation rates (Note 9)	2.4				18.8
Income tax rate change - returned to electric customers through retail rates September 2018 through August 2019 (Note 2 - Retail Rate Proceedings)	—				49.9
Other	36.8				33.4
Entergy Louisiana Total		$794.1				$748.8

Entergy Mississippi

	2019				2018
	(In Millions)
Retail rate deferrals - returned to customers through rate riders as rates are redetermined annually		$14.6				$1.3
Future formula rate plan revenue reductions (Note 2 - Retail Rate Proceedings)	4.5				9.3
Grand Gulf Over-Recovery - returned to customers through rate riders as rates are redetermined annually	2.4				22.6
Other	—				0.4
Entergy Mississippi Total		$21.5				$33.6

Entergy Texas

	2019				2018
	(In Millions)
Advanced metering system (AMS) surcharge - returned to customers dependent upon AMS spend (Note 2 - Advanced Metering Infrastructure (AMI) Filings)		$25.3				$16.5
Income tax rate change - refunded through a rate rider (Note 2 - Retail Rate Proceedings)	10.4				23.1
Transition to competition costs - returned to customers through rate riders when rates are redetermined periodically	3.8				4.2
Other	2.6				4.1
Entergy Texas Total		$42.1				$47.9

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System Energy

	2019				2018
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)		$403.3				$244.6
Grand Gulf sale-leaseback - (Note 5 - Grand Gulf Sale-Leaseback Transactions)	55.6				55.6
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and the FERC	44.4				44.4
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement	17.8				25.0
Other	12.3				12.3
System Energy Total		$533.4				$381.9

(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 were returned to customers over a 21-month period from April 2018 through December 2019. For all other customer classes, unprotected excess accumulated deferred income taxes were returned to customers over a nine-month period from April 2018 through December 2018. A true-up provision also was included in the rider, with any over- or under-returned unprotected excess accumulated deferred income taxes credited or billed to customers during the billing month of January 2020, with any residual amounts of over- or under-returned unprotected excess accumulated deferred income taxes to be flowed through Entergy Arkansas’s energy cost recovery rider. In March 2018 the APSC approved the tax adjustment rider effective with the first billing cycle of April 2018.

As discussed below, in July 2018, Entergy Arkansas made its formula rate plan filing to set its formula rate for the 2019 calendar year. A hearing was held in May 2018 regarding the APSC’s inquiries into the effects of the Tax Act, including Entergy Arkansas’s proposal to utilize its formula rate plan rider for its customers to realize the remaining benefits of the Tax Act. Entergy Arkansas’s formula rate plan rider included a netting adjustment that compared actual annual results to the allowed rate of return on common equity. In July 2018 the APSC issued an order agreeing with Entergy Arkansas’s proposal to have the effects of the Tax Act on current income tax expense flow through Entergy Arkansas’s formula rate plan rider and with Entergy Arkansas’s treatment of protected and unprotected excess accumulated deferred income taxes. The APSC also directed Entergy Arkansas to submit in the tax adjustment rider proceeding, discussed above, the adjustments to all other riders affected by the Tax Act and to include an amendment

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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 an electric formula rate plan settlement approved by the LPSC in April 2018 the parties agreed that Entergy Louisiana would return to customers one-half of its eligible unprotected excess deferred income taxes from May 2018 through December 2018 and return to customers the other half from January 2019 through August 2022. In addition, the settlement provided that in order to flow back to customers certain other tax benefits created by the Tax Act, Entergy Louisiana established a regulatory liability effective January 1, 2018 in the amount of $9.1 million per month to reflect these tax benefits already included in retail rates until new base rates under the formula rate plan were established in September 2018, and this regulatory liability was returned to customers over the September 2018 through August 2019 formula rate plan rate-effective period. The LPSC staff and intervenors in the settlement reserved the right to obtain data from Entergy Louisiana to confirm the determination of excess accumulated deferred income taxes resulting from the Tax Act and the analysis thereof as part of the formula rate plan review proceeding for the 2017 test year filing which, as discussed below, Entergy Louisiana filed in June 2018.

Entergy Mississippi

Entergy Mississippi filed its 2018 formula rate plan in March 2018 and included a proposal to return all of its unprotected excess accumulated deferred income taxes to customers through rates or in exchange for other assets, or a combination of both, by the end of 2018. In June 2018 the MPSC approved a stipulation filed by Entergy Mississippi and the Mississippi Public Utilities Staff in Entergy Mississippi’s formula rate plan filing that addressed Entergy Mississippi’s 2018 formula rate plan evaluation report and the ratemaking effects of the Tax Act. The stipulation provided for incorporating the reduction of the statutory federal income tax rate through Entergy Mississippi’s formula rate plan. The stipulation approved in June 2018 provided for the flow-back of protected excess accumulated deferred income taxes over the remaining lives of the assets through the formula rate plan. The stipulation also provided for the offset of unprotected excess accumulated deferred income taxes of $127.2 million against net utility plant and $2.2 million against other regulatory assets, and the return to customers of the remaining balance of unprotected excess accumulated deferred income taxes as recovery of a portion of fuel oil inventory and customer bill credits over a three-month period from July 2018 through September 2018, with an insignificant true-up reflected in the November 2018 power management rider filing. Entergy Mississippi recorded the reduction against net utility plant and other regulatory assets in June 2018. In third quarter 2018, Entergy Mississippi returned unprotected excess accumulated deferred income taxes of $25.8 million through customer bill credits and $5.8 million through the sale of fuel oil inventory.

Entergy New Orleans

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

In March 2018, Entergy New Orleans filed its response to the resolution stating that the Tax Act reduced income tax expense from what was then reflected in rates by approximately $8.2 million annually for electric operations and by approximately $1.3 million annually for gas operations. In the filing, Entergy New Orleans proposed to return to customers from June 2018 through August 2019 the benefits of the reduction in income tax expense and its unprotected excess accumulated deferred income taxes through a combination of bill credits and investments in energy efficiency

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programs, grid modernization, and Smart City projects. Entergy New Orleans submitted supplemental information in April 2018 and May 2018. Shortly thereafter, Entergy New Orleans and the City Council’s advisors reached an agreement in principle that provides for benefits that will be realized by Entergy New Orleans customers through bill credits that started in July 2018 and offsets to future investments in energy efficiency programs, grid modernization, and Smart City projects, as well as additional benefits related to the filings made at the FERC. The agreement in principle was approved by the City Council in June 2018.

Entergy Texas

After enactment of the Tax Act the PUCT issued an order requiring most utilities, including Entergy Texas, beginning January 25, 2018, to record a regulatory liability for the difference between revenues collected under existing rates and revenues that would have been collected had existing rates been set using the new federal income tax rates and also for the balance of excess accumulated deferred income taxes. Entergy Texas had previously provided information to the PUCT staff and stated that it expected the PUCT to address the lower tax expense as part of Entergy Texas’s rate case expected to be filed in May 2018. 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 be credited to customers through a rider to reflect the lower federal income tax rate applicable to Entergy Texas from January 2018 through the date new rates were implemented, 2) $242.5 million of protected excess accumulated deferred income taxes be returned to customers through base rates under the average rate assumption method over the lives of the associated assets, and 3) $185.2 million of unprotected excess accumulated deferred income taxes be returned to customers through a rider. The unprotected excess accumulated deferred income taxes rider includes carrying charges and is in effect over a period of 12 months for larger customers and over a period of four years for other customers.

System Energy

In a filing made with the FERC in March 2018, 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 terminated in April 2019, and the hearing is scheduled for March 2020. The retail regulators of the Utility operating companies that are parties to the Unit Power Sales Agreement are challenging whether there are excess tax liabilities associated with uncertain tax positions related to nuclear decommissioning.

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, 2019 and 2018 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.

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	2019				2018
	(In Millions)
Entergy Arkansas (a)		$14.0				$86.5
Entergy Louisiana (b)		$112.5				$136.7
Entergy Mississippi		($70.4	)			$8.0
Entergy New Orleans (b)		($0.8	)			$2.8
Entergy Texas		($13.0	)			($19.7	)

(a)	Includes $67.7 million in 2019 and $67.3 million in 2018 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.

    

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

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March 31, 2017 pursuant to the tariff. In July 2017 the Arkansas Attorney General requested additional information to support certain of the costs included in Entergy Arkansas’s 2017 energy cost rate redetermination.

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

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

Entergy Louisiana

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

In July 2014 the LPSC authorized its staff to initiate an audit of the fuel adjustment clause filings by Entergy Gulf States Louisiana, whose business was combined with Entergy Louisiana in 2015. The audit includes a review of the reasonableness of charges flowed through Entergy Gulf States Louisiana’s fuel adjustment clause for the period from 2010 through 2013. In January 2019 the LPSC staff consultant issued its audit report. In its report, the LPSC staff consultant recommended that Entergy Louisiana refund approximately $900,000, plus interest, to customers based

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upon the imputation of a claim of vendor fault in servicing its nuclear plant. Entergy Louisiana recorded a provision in the first quarter 2019 for the potential outcome of the audit. In August 2019, Entergy Louisiana filed direct testimony challenging the basis for the LPSC staff’s recommended disallowance and providing an alternative calculation of replacement power costs should it be determined that a disallowance is appropriate. Entergy Louisiana’s calculation would require no refund to customers.

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

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

In June 2016 the LPSC issued notice of audits of Entergy Louisiana’s fuel adjustment clause filings and purchased gas adjustment clause filings for the period 2014 through 2015. In recognition of the business combination that occurred in 2015, the audit notice was issued to Entergy Louisiana and also includes a review of charges to legacy Entergy Gulf States Louisiana customers prior to the business combination. The audits include a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2014 through 2015 and charges flowed through Entergy Louisiana’s purchased gas adjustment clause for the period from 2012 through 2015. 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 January 2017 the MPSC certified to the Mississippi Legislature the audit reports of its independent auditors for the fuel year ending September 30, 2016. In November 2017 the Mississippi Public Utilities Staff separately engaged a consultant to review the September 2016 outage at the Grand Gulf Nuclear Station and to review ongoing operations at Grand Gulf. This engagement continues, and subsequently, was expanded to include all outages at Grand Gulf that occurred through 2019.

In November 2017, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an under-recovery of approximately

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

In November 2018, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an under-recovery of approximately $57 million as of September 30, 2018. In January 2019 the MPSC approved the proposed energy cost factor effective for February 2019 bills.

In November 2019, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an over-recovery of approximately $39.6 million as of September 30, 2019. In January 2020 the MPSC approved the proposed energy cost factor effective for February 2020 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, 2019, Entergy Mississippi has a regulatory asset of $29.5 million for these deferred legal expenses. In April 2019 the District Court remanded the Attorney General’s lawsuit to the Hinds County Chancery Court. A hearing on procedural and dispositive motions was held in August 2019. In December 2019 the Hinds County Chancery Court issued its ruling granting the motion for summary judgment filed by the Entergy defendants. The Chancery Court found it lacked subject matter jurisdiction, and that the claims fall under the purview of the FERC. In February 2020 the Chancery Court entered a final order dismissing all claims. The order was approved by counsel for the Attorney General, and dismisses with prejudice all claims and matters in dispute and states that the plaintiff will not seek an appeal or further relief and that all matters in dispute have been resolved.

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

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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.

    

In September 2019, Entergy Texas filed an application to reconcile its fuel and purchased power costs for the period from April 2016 through March 2019. During the reconciliation period, Entergy Texas incurred approximately $1.6 billion in Texas jurisdictional eligible fuel and purchased power expenses, net of certain revenues credited to such expenses and other adjustments. Entergy Texas estimated an under-recovery balance of approximately $25.8 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning April 2019. The proceeding is currently pending.

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Retail Rate Proceedings

Filings with the APSC (Entergy Arkansas)

Retail Rates

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

2019 Formula Rate Plan Filing

In July 2019, Entergy Arkansas filed with the APSC its 2019 formula rate plan filing to set its formula rate for the 2020 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2020 and a netting adjustment for the historical year 2018.  The total proposed formula rate plan rider revenue change designed to produce a target rate of return on common equity of 9.75% is $15.3 million, which is based upon a deficiency of approximately $61.9 million for the 2020 projected year, netted with a credit of approximately $46.6 million in the 2018 historical year netting adjustment. During 2018 Entergy Arkansas experienced higher-than expected sales volume, and actual costs were lower than forecasted.  These changes, coupled with a reduced income tax rate resulting from the Tax Cuts and Jobs Act, resulted in the credit for the historical year netting adjustment. In the fourth quarter 2018,

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Entergy Arkansas recorded a provision of $35.1 million that reflected the estimate of the historical year netting adjustment that was expected to be included in the 2019 filing. In 2019, Entergy Arkansas recorded additional provisions totaling $11.5 million to reflect the updated estimate of the historical year netting adjustment included in the 2019 filing.  In October 2019 other parties in the proceeding filed their errors and objections requesting certain adjustments to Entergy Arkansas’s filing that would reduce or eliminate Entergy Arkansas’s proposed revenue change. Entergy Arkansas filed its response addressing the requested adjustments in October 2019. In its response, Entergy Arkansas accepted certain of the adjustments recommended by the General Staff of the APSC that would reduce the proposed formula rate plan rider revenue change to $14 million. Entergy Arkansas disputed the remaining adjustments proposed by the parties. In October 2019, Entergy Arkansas filed a unanimous settlement agreement with the other parties in the proceeding seeking APSC approval of a revised total formula rate plan rider revenue change of $10.1 million. In its July 2019 formula rate plan filing, Entergy Arkansas proposed to recover an $11.2 million regulatory asset, amortized over five years, associated with specific costs related to the potential construction of scrubbers at the White Bluff plant. Although Entergy Arkansas does not concede that the regulatory asset lacks merit, for purposes of reaching a settlement on the total formula rate plan rider amount, Entergy Arkansas agreed not to include the White Bluff scrubber regulatory asset cost in the 2019 formula rate plan filing or future filings. Entergy Arkansas recorded a write-off in 2019 of the $11.2 million White Bluff scrubber regulatory asset. In December 2019 the APSC approved the settlement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2020.

Internal Restructuring

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

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

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

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

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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.

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Filings with the LPSC (Entergy Louisiana)

Retail Rates - Electric

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 staff 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.  In April 2018 the LPSC approved an unopposed joint motion filed by Entergy Louisiana and the LPSC staff that settled the matter and 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.

Entergy Louisiana has indicated its intent to seek an extension of its formula rate plan on terms similar to the existing terms.

 

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2017 Formula Rate Plan Filing

In June 2018, Entergy Louisiana filed its formula rate plan evaluation report for its 2017 calendar year operations. The 2017 test year evaluation report produced an earned return on equity of 8.16%, due in large part to revenue-neutral realignments to other recovery mechanisms. Without these realignments, the evaluation report produces an earned return on equity of 9.88% and a resulting base rider formula rate plan revenue increase of $4.8 million. Excluding the Tax Act credits provided for by the tax reform adjustment mechanisms, total formula rate plan revenues were further increased by a total of $98 million as a result of the evaluation report due to adjustments to the additional capacity and MISO cost recovery mechanisms of the formula rate plan, and implementation of the transmission recovery mechanism. In August 2018, Entergy Louisiana filed a supplemental formula rate plan evaluation report to reflect changes from the 2016 test year formula rate plan proceedings, a decrease to the transmission recovery mechanism to reflect lower actual capital additions, and a decrease to evaluation period expenses to reflect the terms of a new power sales agreement. Based on the August 2018 update, Entergy Louisiana recognized a total decrease in formula rate plan revenue of approximately $17.6 million. Results of the updated 2017 evaluation report filing were implemented with the September 2018 billing month subject to refund and review by the LPSC staff and intervenors. In accordance with the terms of the formula rate plan, in September 2018 the LPSC staff and intervenors submitted their responses to Entergy Louisiana’s original formula rate plan evaluation report and supplemental compliance updates. The LPSC staff asserted objections/reservations regarding 1) Entergy Louisiana’s proposed rate adjustments associated with the return of excess accumulated deferred income taxes pursuant to the Tax Act and the treatment of accumulated deferred income taxes related to reductions of rate base; 2) Entergy Louisiana’s reservation regarding treatment of a regulatory asset related to certain special orders by the LPSC; and 3) test year expenses billed from Entergy Services to Entergy Louisiana. Intervenors also objected to Entergy Louisiana’s treatment of the regulatory asset related to certain special orders by the LPSC. A procedural schedule has not yet been established to resolve these issues.

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

Commercial operation at St. Charles Power Station commenced in May 2019. In May 2019, Entergy Louisiana filed an update to its 2017 formula rate plan evaluation report to include the estimated first-year revenue requirement of $109.5 million associated with the St. Charles Power Station. The resulting interim adjustment to rates became effective with the first billing cycle of June 2019.

2018 Formula Rate Plan Filing

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

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

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

Investigation of Costs Billed by Entergy Services

In November 2018 the LPSC issued a notice of proceeding initiating an investigation into costs incurred by Entergy Services that are included in the retail rates of Entergy Louisiana. As stated in the notice of proceeding, the LPSC observed an increase in capital construction-related costs incurred by Entergy Services. Discovery was issued and included efforts to seek highly detailed information on a broad range of matters unrelated to the scope of the audit. There has been no further activity in the investigation since May 2019.

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

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$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.

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. In October 2019 the LPSC staff issued its report finding that Entergy Louisiana’s filing complied with the terms of the rate stabilization plan but recommending an additional refund of $0.7 million related to the Tax Act. 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 made a compliance filing in April 2019 and rates were implemented during the first billing cycle of May 2019, subject to refund and final LPSC review. The proceeding is currently in its discovery phase.

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Gas Rate Stabilization Plan Extension Request

In August 2019, Entergy Louisiana submitted an application to the LPSC seeking extension of the gas rate stabilization plan for the 2019-2021 test years on the same terms as those approved for the 2018 test year. The LPSC established a procedural schedule to address this request with a hearing scheduled in May 2020. Entergy Louisiana and the LPSC staff recently submitted a joint stipulation that recommends approval of the requested extension with certain modifications to the current terms, including a 9.8% evaluation period cost rate for common equity and provisions for the return of the excess accumulated deferred income tax to customers on a dollar for dollar basis in a manner consistent with IRS normalization rules. The LPSC approved the joint stipulation in January 2020.

2019 Rate Stabilization Plan Filing

In January 2020, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2019. The filing of the evaluation report for the test year 2019 reflected an earned return on common equity of 10.78%. This earned return exceeds the earning sharing band of the gas rate stabilization plan leading to a rate reduction of approximately $256 thousand.

Filings with the MPSC (Entergy Mississippi)

Formula Rate Plan Filings

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.

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

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

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.

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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.

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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.

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. 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. In December 2019, Entergy New Orleans filed an application with the City Council seeking approval of an implementation plan for the Energy Smart program from April 2020 through December 2022. Entergy New Orleans proposed to recover the costs of the program through mechanisms previously approved by the City Council or through the energy efficiency cost recovery rider, which was approved in the 2018 combined rate case resolution. In January 2020 the City Council’s advisors recommended that the City Council allow Entergy New Orleans to earn a utility performance incentive of 7% of Energy Smart costs for each year in which Entergy New Orleans achieves 100% of the City Council’s savings targets for Energy Smart. The City Council is expected to decide on the matter in February 2020.

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

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

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

The resolution directed Entergy New Orleans to submit a compliance filing within 30 days of the date of the resolution to facilitate the eventual implementation of rates, including all necessary calculations and conforming rate schedules and riders. The electric formula rate plan rider includes, among other things, 1) a provision for forward-looking adjustments to include known and measurable changes realized up to 12 months after the evaluation period; 2) a decoupling mechanism; and 3) recognition that Entergy New Orleans is authorized to make an in-service adjustment to the formula rate plan to include the non-fuel cost of the New Orleans Power Station in rates, unless the two pending appeals in the New Orleans Power Station proceeding have not concluded. Under this circumstance, Entergy New Orleans shall be permitted to defer the New Orleans Power Station non-fuel costs, including the cost of capital, until Entergy New Orleans commences non-fuel cost recovery. After taking into account the requirements for submission of the compliance filing, the total annual revenue requirement reduction required by the resolution was refined to approximately $45 million ($42 million electric, including $29 million in rider reductions; $3 million gas). In January

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2020 the City Council’s advisors found that the rates calculated by Entergy New Orleans and reflected in the December 2019 compliance filing should be implemented, except with respect to the City Council-approved energy efficiency cost recovery rider, which rider calculation should take into account events to be determined by the City Council in the future. Also in response to the resolution, Entergy New Orleans filed timely a petition for appeal and judicial review and for stay of or injunctive relief alleging that the resolution is unlawful in failing to produce just and reasonable rates. Based on the general acceptance of Entergy New Orleans’s compliance filing, however, during the pendency of its appeal Entergy New Orleans expects to implement the compliance filing rates in April 2020. A hearing on the requested injunction was scheduled in Civil District Court for February 2020, but by joint motion of the City Council and Entergy New Orleans, the Civil District Court issued an order for a limited remand to the City Council to consider a potential agreement in principle/stipulation at its February 20, 2020 meeting. On February 17, 2020, Entergy New Orleans filed with the City Council an agreement in principle between Entergy New Orleans and the City Council’s advisors. On February 20, 2020, the full City Council voted to approve the proposed agreement in principle and issued a resolution modifying the required treatment of certain accumulated deferred income taxes. As a result of the agreement in principle, the total annual revenue requirement reduction will be approximately $45 million ($42 million electric, including $29 million in rider reductions; and $3 million gas). As a result, Entergy New Orleans will fully implement new rates by April 2020. The merits of the appeal will be subject to a separate procedural schedule issued by the Civil District Court.

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.

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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.

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Filings with the PUCT and Texas Cities (Entergy Texas)

Retail Rates

2018 Base Rate Case

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

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

In January 2019, Entergy Texas filed for recovery of rate case expenses totaling $7.2 million. The amounts requested primarily include internal and external expenses related to litigating the 2018 base rate case. Parties filed testimony in April 2019 recommending a disallowance ranging from $3.2 million to $4.2 million of the $7.2 million requested. In May 2019, Entergy Texas filed rebuttal testimony responding to the parties’ positions. In September 2019 an order was issued abating the procedural schedule and scheduled hearing to allow the finalization of a settlement in principle reached among the parties. The settlement provides for a black box disallowance of $1.4 million. In the third quarter 2019, Entergy Texas recorded a provision for the 2018 base rate case expenses based on the settlement in principle. In October 2019 the settlement was filed for review by the PUCT. In February 2020 the PUCT approved the 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.

    

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

Transmission Cost Recovery Factor (TCRF) Rider

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

 

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

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 and identified a number of quantified and unquantified benefits. Entergy Arkansas proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which began in January 2019. Deployment of the communications network began in 2018. 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 is recovering the AMI deployment costs and the quantified benefits through its formula rate plan. Entergy Arkansas will

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recover the undepreciated balance of its existing meters through a regulatory asset to be amortized over 15 years, as approved by the APSC.

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 and identified a number of quantified and unquantified benefits. 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 will recover the undepreciated balance of its existing meters through a regulatory asset to be amortized at current depreciation rates, as approved by the LPSC.

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 and identified a number of quantified and unquantified benefits. Entergy Mississippi proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which began in 2019. 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 and identified a number of quantified and unquantified benefits.  Entergy New Orleans proposed a 15-year depreciable life for the new advanced meters.  Deployment of the information technology infrastructure began in 2017 and deployment of the communications network began in 2018.  Entergy New Orleans proposed to

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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 New Orleans began deployment of AMI during the first quarter of 2019 and expects to complete deployment by the end of 2020. Entergy New Orleans will recover the undepreciated balance of its existing meters through a regulatory asset to be amortized on a straight-line basis over 12 years, as approved by the City Council.

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 and identified a number of quantified and unquantified benefits. Entergy Texas proposed a seven-year depreciable life for the new advanced meters. 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, 2019, 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 the three-year deployment of the advanced meters began in 2019. Entergy Texas will recover the undepreciated balance of its existing meters through a regulatory asset to be amortized at current depreciation rates, as approved by the PUCT.

System Agreement Cost Equalization Proceedings

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

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•	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.

•	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 a separate FERC proceeding, the FERC concluded that this refund ruling would be held in abeyance pending the outcome of the rehearing requests in the other 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 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

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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 argued in favor of such remands and Entergy has opposed the LPSC’s request. In an order issued in November 2019, the FERC ruled that refunds are not appropriate for the 20-month refund period.

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 or briefs opposing exceptions, or both, 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,

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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 May 2019, the FERC accepted the July 2018 compliance filing, and the LPSC sought rehearing of that decision in June 2019. In December 2019 the FERC denied the LPSC’s request for rehearing, and the LPSC appealed the FERC’s prior orders to the D.C. Circuit in January 2020.

In the course of these proceedings the FERC rejected the APSC’s protest that Entergy Arkansas should not be subject to the 2014 compliance 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 compliance filing.

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		$278				$252				$390				$47				$77				$41				$—				$—
Entergy Louisiana		($203	)			($160	)			($247	)			($25	)			($12	)			($41	)			$—				$—
Entergy Mississippi		($34	)			($20	)			($24	)			($21	)			($40	)			$—				$—				$—
Entergy New Orleans		$—				($7	)			$—				($1	)			($25	)			$—				($15	)			($15	)
Entergy Texas		($41	)			($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.

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The following rough production cost equalization rate proceedings are still ongoing.

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):

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	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.

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

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allocation as joint account sales. The FERC reversed the ALJ’s decision that any payments by Entergy Arkansas should be reduced by 20%. The FERC also reversed the ALJ’s decision that adjustments to other System Agreement service schedules and excess bandwidth payments should not be taken into account when calculating the payments to be made by Entergy Arkansas. The FERC held that such adjustments and excess bandwidth payments should be taken into account but ordered further proceedings before an ALJ to address whether a cap on any reduction due to bandwidth payments was necessary and to implement the other adjustments to the calculation methodology.

In May 2016, Entergy Services filed a request for rehearing of the FERC’s April 2016 order arguing that payments made by Entergy Arkansas should be reduced as a result of the timing of the LPSC’s approval of certain contracts. Entergy Services also filed a request for clarification and/or rehearing of the FERC’s April 2016 order addressing the ALJ’s August 2013 initial decision. The APSC and the LPSC also filed requests for rehearing of the FERC’s April 2016 order. In September 2017 the FERC issued an order denying the request for rehearing on the issue of whether any payments by Entergy Arkansas to the other Utility operating companies should be reduced due to the timing of the LPSC’s approval of Entergy Arkansas’s wholesale baseload contract with Entergy Louisiana. In November 2017 the FERC issued an order denying all of the remaining requests for rehearing of the April 2016 order. In November 2017, Entergy Services filed a petition for review in the D.C. Circuit of the FERC’s orders in the first two phases of the opportunity sales case. In December 2017 the D.C. Circuit granted Entergy Services’ request to hold the appeal in abeyance pending final resolution of the related proceeding before the FERC. In January 2018 the APSC and the LPSC filed separate petitions for review in the D.C. Circuit, and the D.C. Circuit consolidated the appeals with Entergy Services’ appeal 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 November 2018 the LPSC requested rehearing of the FERC’s October 2018 decision. In December 2019 the FERC denied the LPSC’s request for rehearing.

In December 2018, Entergy made a compliance filing in response to the FERC’s October 2018 order. The compliance filing provided a final calculation of Entergy Arkansas’s payments to the other Utility operating companies, including interest. No protests were filed in response to the December 2018 compliance filing. The December 2018 compliance filing is pending FERC action. Refunds and interest in the following amounts were paid by Entergy Arkansas to the other operating companies in December 2018:

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	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.

In February 2019 the LPSC filed a new complaint relating to two issues that were raised in the opportunity sales proceeding, but that, in its October 2018 order, the FERC held were outside the scope of the proceeding. In March 2019, Entergy Services filed an answer and motion to dismiss the new complaint. In November 2019 the FERC issued an order denying the LPSC’s complaint. The order concluded that the settlement agreement approved by FERC in December 2015 terminating the System Agreement barred the LPSC’s new complaint.

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

    

Complaints Against System Energy

Return on Equity and Capital Structure Complaints

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

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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 and directed the parties to engage in settlement proceedings before an ALJ. The parties have been unable to settle the return on equity issue and a FERC hearing judge was assigned in July 2018. The 15-month refund period in connection with the APSC/MPSC complaint expired on April 23, 2018.

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

In August 2018 the FERC issued an order dismissing the LPSC’s request to investigate System Energy’s capital structure and setting for hearing the return on equity complaint, with a refund effective date of April 27, 2018. The portion of the LPSC’s complaint dealing with return on equity was subsequently consolidated with the APSC and MPSC complaint for hearing. 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 capital structure complaint, and System Energy submitted a response in October 2018. In January 2019 the FERC set the amended complaint for settlement and hearing proceedings. Settlement proceedings in the capital structure proceeding commenced in February 2019. As noted below, in June 2019 settlement discussions were terminated and the amended capital structure complaint was consolidated with the ongoing return on equity proceeding. The 15-month refund period in connection with the capital structure complaint is from September 24, 2018 to December 23, 2019.

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

In May 2019 the FERC trial staff filed its direct and answering testimony in the return on equity proceeding. For the first refund period, the FERC trial staff calculates an authorized return on equity for System Energy of 9.89% based on the application of FERC’s proposed methodology. The FERC trial staff’s direct and answering testimony noted that an authorized return on equity of 9.89% for the first refund period was within the range of presumptively

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just and reasonable returns on equity for the second refund period, as calculated using a study period ending January 31, 2019 for the second refund period.

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

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

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

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

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

In November 2019, in a proceeding that did not involve Entergy, the FERC issued an order addressing the methodology for determining the return on equity applicable to transmission owners in MISO. Thereafter, the participants in the System Energy proceeding agreed to amend the procedural schedule to allow the participants to file testimony addressing the order in the MISO transmission owner proceeding. Under the new schedule, the hearing in the System Energy proceeding will commence in June 2020 and the initial decision will be due in October 2020.

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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 18, 2018.

In February 2019 the presiding ALJ ruled that the hearing ordered by the FERC includes the issue of whether specific subcategories of accumulated deferred income tax should be included in, or excluded from, System Energy’s formula rate. In March 2019 the LPSC, MPSC, APSC and City Council filed direct testimony. The LPSC testimony seeks refunds that include the renewal lease payments (approximately $17.2 million per year since July 2015), rate base reductions for accumulated deferred income tax associated with uncertain tax positions (claimed to be approximately $334.5 million as of December 2018), and the cost of capital additions associated with the sale-leaseback interest (claimed to be approximately $274.8 million), as well as interest on those amounts. The direct testimony of the City Council and the APSC and MPSC address various issues raised by the LPSC. System Energy disputes that any refunds are owed for billings under the Unit Power Sales Agreement.

In June 2019 System Energy filed answering testimony in the sale-leaseback complaint proceeding arguing that the FERC should reject all claims for refunds.  Among other things, System Energy argued that claims for refunds of the costs of lease renewal payments and capital additions should be rejected because those costs were recovered consistent with the Unit Power Sales Agreement formula rate, System Energy was not over or double recovering any costs, and ratepayers will save approximately $850 million over initial and renewal terms of the leases.  System Energy argued that claims for refunds associated with liabilities arising from uncertain tax positions should be rejected because the liabilities do not provide cost-free capital, the repayment timing of the liabilities is uncertain, and the outcome of the underlying tax positions is uncertain.  System Energy’s testimony also challenged the refund calculations supplied by the other parties.

In August 2019 the FERC trial staff filed direct and answering testimony seeking refunds for rate base reductions for liabilities associated with uncertain tax positions (claimed to be up to approximately $602 million plus interest).

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The FERC trial staff also argued that System Energy recovered $32 million more than it should have in depreciation expense for capital additions. In September 2019, System Energy filed cross-answering testimony disputing the FERC trial staff’s arguments for refunds, stating that the FERC trial staff’s position regarding depreciation rates for capital additions is not unreasonable and explaining that any change in depreciation expense is only one element of a Unit Power Sales Agreement rebilling calculation. Adjustments to depreciation expense in any rebilling under the Unit Power Sales Agreement formula rate will also involve changes to accumulated depreciation, accumulated deferred income taxes, and other formula elements as needed. In October 2019 the LPSC filed rebuttal testimony increasing the amount of refunds sought for liabilities associated with uncertain tax positions.  The LPSC now seeks approximately $512 million plus interest.  At the same time, the FERC trial staff filed rebuttal testimony conceding that it was no longer seeking up to $602 million related to the uncertain tax positions; instead, it is seeking approximately $511 million plus interest.  The LPSC also argued that adjustments to depreciation rates should affect rate base on a prospective basis only.

A hearing was held before a FERC ALJ in November 2019 and the initial decision is due in April 2020.

Unit Power Sales Agreement

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

In September 2017 the FERC accepted System Energy’s proposed Unit Power Sales Agreement amendments, subject to further proceedings to consider the justness and reasonableness of the amendments. Because the amendments 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. 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.

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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

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and remits the collections to the bond indenture trustee.  Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as the billing and collection agent for the state.

Hurricane Katrina and Hurricane Rita

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

In July 2008 the LPFA issued $687.7 million in bonds under the aforementioned Act 55.  From the $679 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $152 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $527 million directly to Entergy Louisiana.  From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $545 million, including $17.8 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 5,449,861.85 Class A preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 10% annual distribution rate.  In August 2008, the LPFA issued $278.4 million in bonds under the aforementioned Act 55.  From the $274.7 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $87 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $187.7 million directly to Entergy Louisiana.  From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $189.4 million, including $1.7 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 1,893,918.39 Class A preferred, non-voting, membership interest units of Entergy Holdings Company LLC that carry a 10% annual distribution rate.  Distributions are payable quarterly commencing on September 15, 2008 and have a liquidation price of $100 per unit.  The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement.  The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion.  

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

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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 July 31, 2017, the balance in Entergy Mississippi’s accumulated storm damage provision was 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. As of May 31, 2019, Entergy Mississippi’s storm damage provision balance was less than $10 million. Accordingly, Entergy Mississippi resumed billing the monthly storm damage provision effective with July 2019 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, 2019, Entergy Louisiana has a regulatory asset of $21.2 million on its balance sheet related to these new nuclear generation development costs.

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Income taxes for 2019, 2018, and 2017 for Entergy Corporation and Subsidiaries consist of the following:

	2019				2018				2017
	(In Thousands)
Current:
Federal		($14,416	)			$36,848				$29,595
State	6,535				7,274				15,478
Total	(7,881		)		44,122				45,073
Deferred and non-current - net	(155,956		)		(1,074,416		)		505,010
Investment tax credit adjustments - net	(5,988		)		(6,532		)		(7,513		)
Income taxes		($169,825	)			($1,036,826	)			$542,570

    

Income taxes for 2019, 2018, and 2017 for Entergy’s Registrant Subsidiaries consist of the following:

2019		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
		(In Thousands)
Current:
Federal			($14,549	)			($20,173	)			($8,939	)			($5,822	)			$16,035				$16,256
State		(714		)		(735		)		5,823				1,856				663				(2,831		)
Total		(15,263		)		(20,908		)		(3,116		)		(3,966		)		16,698				13,425
Deferred and non-current - net		(30,278		)		147,453				34,579				4,248				(69,963		)		422
Investment tax credit adjustments - net		(1,228		)		(4,922		)		(597		)		(96		)		(631		)		1,502
Income taxes			($46,769	)			$121,623				$30,866				$186				($53,896	)			$15,349

2018		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
		(In Thousands)
Current:
Federal			($23,638	)			($15,841	)			($11,275	)			($10,813	)			$16,190				($9,786	)
State		(1,617		)		(1,122		)		(1,066		)		545				3,205				(1,821		)
Total		(25,255		)		(16,963		)		(12,341		)		(10,268		)		19,395				(11,607		)
Deferred and non-current - net		(270,586		)		(32,725		)		(114,738		)		7,943				(44,817		)		(35,329		)
Investment tax credit adjustments - net		(1,226		)		(4,923		)		1,306				(111		)		(821		)		(739		)
Income taxes			($297,067	)			($54,611	)			($125,773	)			($2,436	)			($26,243	)			($47,675	)

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2017		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
		(In Thousands)
Current:
Federal			$16,086				($84,250	)			($8,845	)			($30,635	)			$6,034				$47,674
State		9,191				1,480				(924		)		(728		)		310				5,314
Total		25,277				(82,770		)		(9,769		)		(31,363		)		6,344				52,988
Deferred and non-current - net		69,753				572,988				83,501				62,946				43,102				19,243
Investment tax credit adjustments - net		(1,226		)		(4,920		)		187				1,695				(965		)		(2,262		)
Income taxes			$93,804				$485,298				$73,919				$33,278				$48,481				$69,969

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Total income taxes for Entergy Corporation and Subsidiaries differ from the amounts computed by applying the statutory income tax rate to income before income taxes.  The reasons for the differences for the years 2019, 2018, and 2017 are:

	2019				2018				2017
	(In Thousands)
Net income (loss) attributable to Entergy Corporation		$1,241,226				$848,661				$411,612
Preferred dividend requirements of subsidiaries	17,018				13,894				13,741
Consolidated net income (loss)	1,258,244				862,555				425,353
Income taxes	(169,825		)		(1,036,826		)		542,570
Income (loss) before income taxes		$1,088,419				($174,271	)			$967,923
Computed at statutory rate (21% for 2019 and 2018) (35% for 2017)		$228,568				($36,597	)			$338,773
Increases (reductions) in tax resulting from:
State income taxes net of federal income tax effect	61,791				21,398				44,179
Regulatory differences - utility plant items	(45,336		)		(37,507		)		39,825
Equity component of AFUDC	(30,444		)		(27,216		)		(33,282		)
Amortization of investment tax credits	(8,093		)		(8,304		)		(10,204		)
Flow-through / permanent differences	(2,059		)		439				8,727
Tax legislation enactment (a)	—				—				560,410
Amortization of excess ADIT (a)	(205,614		)		(577,082		)		—
Revisions of the 2017 tax legislation enactment regulatory liability accrual, including the effect of the Entergy Texas 2018 base rate proceeding	—				(40,494		)		—
Utility restructuring (b)	—				(169,918		)		—
Settlement on treatment of regulatory obligations (c)	—				(52,320		)		—
State income tax audit conclusion	—				(23,425		)		—
IRS audit adjustment	—				(8,404		)		—
Entergy Wholesale Commodities nuclear decommissioning trust restructuring (d)	—				(106,833		)		—
Entergy Wholesale Commodities restructuring (d)	(173,725		)		—				(373,277		)
FitzPatrick disposition	—				—				(44,344		)
Charitable contribution (d)	(19,101		)		—				—
Net operating loss recognition	(41,427		)		—				—
Provision for uncertain tax positions	7,332				24,569				8,756
Valuation allowance	59,345				2,211				—
Other - net	(1,062		)		2,657				3,007
Total income taxes as reported		($169,825	)			($1,036,826	)			$542,570
Effective Income Tax Rate	(15.6		%)		595.0		%		56.1		%

(a)	See “Other Tax Matters - Tax Cuts and Jobs Act” below for discussion of the amortization of excess ADIT in 2018 and 2019 and the tax legislation enactment in 2017.

(b)	See “Other Tax Matters - Entergy Arkansas and Entergy Mississippi Internal Restructuring” below for discussion of the Utility restructuring.

(c)	See “Income Tax Audits - 2012-2013 IRS Audit” below for discussion of the settlement.

(d)	See “Other Tax Matters - Entergy Wholesale Commodities Restructuring” below for discussion of the Entergy Wholesale Commodities nuclear decommissioning trust restructuring in 2018, the Entergy Wholesale Commodities restructurings in 2017 and 2019, and the charitable contribution in 2019.

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Total income taxes for the Registrant Subsidiaries differ from the amounts computed by applying the statutory income tax rate to income before taxes.  The reasons for the differences for the years 2019, 2018, and 2017 are:

2019		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
		(In Thousands)
Net income			$262,964				$691,537				$119,925				$52,629				$159,397				$99,120
Income taxes		(46,769		)		121,623				30,866				186				(53,896		)		15,349
Pretax income			$216,195				$813,160				$150,791				$52,815				$105,501				$114,469
Computed at statutory rate (21%)			$45,401				$170,764				$31,666				$11,091				$22,155				$24,039
Increases (reductions) in tax resulting from:
State income taxes net of federal income tax effect		15,954				42,854				5,563				3,443				360				5,134
Regulatory differences - utility plant items		(10,627		)		(19,421		)		(5,556		)		(1,532		)		(1,987		)		(6,213		)
Equity component of AFUDC		(3,255		)		(15,545		)		(1,755		)		(2,088		)		(5,973		)		(1,829		)
Amortization of investment tax credits		(1,201		)		(4,871		)		(160		)		(88		)		(617		)		(1,155		)
Flow-through / permanent differences		696				439				160				(741		)		560				(500		)
Amortization of excess ADIT (b)		(90,921		)		(28,531		)		203				(11,724		)		(69,091		)		(5,550		)
Non-taxable dividend income		—				(26,795		)		—				—				—				—
Provision for uncertain tax positions		(3,517		)		1,519				500				1,672				430				1,300
Other - net		701				1,210				245				153				267				123
Total income taxes as reported			($46,769	)			$121,623				$30,866				$186				($53,896	)			$15,349
Effective Income Tax Rate		(21.6		%)		15.0		%		20.5		%		0.4		%		(51.1		%)		13.4		%

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2018		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
		(In Thousands)
Net income			$252,707				$675,614				$126,078				$53,152				$162,235				$94,109
Income taxes		(297,067		)		(54,611		)		(125,773		)		(2,436		)		(26,243		)		(47,675		)
Pretax income			($44,360	)			$621,003				$305				$50,716				$135,992				$46,434
Computed at statutory rate (21%)			($9,316	)			$130,411				$64				$10,650				$28,558				$9,751
Increases (reductions) in tax resulting from:
State income taxes net of federal income tax effect		(794		)		26,031				(1,747		)		2,322				2,576				2,812
Regulatory differences - utility plant items		(14,916		)		(12,604		)		(4,103		)		(1,502		)		(1,872		)		(2,510		)
Equity component of AFUDC		(3,477		)		(16,784		)		(1,829		)		(1,248		)		(2,042		)		(1,837		)
Amortization of investment tax credits		(1,201		)		(4,871		)		(160		)		(109		)		(808		)		(1,155		)
Flow-through / permanent differences		570				3,203				1,893				(4,222		)		1,038				2,815
Revisions of the 2017 tax legislation enactment regulatory liability accrual, including the effect of the Entergy Texas 2018 base rate proceeding (a)		933				(2,810		)		(556		)		884				(43,799		)		(3,565		)
Amortization of excess ADIT (b)		(271,570		)		(104,313		)		(120,831		)		(9,878		)		(11,519		)		(58,971		)
Settlement on treatment of regulatory obligations (c)		—				(52,320		)		—				—				—				—
IRS audit adjustment		1,290				1,097				1,018				(96		)		524				(12		)
Non-taxable dividend income		—				(26,795		)		—				—				—				—
Provision for uncertain tax positions		724				3,949				240				613				839				4,876
Other - net		690				1,195				238				150				262				121
Total income taxes as reported			($297,067	)			($54,611	)			($125,773	)			($2,436	)			($26,243	)			($47,675	)
Effective Income Tax Rate		669.7		%		(8.8		%)		(41,237.0		%)		(4.8		%)		(19.3		%)		(102.7		%)

---

2017		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
		(In Thousands)
Net income			$139,844				$316,347				$110,032				$44,553				$76,173				$78,596
Income taxes		93,804				485,298				73,919				33,278				48,481				69,969
Pretax income			$233,648				$801,645				$183,951				$77,831				$124,654				$148,565
Computed at statutory rate (35%)			$81,777				$280,576				$64,383				$27,241				$43,629				$51,998
Increases (reductions) in tax resulting from:
State income taxes net of federal income tax effect		11,586				31,927				6,202				2,842				527				5,635
Regulatory differences - utility plant items		7,220				12,168				1,356				619				5,581				12,880
Equity component of AFUDC		(6,458		)		(18,020		)		(3,383		)		(847		)		(2,353		)		(2,221		)
Amortization of investment tax credits		(1,201		)		(4,871		)		(160		)		(124		)		(951		)		(2,896		)
Flow-through / permanent differences		3,098				3,774				1,567				(3,352		)		1,428				(276		)
Tax legislation enactment (b)		(3,090		)		217,258				3,492				6,153				2,981				(69		)
Non-taxable dividend income		—				(44,658		)		—				—				—				—
Provision for uncertain tax positions		200				5,700				228				600				(2,617		)		4,800
Other - net		672				1,444				234				146				256				118
Total income taxes as reported			$93,804				$485,298				$73,919				$33,278				$48,481				$69,969
Effective Income Tax Rate		40.1		%		60.5		%		40.2		%		42.8		%		38.9		%		47.1		%

(a)	See Note 2 to the financial statements for discussion of the Entergy Texas rate case settlement.

(b)	See “Other Tax Matters - Tax Cuts and Jobs Act” below for discussion of the amortization of excess ADIT in 2018 and 2019 and the tax legislation enactment in 2017.

(c)	See “Income Tax Audits - 2012-2013 IRS Audit” below for discussion of the settlement for Entergy Louisiana.

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Significant components of accumulated deferred income taxes and taxes accrued for Entergy Corporation and Subsidiaries as of December 31, 2019 and 2018 are as follows:

 

	2019				2018
	(In Thousands)
Deferred tax liabilities:
Plant basis differences - net		($4,111,761	)			($3,835,211	)
Regulatory assets	(389,573		)		(370,484		)
Nuclear decommissioning trusts/receivables	(1,015,542		)		(1,128,140		)
Pension, net funding	(348,260		)		(307,626		)
Combined unitary state taxes	(11,519		)		(9,440		)
Power purchase agreements	—				(73,335		)
Deferred fuel	(8,360		)		(29,953		)
Other	(445,378		)		(248,997		)
Total	(6,330,393		)		(6,003,186		)
Deferred tax assets:
Nuclear decommissioning liabilities	929,251				1,070,583
Regulatory liabilities	806,777				895,756
Pension and other post-employment benefits	297,272				305,736
Sale and leaseback	102,420				121,473
Compensation	87,355				86,461
Accumulated deferred investment tax credit	56,013				57,643
Provision for allowances and contingencies	126,886				135,631
Power purchase agreements	231,502				—
Unbilled/deferred revenues	(10,218		)		43,762
Net operating loss carryforwards	1,133,197				628,165
Capital losses and miscellaneous tax credits	22,597				20,549
Valuation allowance	(303,307		)		(243,726		)
Other	289,557				125,522
Total	3,769,302				3,247,555
Non-current accrued taxes (including unrecognized tax benefits)	(1,775,638		)		(1,296,928		)
Accumulated deferred income taxes and taxes accrued		($4,336,729	)			($4,052,559	)

Entergy’s estimated tax attributes carryovers and their expiration dates as of December 31, 2019 are as follows:

Carryover Description		Carryover Amount		Year(s) of expiration
Federal net operating losses before 1/1/2018		$9.8 billion		2023-2037
Federal net operating losses - 1/1/2018 forward		$10.7 billion		N/A
State net operating losses		$20.8 billion		2020-2039
Federal and state charitable contributions		$395.8 million		2020-2024
Miscellaneous federal and state credits		$101.1 million		2020-2038

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As a result of the accounting for uncertain tax positions, the amount of the deferred tax assets reflected in the financial statements is less than the amount of the tax effect of the federal and state net operating loss carryovers, tax credit carryovers, and other tax attributes reflected on income tax returns. Entergy evaluates the available positive and negative evidence to estimate whether sufficient future taxable income of the appropriate character will be generated to realize the benefits of existing deferred tax assets. When the evaluation indicates that Entergy will not be able to realize the existing benefits, a valuation allowance is recorded to reduce deferred tax assets to the realizable amount.

Because it is more likely than not that the benefit from certain state net operating loss and other deferred tax assets will not be utilized, valuation allowances totaling $303 million as of December 31, 2019 and $244 million as of December 31, 2018 have been provided on the deferred tax assets related to federal and state jurisdictions in which Entergy does not currently expect to be able to utilize certain separate company tax return attributes, preventing realization of such deferred tax assets.

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Significant components of accumulated deferred income taxes and taxes accrued for the Registrant Subsidiaries as of December 31, 2019 and 2018 are as follows:

2019		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
		(In Thousands)
Deferred tax liabilities:
Plant basis differences - net			($979,033	)			($1,987,025	)			($565,202	)			($133,073	)			($551,365	)			($380,594	)
Regulatory assets		(170,949		)		(79,117		)		(10,528		)		(16,867		)		(59,745		)		(52,662		)
Nuclear decommissioning trusts/receivables		(120,306		)		(113,830		)		—				—				—				(100,621		)
Pension, net funding		(102,685		)		(98,743		)		(27,325		)		(11,859		)		(19,961		)		(21,609		)
Deferred fuel		—				(2,637		)		(609		)		(666		)		(4,380		)		(55		)
Other		(82,682		)		(94,139		)		(27,905		)		(25,909		)		2,059				(7,350		)
Total		(1,455,655		)		(2,375,491		)		(631,569		)		(188,374		)		(633,392		)		(562,891		)
Deferred tax assets:
Regulatory liabilities		250,410				283,507				53,421				33,258				65,602				121,011
Nuclear decommissioning liabilities		111,078				56,300				—				—				—				52,633
Pension and other post-employment benefits		(21,828		)		74,881				(5,844		)		(12,666		)		(15,406		)		(898		)
Sale and leaseback		—				—				—				—				—				102,480
Accumulated deferred investment tax credit		8,285				32,534				2,396				556				2,217				10,025
Provision for allowances and contingencies		5,365				77,298				12,963				24,022				4,024				—
Power purchase agreements		(15,087		)		18,004				1,147				7,961				26				—
Unbilled/deferred revenues		5,897				(28,081		)		4,715				1,428				5,544				—
Compensation		2,550				3,670				1,625				496				1,282				75
Net operating loss carryforwards		112,658				65,178				21,492				5,056				—				—
Capital losses and miscellaneous tax credits		—				—				45				—				—				7,857
Other		12,541				35,401				999				9,027				2,004				3
Total		471,869				618,692				92,959				69,138				65,293				293,186
Non-current accrued taxes (including unrecognized tax benefits)		(199,340		)		(707,714		)		(56,222		)		(235,300		)		(17,314		)		(544,235		)
Accumulated deferred income taxes and taxes accrued			($1,183,126	)			($2,464,513	)			($594,832	)			($354,536	)			($585,413	)			($813,940	)

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2018		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
		(In Thousands)
Deferred tax liabilities:
Plant basis differences - net			($966,791	)			($1,893,831	)			($579,319	)			($135,143	)			($544,282	)			($403,809	)
Regulatory assets		(169,482		)		(74,917		)		(1,732		)		(20,009		)		(57,777		)		(46,627		)
Nuclear decommissioning trusts/receivables		(77,664		)		(71,470		)		—				—				—				(86,882		)
Pension, net funding		(91,962		)		(92,693		)		(24,398		)		(11,885		)		(20,331		)		(18,898		)
Deferred fuel		(5,801		)		(6,974		)		(11,819		)		(1,701		)		(2,835		)		(312		)
Other		(41,025		)		(34,700		)		(13,443		)		(7,640		)		(6,085		)		(4,544		)
Total		(1,352,725		)		(2,174,585		)		(630,711		)		(176,378		)		(631,310		)		(561,072		)
Deferred tax assets:
Regulatory liabilities		247,964				339,126				72,570				40,181				86,032				110,370
Nuclear decommissioning liabilities		99,479				48,738				—				—				—				46,643
Pension and other post-employment benefits		(19,068		)		80,102				(5,405		)		(11,371		)		(14,215		)		(632		)
Sale and leaseback		—				18,999				—				—				—				102,481
Accumulated deferred investment tax credit		8,599				33,928				2,541				579				2,347				9,649
Provision for allowances and contingencies		9,877				81,108				13,412				23,962				5,579				—
Power purchase agreements		(17,223		)		19,385				1,140				12,155				(18		)		—
Unbilled/deferred revenues		7,471				(17,345		)		5,527				636				7,016				—
Compensation		1,708				1,959				1,265				512				995				(260		)
Net operating loss carryforwards		6,338				20,118				4,896				480				261				—
Other		7,977				23,412				1,610				12,181				2,127				4
Total		353,122				649,530				97,556				79,315				90,124				268,255
Non-current accrued taxes (including unrecognized tax benefits)		(85,942		)		(701,666		)		(18,714		)		(226,532		)		(11,349		)		(512,479		)
Accumulated deferred income taxes and taxes accrued			($1,085,545	)			($2,226,721	)			($551,869	)			($323,595	)			($552,535	)			($805,296	)

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The Registrant Subsidiaries’ estimated tax attributes carryovers and their expiration dates as of December 31, 2019 are as follows:

Entergy Arkansas

Entergy Louisiana

Entergy Mississippi

Entergy New Orleans

Entergy Texas

System Energy

Federal net operating losses

$4.4 billion

$4.3 billion

$2 billion

$1.1 billion

$—

$—

Year(s) of expiration

N/A

2035-2037

N/A

2037

N/A

N/A

State net operating losses

$4.5 billion

$5.2 billion

$2.1 billion

$1.2 billion

$—

$—

Year(s) of expiration

2024

2035-2039

2038-2039

2038-2039

N/A

N/A

Misc. federal credits

$—

$5.2 million

$—

$—

$1.9 million

$3.2 million

Year(s) of expiration

N/A

2035-2038

N/A

N/A

2029-2038

2029-2038

State credits

$—

$—

$—

$—

$2.9 million

$13.1 million

Year(s) of expiration

N/A

N/A

N/A

N/A

2026

2020-2023

As a result of the accounting for uncertain tax positions, the amount of the deferred tax assets reflected in the financial statements is less than the amount of the tax effect of the federal and state net operating loss carryovers and tax credit carryovers.

Unrecognized tax benefits

Accounting standards establish a “more-likely-than-not” recognition threshold that must be met before a tax benefit can be recognized in the financial statements.  If a tax deduction is taken on a tax return but does not meet the more-likely-than-not recognition threshold, an increase in income tax liability, above what is payable on the tax return, is required to be recorded.  A reconciliation of Entergy’s beginning and ending amount of unrecognized tax benefits is as follows:

	2019				2018				2017
	(In Thousands)
Gross balance at January 1		$7,181,482				$4,871,846				$3,909,855
Additions based on tax positions related to the current year	731,276				2,276,614				1,120,687
Additions for tax positions of prior years	151,628				506,142				283,683
Reductions for tax positions of prior years	(681,232		)		(274,600		)		(442,379		)
Settlements	—				(198,520		)		—
Gross balance at December 31	7,383,154				7,181,482				4,871,846
Offsets to gross unrecognized tax benefits:
Carryovers and refund claims	(5,831,587		)		(5,957,992		)		(3,945,524		)
Cash paid to taxing authorities	(10,000		)		(10,000		)		(10,000		)
Unrecognized tax benefits net of unused tax attributes, refund claims and payments (a)		$1,541,567				$1,213,490				$916,322

(a)	Potential tax liability above what is payable on tax returns

The balances of unrecognized tax benefits include $2,421 million, $2,161 million, and $1,462 million as of December 31, 2019, 2018, and 2017, respectively, which, if recognized, would lower the effective income tax rates.  Because of the effect of deferred tax accounting, the remaining balances of unrecognized tax benefits of $4,962

---

million, $5,020 million, and $3,410 million as of December 31, 2019, 2018, and 2017, respectively, if disallowed, would not affect the annual effective income tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.

Entergy accrues interest expense, if any, related to unrecognized tax benefits in income tax expense.  Entergy’s December 31, 2019, 2018, and 2017 accrued balance for the possible payment of interest is approximately $48 million, $44 million, and $38 million, respectively. Interest (net-of-tax) of $4 million, $7 million, and $8 million was recorded in 2019, 2018, and 2017, respectively.

A reconciliation of the Registrant Subsidiaries’ beginning and ending amount of unrecognized tax benefits for 2019, 2018, and 2017 is as follows:

2019		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
		(In Thousands)
Gross balance at January 1, 2019			$1,298,662				$2,400,171				$508,765				$686,687				$17,802				$467,487
Additions based on tax positions related to the current year		84,335				28,705				68,594				40,676				2,312				5,496
Additions for tax positions of prior years		20,399				25,090				1,651				489				1,299				2,186
Reductions for tax positions of prior years		(62,154		)		(72,313		)		(12,723		)		(11,079		)		(7		)		(1,838		)
Gross balance at December 31, 2019		1,341,242				2,381,653				566,287				716,773				21,406				473,331
Offsets to gross unrecognized tax benefits:
Loss carryovers		(1,134,187		)		(1,573,257		)		(506,976		)		(445,430		)		(3,944		)		(8,392		)
Unrecognized tax benefits net of unused tax attributes and payments			$207,055				$808,396				$59,311				$271,343				$17,462				$464,939

2018		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
		(In Thousands)
Gross balance at January 1, 2018			($117,716	)			$2,518,457				$15,122				$679,544				$16,399				$445,511
Additions based on tax positions related to the current year (a)		1,430,828				30,577				493,039				2,261				1,978				18,271
Additions for tax positions of prior years		31,612				77,372				3,878				12,972				1,722				7,255
Reductions for tax positions of prior years		(21,619		)		(158,510		)		(3,253		)		(8,081		)		(2,262		)		(3,253		)
Settlements		(24,443		)		(67,725		)		(21		)		(9		)		(35		)		(297		)
Gross balance at December 31, 2018		1,298,662				2,400,171				508,765				686,687				17,802				467,487
Offsets to gross unrecognized tax benefits:
Loss carryovers		(1,173,839		)		(1,597,826		)		(478,268		)		(420,813		)		(3,199		)		(42,228		)
Unrecognized tax benefits net of unused tax attributes and payments			$124,823				$802,345				$30,497				$265,874				$14,603				$425,259

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2017		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
		(In Thousands)
Gross balance at January 1, 2017			$2,503				$2,440,339				$12,206				$166,230				$15,946				$472,372
Additions based on tax positions related to the current year (a)		8,974				32,843				2,105				509,183				1,747				909
Additions for tax positions of prior years		3,682				235,331				1,267				13,364				3,115				1,432
Reductions for tax positions of prior years		(132,875		)		(190,056		)		(456		)		(9,233		)		(4,409		)		(29,202		)
Gross balance at December 31, 2017		(117,716		)		2,518,457				15,122				679,544				16,399				445,511
Offsets to gross unrecognized tax benefits:
Loss carryovers		—				(1,591,907		)		(15,122		)		(441,374		)		(638		)		(12,536		)
Unrecognized tax benefits net of unused tax attributes and payments			($117,716	)			$926,550				$—				$238,170				$15,761				$432,975

(a)

The primary additions for Entergy Mississippi in 2018, and Entergy New Orleans in 2017 are related to the mark-to-market treatment discussed in “Other Tax Matters - Tax Accounting Methods” below. The primary additions for Entergy Arkansas in 2018 are related to the nuclear decommissioning costs treatment and the mark-to-market treatment discussed in “Other Tax Matters - Tax Accounting Methods” below.

The Registrant Subsidiaries’ balances of unrecognized tax benefits included amounts which, if recognized, would have reduced income tax expense as follows:

	December 31,
	2019				2018				2017
	(In Millions)
Entergy Arkansas		$203.3				$85.4				$2.6
Entergy Louisiana		$556.3				$594.0				$575.8
Entergy Mississippi		$1.9				$1.5				$—
Entergy New Orleans		$242.7				$246.2				$31.7
Entergy Texas		$5.7				$5.1				$4.4
System Energy		$—				$—				$—

Accrued balances for the possible payment of interest related to unrecognized tax benefits are as follows:

	December 31,
	2019				2018				2017
	(In Millions)
Entergy Arkansas		$3.1				$1.7				$1.6
Entergy Louisiana		$14.2				$17.9				$14.1
Entergy Mississippi		$1.7				$1.2				$1.0
Entergy New Orleans		$4.7				$2.7				$2.1
Entergy Texas		$1.1				$0.9				$0.4
System Energy		$14.5				$13.2				$8.5

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The Registrant Subsidiaries record interest and penalties related to unrecognized tax benefits in income tax expense.  No penalties were recorded in 2019, 2018, and 2017. Interest (net-of-tax) was recorded as follows:

	2019				2018				2017
	(In Millions)
Entergy Arkansas		$1.4				$0.2				$0.2
Entergy Louisiana		($3.7	)			$3.8				$5.7
Entergy Mississippi		$0.5				$0.2				$0.2
Entergy New Orleans		$2.0				$0.6				$0.6
Entergy Texas		$0.2				$0.5				($0.8	)
System Energy		$1.3				$4.7				$4.8

Income Tax Audits

Entergy and its subsidiaries file U.S. federal and various state and foreign income tax returns.  IRS examinations are complete for years before 2014. All state taxing authorities’ examinations are complete for years before 2015. Entergy regularly negotiates with the IRS to achieve settlements.  The resolution of audit issues could result in significant changes to the amounts of unrecognized tax benefits in the next twelve months.

2012-2013 IRS Audit

The IRS completed its examination of the 2012 and 2013 tax years and issued its 2012-2013 Revenue Agent Report (RAR) in June 2018. Entergy agreed to all proposed adjustments contained in the RAR. Entergy and the Registrant Subsidiaries recorded the effects of these adjustments in June 2018.

As a result of the issuance of the RAR, Entergy Louisiana was able to recognize previously unrecognized tax benefits of $52 million related to the Hurricane Katrina and Hurricane Rita contingent sharing obligation associated with the Louisiana Act 55 financing.

2014-2015 IRS Audit

The IRS is examining the 2014 and 2015 tax years. Entergy expects the IRS to complete this examination in 2020. As of December 31, 2019, Entergy has not received any proposed adjustments to taxable income from the IRS.

Other Tax Matters

Tax Cuts and Jobs Act

Deferred tax liabilities and assets have been adjusted for the effect of the enactment of the Tax Cuts and Jobs Act (the Act), signed by President Trump on December 22, 2017. The most significant effect of the Act for Entergy and the Registrant Subsidiaries was the change in the federal corporate income tax rate from 35% to 21%, effective January 1, 2018. Other significant provisions and their effect on Entergy and the Registrant Subsidiaries are summarized below.

The Act limits the deduction for net business interest expense to 30 percent of adjusted taxable income which is similar to earnings before interest, taxes, depreciation, and amortization. The limitation does not apply to interest expense that is properly allocable to a trade or business that furnishes or sells electrical energy, gas, or steam through a local distribution system, or transports gas or steam by pipeline if the rates for such furnishing or sale are subject to ratemaking by a government entity or instrumentality or by a public utility commission.

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The IRS issued proposed regulations relating to this limitation in November 2018. The regulations are generally proposed to be effective for taxable years ending after the date Treasury adopts the regulations as final. Taxpayers may apply the rules of the proposed regulations to a taxable year beginning after December 31, 2017, so long as taxpayers consistently apply the rules of the proposed regulations. The proposed regulations provide guidance that if 90% of a tax group’s consolidated assets consist of utility property, the entire consolidated tax group will be treated as a regulated public utility and all of the consolidated group’s interest expense will be currently tax deductible.

As a result of the limitation under the Act, Entergy recorded limitations in 2018 and 2019 and recorded a deferred tax asset on the nondeductible portion, as it has an unlimited carryover period. Entergy recorded a valuation allowance of $24 million due to a lack of earnings from sources other than the Utility.

The Act limits the net operating loss (NOL) deduction for a given year to 80% of taxable income, effective with respect to losses arising in tax years beginning after December 31, 2017. Only NOLs generated after December 31, 2017 are subject to the 80% limitation. Prior law generally provided a two-year carryback and 20-year carryforward for NOLs. The Act does not allow a carryback period but does provide for the indefinite carryforward of NOLs arising in tax years ending after December 31, 2017. Because of the indefinite carryforward, the new limitations on NOL utilization are not expected to have a material effect on Entergy or the Registrant Subsidiaries.

The Act also modified Internal Revenue Code section 162(m), which limits the deduction for compensation with respect to certain covered employees to no more than $1 million per year.  The IRS issued proposed regulations relating to this limitation in December 2019. The significant provisions of the Act and associated proposed regulations require inclusion of performance-based compensation and an expanded definition of “covered employees” in the annual computation of the section 162 limitation. The Act amendments and associated proposed regulations resulted in an increase in disallowed compensation expense, but this limitation does not have a material effect on Entergy or the Registrant Subsidiaries.

With respect to the federal corporate income tax rate change from 35% to 21%, Entergy and the Registrant Subsidiaries recorded a regulatory liability associated with the decrease in the net accumulated deferred income tax liability, which is often referred to as “excess ADIT,” a significant portion of which has been paid to customers in 2018 and 2019 in the form of lower rates. Entergy’s December 31, 2019 and December 31, 2018 balance sheets reflect a regulatory liability of $1.7 billion and $2.1 billion, respectively, as a result of the re-measurement of deferred tax assets and liabilities from the income tax rate change, amortization of excess ADIT, and payments to customers during 2018 and 2019. Entergy’s regulatory liability for income taxes includes a gross-up at the applicable tax rate because of the effect that excess ADIT has on the ratemaking formula. The regulatory liability for income taxes includes the effect of a) the reduction of the net deferred tax liability resulting in excess ADIT, b) the tax gross-up of excess ADIT, and c) the effect of the new tax rate on the previous net regulatory asset for income taxes. For the same reasons, the Registrant Subsidiaries’ December 31, 2019 and December 31, 2018 balance sheets reflect net regulatory liabilities for income taxes as follows:

	2019				2018
	(In Millions)
Entergy Arkansas		$487				$605
Entergy Louisiana		$531				$612
Entergy Mississippi		$237				$246
Entergy New Orleans		$59				$86
Entergy Texas		$253				$352
System Energy		$143				$163

Excess ADIT is generally classified into two categories: 1) the portion that is subject to the normalization requirements of the Act, i.e., “protected”, and 2) the portion that is not subject to such normalization provisions, referred to as “unprotected”. The Act provides that the normalization method of accounting for income taxes is required for

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excess ADIT associated with public utility property. The Act provides for the use of the average rate assumption method (ARAM) for the determination of the timing of the return of excess ADIT associated with such property. Under ARAM, the excess ADIT is reduced over the remaining life of the asset. Remaining asset lives vary for each Registrant Subsidiary, but the average life of public utility property is typically 30 years or longer. Entergy will amortize the protected portion of the excess ADIT in conformity with the normalization requirements. The Registrant Subsidiaries’ net regulatory liability for income taxes as of December 31, 2019 and December 31, 2018, includes protected excess ADIT as follows:

	2019				2018
	(In Millions)
Entergy Arkansas		$490				$521
Entergy Louisiana		$797				$812
Entergy Mississippi		$261				$271
Entergy New Orleans		$62				$59
Entergy Texas		$228				$237
System Energy		$186				$202

During the second quarter of 2018, the Registrant Subsidiaries began paying unprotected excess accumulated deferred income taxes, associated with the effects of the Act, to their customers through rate riders and other means approved by their respective regulatory commissions. Payment of the unprotected excess accumulated deferred income taxes results in a reduction in the regulatory liability for income taxes and a corresponding reduction in income tax expense. This has a significant effect on the effective tax rate for the period as compared to the statutory tax rate. The Registrant Subsidiaries’ net regulatory liability for income taxes as of December 31, 2019 and December 31, 2018, includes unprotected excess ADIT as follows:

	2019				2018
	(In Millions)
Entergy Arkansas		$9				$117
Entergy Louisiana		$242				$295
Entergy New Orleans		$9				$25
Entergy Texas		$83				$171
System Energy		$—				$4

The return of unprotected excess accumulated deferred income taxes reduced Entergy’s and the Registrant Subsidiaries’ regulatory liability for income taxes as follows for 2019 and 2018:

	2019				2018
	(In Millions)
Entergy		$273				$776
Entergy Arkansas		$126				$368
Entergy Louisiana		$39				$141
Entergy Mississippi		$—				$159
Entergy New Orleans		$14				$13
Entergy Texas		$87				$15
System Energy		$7				$80

In addition to the protected and unprotected excess ADIT amounts, the net regulatory liability for income taxes includes other regulatory assets and liabilities for income taxes associated with AFUDC, which is described in Note 1 to the financial statements.

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For a discussion of the proceedings commenced or other responses by Entergy’s regulators to the Act, see Note 2 to the financial statements.

Not all of Entergy’s excess ADIT is included in ratemaking. Consequently, Entergy recorded a net decrease in deferred tax assets of $560 million for which there was a corresponding charge to income tax expense for the year ended December 31, 2017. The corresponding income tax expense (or benefit) recorded by the Registrant Subsidiaries was as follows: Entergy Arkansas, ($3 million); Entergy Louisiana, $217 million; Entergy Mississippi, $3 million; Entergy New Orleans, $6 million; Entergy Texas, $3 million; and System Energy, $0.

Included in the effect of the computation of the changes in deferred tax assets and liabilities is the recognition threshold and measurement of uncertain tax positions resulting in unrecognized tax benefits. The final economic outcome of such unrecognized tax benefits is generally the result of a negotiated settlement with the IRS that often differs from the amount that is recorded as realizable under GAAP. The intrinsic uncertainty with respect to all such tax positions means that the difference between current estimates of such amounts likely to be realized and actual amounts realized upon settlement may have an effect on income tax expense and the regulatory liability for income taxes in future periods.

Entergy anticipates that the Act, including the federal corporate income tax rate change, may continue to have ramifications that require adjustments in the future as certain events occur. These events include: 1) the evaluation by regulators in all of Entergy’s jurisdictions regarding the ratemaking treatment of the Act and excess ADIT; 2) IRS audit adjustments to or amendments of federal and state income tax returns that include modifications to the computation of taxable income resulting from the Act; and 3) additional guidance, interpretations, or rulings by the U.S. Department of the Treasury or the IRS. The potential exists for these types of events to result in future tax expense adjustments because of the difference in the federal corporate income tax rate between past and future periods and the effect of the tax rate change on ratemaking. In turn, these items also could potentially affect the regulatory liability for income taxes.

Entergy Wholesale Commodities Restructuring

The tax classification of the entity that owned FitzPatrick changed in the second quarter 2016.  The change in tax classification required Entergy to recognize the plant’s nuclear decommissioning liability for income tax purposes resulting in a tax accounting permanent difference that reduced income tax expense, net of unrecognized tax benefits, by $238 million. The accrual of the nuclear decommissioning liability also required Entergy to recognize a gain for income tax purposes, a significant portion of which resulted in an increase in tax basis of the assets. Recognition of the gain and the increase in tax basis of the assets represents a tax accounting temporary difference. Entergy sold FitzPatrick on March 31, 2017. The removal of the contingencies regarding the sale of the plant and the receipt of NRC approval for the sale allowed Entergy to re-determine the plant’s tax basis. The re-determined basis resulted in a $44 million income tax benefit in the first quarter 2017.

In the second quarter 2017, Entergy changed the tax classification of legal entities that own Entergy Wholesale Commodities nuclear power plants. The change in tax classification required Entergy to recognize the plants’ nuclear decommissioning liabilities for income tax purposes resulting in a tax accounting permanent difference that reduced income tax expense, net of unrecognized tax benefits, by $373 million. The accrual of the nuclear decommissioning liabilities also required Entergy to recognize a gain for income tax purposes, a portion of which resulted in an increase in tax basis of the assets. Recognition of the gain and the increase in tax basis of the assets represents a tax accounting temporary difference.

In the third quarter 2018, Entergy completed a restructuring of the investment holdings in one of the Entergy Wholesale Commodities nuclear plant decommissioning trusts that resulted in an adjustment to tax basis for the trust. The accounting standards provide that a taxable temporary difference does not exist if the tax law provides a means by which an amount can be recovered without incurrence of tax. The restructuring allows Entergy to recover assets from the trust without incurring tax. As such, the tax basis recognized resulted in the reversal of a deferred tax liability and reduction of income tax expense of approximately $107 million.

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In the fourth quarter 2019, two separate events occurred resulting in a reduction of tax expense of $174 million. In November 2019 an Entergy Wholesale Commodities subsidiary recognized a reduction in income tax expense of $18 million in connection with the accounting method on power contracts associated with the Palisades nuclear power station. Additionally, Entergy’s ownership of Indian Point 2 and Indian Point 3 was restructured. The restructuring required Entergy to recognize Indian Point 2 and Indian Point 3 nuclear decommissioning liabilities for income tax purposes resulting in a tax accounting permanent difference that reduced income tax expense, net of unrecognized tax benefits, by $156 million. The accrual of the nuclear decommissioning liabilities also required Entergy to recognize a gain for income tax purposes, a portion of which resulted in an increase in the tax basis of the assets. Recognition of the gain and the increase in the tax basis of the assets represents a tax accounting temporary difference.

Immediately prior to the restructuring, through its ownership of Indian Point 2 and Indian Point 3, Entergy donated property to Stony Brook University and recognized an associated tax deduction resulting in a decrease to tax expense of $19 million.

Entergy Wholesale Commodities Tax Audit

A state income tax audit involving Entergy Wholesale Commodities was concluded during the third quarter 2018. Upon conclusion of the audit, subsidiaries within Entergy Wholesale Commodities reversed a portion of the provision for uncertain tax positions totaling approximately $23 million, net of tax and interest paid.

Tax Accounting Methods

In the fourth quarter 2015, System Energy and Entergy Louisiana adopted a new method of accounting for income tax return purposes in which their nuclear decommissioning costs will be treated as production costs of electricity includable in cost of goods sold. The new method resulted in a reduction of taxable income of $1.2 billion for System Energy and $2.2 billion for Energy Louisiana. In the fourth quarter 2018, Entergy Arkansas adopted the same method of accounting for its nuclear decommissioning costs which resulted in a $2.2 billion reduction in taxable income.

In 2016, Entergy Louisiana elected mark-to-market income tax treatment for various wholesale electric power purchase and sale agreements, including Entergy Louisiana’s contract to purchase electricity from the Vidalia hydroelectric facility and from System Energy under the Unit Power Sales Agreement. The election resulted in a $2.2 billion deductible temporary difference. In 2017, Entergy New Orleans also elected mark-to-market income tax treatment for wholesale electric contracts which resulted in a $1.1 billion deductible temporary difference. In 2018, Entergy Arkansas and Entergy Mississippi accrued deductible temporary differences related to mark-to-market tax accounting for wholesale electric contracts of $2.1 billion and $1.9 billion, respectively.

Entergy Arkansas and Entergy Mississippi Internal Restructuring

In the fourth quarter 2018, Entergy Arkansas and Entergy Mississippi became wholly-owned subsidiaries of Entergy Utility Holding Company, LLC. The change in ownership required Entergy to recognize Entergy Arkansas’s nuclear decommissioning liabilities for income tax purposes resulting in a tax accounting permanent difference that reduced income tax expense, net of unrecognized tax benefits, by $165 million. The accrual of the nuclear decommissioning liabilities also required Entergy to recognize a gain for income tax purposes, a portion of which resulted in an increase in the tax basis of the assets. Recognition of the gain and the increase in the tax basis of the assets represents a tax accounting temporary difference. Additionally, Entergy recorded a $5 million reduction of income tax expense associated with state income tax effects resulting in a total reduction of income tax expense of $170 million from the restructuring. Entergy recorded a regulatory liability of $40 million ($30 million net-of-tax) which partially offsets the reduction of income tax expense. Entergy Arkansas’s member’s equity increased by $94 million as a result of the restructuring. See Note 2 to the financial statements for further discussion of the internal restructuring.

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Arkansas Corporate Income Tax Rate Reduction

In April 2019 the state of Arkansas enacted corporate income tax law changes that phase in an Arkansas tax rate reduction from the current rate of 6.5% to 6.2% in 2021 and 5.9% in 2022.  The rate reduction will eventually reduce Entergy Arkansas’s combined federal and state applicable tax rate by less than 0.5% once fully adopted.  As a result of the rate reduction, Entergy Arkansas recorded a regulatory liability for income taxes of approximately $25 million which includes a tax gross-up related to the treatment of income taxes in the ratemaking formula. The Arkansas tax law enactment also phases in an increase to the net operating loss carryover period from five to ten years.

Consolidated Income Tax Return of Entergy Corporation

In September 2019, Entergy Utility Holding Company, LLC and its regulated, wholly-owned subsidiaries including Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, became eligible to and joined the Entergy Corporation consolidated federal income tax group.  As a result of these four Utility operating companies re-joining the Entergy Corporation consolidated tax return group, Entergy was able to recognize a $41 million deferred tax asset associated with a previously unrecognized Arkansas net operating loss carryover.

Additionally, in September 2019, Entergy Texas issued $35 million of 5.375% Series A preferred stock with a liquidation value of $25 per share resulting in the disaffiliation and de-consolidation of Entergy Texas from the consolidated federal income tax return of Entergy Corporation.  These changes will not affect the accrual or allocation of income taxes for the Registrant Subsidiaries. See Note 6 to the financial statements for discussion of the preferred stock issuance.

Vermont Yankee

The Vermont Yankee transaction resulted in Entergy generating a net deferred tax asset in January 2019.  The deferred tax asset could not be fully realized by Entergy in the first quarter of 2019; accordingly, Entergy accrued a net tax expense of $29 million on the disposition of Vermont Yankee. See Note 14 to the financial statements for discussion of the Vermont Yankee transaction.

Entergy Corporation has in place a credit facility that has a borrowing capacity of $3.5 billion and expires in September 2024.  The facility includes fronting commitments for the issuance of letters of credit against $20 million of the total borrowing capacity of the credit facility.  The commitment fee is currently 0.225% of the undrawn commitment amount.  Commitment fees and interest rates on loans under the credit facility can fluctuate depending on the senior unsecured debt ratings of Entergy Corporation.  The weighted average interest rate for the year ended December 31, 2019 was 3.77% on the drawn portion of the facility.  Following is a summary of the borrowings outstanding and capacity available under the facility as of December 31, 2019.

Capacity		Borrowings		Letters of Credit		Capacity Available
(In Millions)
$3,500		$440		$6		$3,054

Entergy Corporation’s credit facility requires Entergy to maintain a consolidated debt ratio, as defined, of 65% or less of its total capitalization.  Entergy is in compliance with this covenant.  If Entergy fails to meet this ratio, or if Entergy Corporation or one of the Utility operating companies (except Entergy New Orleans) defaults on other indebtedness or is in bankruptcy or insolvency proceedings, an acceleration of the facility maturity date may occur.

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Entergy Corporation has a commercial paper program with a Board-approved program limit of up to $2 billion.  As of December 31, 2019, Entergy Corporation had $1.947 billion of commercial paper outstanding.  The weighted-average interest rate for the year ended December 31, 2019 was 2.71%.

Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each had credit facilities available as of December 31, 2019 as follows:

Company		Expiration Date		Amount of Facility		Interest Rate (a)		Amount Drawn as of December 31, 2019		Letters of Credit Outstanding as of December 31, 2019
Entergy Arkansas		April 2020		$20 million (b)		2.92%		—		—
Entergy Arkansas		September 2024		$150 million (c)		2.92%		—		—
Entergy Louisiana		September 2024		$350 million (c)		2.92%		—		—
Entergy Mississippi		May 2020		$10 million (d)		3.30%		—		—
Entergy Mississippi		May 2020		$35 million (d)		3.30%		—		—
Entergy Mississippi		May 2020		$37.5 million (d)		3.30%		—		—
Entergy New Orleans		November 2021		$25 million (c)		2.92%		$20 million		$0.8 million
Entergy Texas		September 2024		$150 million (c)		3.30%		—		$1.3 million

(a)	The interest rate is the estimated interest rate as of December 31, 2019 that would have been applied to outstanding borrowings under the facility.

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

(c)	The credit facility includes fronting commitments for the issuance of letters of credit against a portion of the borrowing capacity of the facility as follows: $5 million for Entergy Arkansas; $15 million for Entergy Louisiana; $10 million for Entergy New Orleans; and $30 million for Entergy Texas.

(d)	Borrowings under the Entergy Mississippi credit facilities may be secured by a security interest in its accounts receivable at Entergy Mississippi’s option.

The commitment fees on the credit facilities range from 0.075% to 0.225% of the undrawn commitment amount. Each of the credit facilities requires the Registrant Subsidiary borrower to maintain a debt ratio, as defined, of 65% or less of its total capitalization. Each Registrant Subsidiary is in compliance with this covenant.

In addition, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each entered into one or more uncommitted standby letter of credit facilities as a means to post collateral to support its obligations to MISO. Following is a summary of the uncommitted standby letter of credit facilities as of December 31, 2019:

Company		Amount of Uncommitted Facility		Letter of Credit Fee		Letters of Credit Issued as of December 31, 2019 (a)
Entergy Arkansas		$25 million		0.70%		$1.0 million
Entergy Louisiana		$125 million		0.70%		$12.3 million
Entergy Mississippi		$64 million		0.70%		$1.8 million
Entergy New Orleans		$15 million		1.00%		$5.6 million
Entergy Texas		$50 million		0.70%		$12.1 million

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(a)	As of December 31, 2019, letters of credit posted with MISO covered financial transmission right exposure of $0.2 million for Entergy Mississippi. See Note 15 to the financial statements for discussion of financial transmission rights.

The short-term borrowings of the Registrant Subsidiaries are limited to amounts authorized by the FERC.  The current FERC-authorized limits for Entergy New Orleans are effective through October 31, 2021. The current FERC-authorized limits for Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy Texas, and System Energy are effective through November 8, 2020. In addition to borrowings from commercial banks, these companies may also borrow from the Entergy System money pool and from other internal short-term borrowing arrangements.  The money pool and the other internal borrowing arrangements are inter-company borrowing arrangements designed to reduce the Utility subsidiaries’ dependence on external short-term borrowings.  Borrowings from internal and external short-term borrowings combined may not exceed the FERC-authorized limits.  The following are the FERC-authorized limits for short-term borrowings and the outstanding short-term borrowings as of December 31, 2019 (aggregating both internal and external short-term borrowings) for the Registrant Subsidiaries:

	Authorized		Borrowings
	(In Millions)
Entergy Arkansas	$250		$22
Entergy Louisiana	$450		$83
Entergy Mississippi	$175		—
Entergy New Orleans	$150		—
Entergy Texas	$200		—
System Energy	$200		—

Vermont Yankee Asset Retirement Management, LLC Credit Facility

In January 2019, Entergy Nuclear Vermont Yankee was transferred to NorthStar and its credit facility was assumed by Vermont Yankee Asset Retirement Management, LLC, Entergy Nuclear Vermont Yankee’s parent company that remains an Entergy subsidiary after the transfer. The credit facility has a borrowing capacity of $139 million and expires in December 2021. The commitment fee is currently 0.20% of the undrawn commitment amount.  As of December 31, 2019, $139 million in cash borrowings were outstanding under the credit facility.  The weighted average interest rate for the year ended December 31, 2019 was 3.93% on the drawn portion of the facility. See Note 14 to the financial statements for discussion of the transfer of Entergy Nuclear Vermont Yankee to NorthStar.

Variable Interest Entities (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)

See Note 17 to the financial statements for a discussion of the consolidation of the nuclear fuel company variable interest entities (VIE).  To finance the acquisition and ownership of nuclear fuel, the nuclear fuel company VIEs have credit facilities and three of the four VIEs also issue commercial paper, details of which follow as of December 31, 2019:

Company		Expiration Date		Amount of Facility		Weighted Average Interest Rate on Borrowings (a)		Amount Outstanding as of December 31, 2019
		(Dollars in Millions)
Entergy Arkansas VIE		September 2021		$80		3.33%		$15.1
Entergy Louisiana River Bend VIE		September 2021		$105		3.23%		$70.3
Entergy Louisiana Waterford VIE		September 2021		$105		3.30%		$49.9
System Energy VIE		September 2021		$120		3.34%		$31.6

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(a)	Includes letter of credit fees and bank fronting fees on commercial paper issuances by the nuclear fuel company variable interest entities for Entergy Arkansas, Entergy Louisiana, and System Energy. The nuclear fuel company variable interest entity for Entergy Louisiana River Bend does not issue commercial paper, but borrows directly on its bank credit facility.

The commitment fees on the credit facilities are 0.10% of the undrawn commitment amount for the Entergy Arkansas, Entergy Louisiana, and System Energy VIEs. Each credit facility requires the respective lessee of nuclear fuel (Entergy Arkansas, Entergy Louisiana, or Entergy Corporation as guarantor for System Energy) to maintain a consolidated debt ratio, as defined, of 70% or less of its total capitalization.

The nuclear fuel company variable interest entities had notes payable that are included in debt on the respective balance sheets as of December 31, 2019 as follows:

Company		Description		Amount
Entergy Arkansas VIE		3.65% Series L due July 2021		$90 million
Entergy Arkansas VIE		3.17% Series M due December 2023		$40 million
Entergy Louisiana River Bend VIE		3.38% Series R due August 2020		$70 million
Entergy Louisiana Waterford VIE		3.92% Series H due February 2021		$40 million
Entergy Louisiana Waterford VIE		3.22% Series I due December 2023		$20 million
System Energy VIE		3.42% Series J due April 2021		$100 million

In accordance with regulatory treatment, interest on the nuclear fuel company variable interest entities’ credit facilities, commercial paper, and long-term notes payable is reported in fuel expense.

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Long-term debt for Entergy Corporation and subsidiaries as of December 31, 2019 and 2018 consisted of:

Type of Debt and Maturity		Weighted Average Interest Rate December 31, 2019		Interest Rate Ranges at December 31,				Outstanding at  December 31,
				2019		2018		2019				2018
								(In Thousands)
Mortgage Bonds
2019-2023		3.65%		2.55%-5.10%		2.55%-7.125%			$2,400,000				$3,050,000
2024-2028		3.59%		2.40%-5.59%		2.40%-5.59%		4,610,000				4,610,000
2029-2039		4.05%		3.05%-4.52%		3.05%-4.52%		1,890,000				1,190,000
2044-2066		4.63%		3.55%-5.625%		4.20%-5.625%		5,170,000				3,560,000
Governmental Bonds (a)
2021-2022		2.48%		2.375%-2.50%		2.375%-5.875%		179,000				179,000
2028-2030		3.45%		3.375%-3.50%		3.375%-3.50%		198,680				198,680
Securitization Bonds
2021-2027		3.73%		2.04%-5.93%		2.04%-5.93%		302,145				429,118
Variable Interest Entities Notes Payable (Note 4)
2020-2023		3.41%		3.17%-3.92%		3.17%-3.92%		360,000				360,000
Entergy Corporation Notes
due September 2020		n/a		5.125%		5.125%		450,000				450,000
due July 2022		n/a		4.00%		4.00%		650,000				650,000
due September 2026		n/a		2.95%		2.95%		750,000				750,000
Entergy New Orleans Unsecured Term Loan		n/a		3.00%		—		70,000				—
5 Year Credit Facility (Note 4)		n/a		3.77%		3.60%		440,000				220,000
Entergy New Orleans Credit Facility (Note 4)		n/a		2.92%		—		20,000				—
Vermont Yankee Credit Facility (Note 4)		n/a		3.93%		3.50%		139,000				139,000
Entergy Arkansas VIE Credit Facility (Note 4)		n/a		3.33%		3.48%		15,100				59,600
Entergy Louisiana River Bend VIE Credit Facility (Note 4)		n/a		3.23%		3.44%		70,300				38,600
Entergy Louisiana Waterford VIE Credit Facility (Note 4)		n/a		3.30%		3.35%		49,900				82,000
System Energy VIE Credit Facility (Note 4)		n/a		3.34%		3.44%		31,600				113,900
Long-term DOE Obligation (b)		—		—		—		191,114				186,864
Grand Gulf Sale-Leaseback Obligation		n/a		—		—		34,346				34,352
Unamortized Premium and Discount - Net								(16,124		)		(14,784		)
Unamortized Debt Issuance Costs								(143,502		)		(130,612		)
Other								12,096				12,594
Total Long-Term Debt								17,873,655				16,168,312
Less Amount Due Within One Year								795,012				650,009
Long-Term Debt Excluding Amount Due Within One Year									$17,078,643				$15,518,303
Fair Value of Long-Term Debt									$19,059,950				$16,101,455

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(a)	Consists of pollution control revenue bonds and environmental revenue bonds, some of which are secured by collateral mortgage bonds.

(b)

Pursuant to the Nuclear Waste Policy Act of 1982, Entergy’s nuclear owner/licensee subsidiaries have contracts with the DOE for spent nuclear fuel disposal service.  The contracts include a one-time fee for generation prior to April 7, 1983.  Entergy Arkansas is the only Entergy company that generated electric power with nuclear fuel prior to that date and includes the one-time fee, plus accrued interest, in long-term debt.

The annual long-term debt maturities (excluding lease obligations and long-term DOE obligations) for debt outstanding as of December 31, 2019, for the next five years are as follows:

	Amount
	(In Thousands)
2020		$795,000
2021		$1,358,159
2022		$1,104,289
2023		$1,865,154
2024		$1,175,000

Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy Texas, and System Energy have obtained long-term financing authorizations from the FERC that extend through November 2020.  Entergy New Orleans has obtained long-term financing authorization from the FERC and the City Council that extends through October 2021. Entergy Arkansas has also obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2020.

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Long-term debt for the Registrant Subsidiaries as of December 31, 2019 and 2018 consisted of:

		2019				2018
		(In Thousands)
Entergy Arkansas
Mortgage Bonds:
3.75% Series due February 2021			$350,000				$350,000
3.05% Series due June 2023		250,000				250,000
3.7% Series due June 2024		375,000				375,000
3.5% Series due April 2026		600,000				600,000
4.0% Series due June 2028		250,000				250,000
4.95% Series due December 2044		250,000				250,000
4.20% Series due April 2049		350,000				—
4.90% Series due December 2052		200,000				200,000
4.75% Series due June 2063		125,000				125,000
4.875% Series due September 2066		410,000				410,000
Total mortgage bonds		3,160,000				2,810,000
Governmental Bonds (a):
2.375% Series due 2021, Independence County (c)		45,000				45,000
Total governmental bonds		45,000				45,000
Variable Interest Entity Notes Payable and Credit Facility (Note 4):
3.65% Series L due July 2021		90,000				90,000
3.17% Series M due December 2023		40,000				40,000
Credit Facility due September 2021, weighted avg rate 3.33%		15,100				59,600
Total variable interest entity notes payable and credit facility		145,100				189,600
Securitization Bonds:
2.30% Series Senior Secured due August 2021		7,259				21,692
Total securitization bonds		7,259				21,692
Other:
Long-term DOE Obligation (b)		191,114				186,864
Unamortized Premium and Discount – Net		1,664				4,408
Unamortized Debt Issuance Costs		(34,936		)		(33,831		)
Other		2,007				2,026
Total Long-Term Debt		3,517,208				3,225,759
Less Amount Due Within One Year		—				—
Long-Term Debt Excluding Amount Due Within One Year			$3,517,208				$3,225,759
Fair Value of Long-Term Debt			$3,747,914				$3,189,491

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		2019				2018
		(In Thousands)
Entergy Louisiana
Mortgage Bonds:
3.95% Series due October 2020			$250,000				$250,000
4.8% Series due May 2021		200,000				200,000
3.3% Series due December 2022		200,000				200,000
4.05% Series due September 2023		325,000				325,000
5.59% Series due October 2024		300,000				300,000
5.40% Series due November 2024		400,000				400,000
3.78% Series due April 2025		110,000				110,000
3.78% Series due April 2025		190,000				190,000
4.44% Series due January 2026		250,000				250,000
2.40% Series due October 2026		400,000				400,000
3.12% Series due September 2027		450,000				450,000
3.25% Series due April 2028		425,000				425,000
3.05% Series due June 2031		325,000				325,000
4.0% Series due March 2033		750,000				750,000
5.0% Series due July 2044		170,000				170,000
4.95% Series due January 2045		450,000				450,000
4.20% Series due September 2048		600,000				600,000
4.20% Series due April 2050		525,000				—
5.25% Series due July 2052		200,000				200,000
4.70% Series due June 2063		100,000				100,000
4.875% Series due September 2066		270,000				270,000
Total mortgage bonds		6,890,000				6,365,000
Governmental Bonds (a):
3.375 % Series due 2028, Louisiana Public Facilities Authority (c)		83,680				83,680
3.50% Series due 2030, Louisiana Public Facilities Authority (c)		115,000				115,000
Total governmental bonds		198,680				198,680
Variable Interest Entity Notes Payable and Credit Facilities (Note 4):
3.38% Series R due August 2020		70,000				70,000
3.92% Series H due February 2021		40,000				40,000
3.22% Series I due December 2023		20,000				20,000
Credit Facility due September 2021, weighted avg rate 3.23%		70,300				38,600
Credit Facility due September 2021, weighted avg rate 3.30%		49,900				82,000
Total variable interest entity notes payable and credit facilities		250,200				250,600
Securitization Bonds:
2.04% Series Senior Secured due September 2023		34,185				56,910
Total securitization bonds		34,185				56,910
Other:
Unamortized Premium and Discount - Net		(17,372		)		(14,955		)
Unamortized Debt Issuance Costs		(58,089		)		(57,011		)
Other		6,065				6,544
Total Long-Term Debt		7,303,669				6,805,768
Less Amount Due Within One Year		320,002				2
Long-Term Debt Excluding Amount Due Within One Year			$6,983,667				$6,805,766
Fair Value of Long-Term Debt			$7,961,168				$6,834,134

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		2019				2018
		(In Thousands)
Entergy Mississippi
Mortgage Bonds:
6.64% Series due July 2019			$—				$150,000
3.1% Series due July 2023		250,000				250,000
3.75% Series due July 2024		100,000				100,000
3.25% Series due December 2027		150,000				150,000
2.85% Series due June 2028		375,000				375,000
4.52% Series due December 2038		55,000				55,000
3.85% Series due June 2049		435,000				—
4.90% Series due October 2066		260,000				260,000
Total mortgage bonds		1,625,000				1,340,000
Other:
Unamortized Premium and Discount – Net		6,127				(989		)
Unamortized Debt Issuance Costs		(16,998		)		(13,261		)
Total Long-Term Debt		1,614,129				1,325,750
Less Amount Due Within One Year		—				150,000
Long-Term Debt Excluding Amount Due Within One Year			$1,614,129				$1,175,750
Fair Value of Long-Term Debt			$1,709,505				$1,276,452

		2019				2018
		(In Thousands)
Entergy New Orleans
Mortgage Bonds:
5.10% Series due December 2020			$25,000				$25,000
3.9% Series due July 2023		100,000				100,000
4.0% Series due June 2026		85,000				85,000
4.51% Series due September 2033		60,000				60,000
5.0% Series due December 2052		30,000				30,000
5.50% Series due April 2066		110,000				110,000
Total mortgage bonds		410,000				410,000
Securitization Bonds:
2.67% Series Senior Secured due June 2027		54,443				65,666
Total securitization bonds		54,443				65,666
Other:
3.0% Unsecured Term Loan due May 2022		70,000				—
Credit Facility due November 2021, weighted avg rate 2.92%		20,000				—
Payable to associated company due November 2035		14,367				16,346
Unamortized Premium and Discount – Net		(129		)		(168		)
Unamortized Debt Issuance Costs		(7,775		)		(8,140		)
Total Long-Term Debt		560,906				483,704
Less Amount Due Within One Year		26,838				1,979
Long-Term Debt Excluding Amount Due Within One Year			$534,068				$481,725
Fair Value of Long-Term Debt			$523,846				$491,569

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		2019				2018
		(In Thousands)
Entergy Texas
Mortgage Bonds:
7.125% Series due February 2019			$—				$500,000
2.55% Series due June 2021		125,000				125,000
4.1% Series due September 2021		75,000				75,000
3.45% Series due December 2027		150,000				150,000
4.0% Series due March 2029		300,000				—
4.5% Series due March 2039		400,000				—
5.15% Series due June 2045		250,000				250,000
3.55% Series due September 2049		300,000				—
5.625% Series due June 2064		135,000				135,000
Total mortgage bonds		1,735,000				1,235,000
Securitization Bonds:
5.93% Series Senior Secured, Series A due June 2022		50,289				81,237
4.38% Series Senior Secured, Series A due November 2023		155,969				203,613
Total securitization bonds		206,258				284,850
Other:
Unamortized Premium and Discount - Net		(4,814		)		(992		)
Unamortized Debt Issuance Costs		(17,510		)		(9,145		)
Other		4,022				4,022
Total Long-Term Debt		1,922,956				1,513,735
Less Amount Due Within One Year		—				500,000
Long-Term Debt Excluding Amount Due Within One Year			$1,922,956				$1,013,735
Fair Value of Long-Term Debt			$2,090,215				$1,528,828

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		2019				2018
		(In Thousands)
System Energy
Mortgage Bonds:
4.1% Series due April 2023			$250,000				$250,000
Total mortgage bonds		250,000				250,000
Governmental Bonds (a):
5.875% Series due 2022, Mississippi Business Finance Corp.		—				134,000
2.5% Series due 2022, Mississippi Business Finance Corp.		134,000				—
Total governmental bonds		134,000				134,000
Variable Interest Entity Notes Payable and Credit Facility (Note 4):
3.42% Series J due April 2021		100,000				100,000
Credit Facility due September 2021, weighted avg rate 3.34%		31,600				113,900
Total variable interest entity notes payable and credit facility		131,600				213,900
Other:
Grand Gulf Sale-Leaseback Obligation		34,346				34,352
Unamortized Premium and Discount – Net		(144		)		(328		)
Unamortized Debt Issuance Costs		(1,697		)		(1,176		)
Other		2				2
Total Long-Term Debt		548,107				630,750
Less Amount Due Within One Year		10				6
Long-Term Debt Excluding Amount Due Within One Year			$548,097				$630,744
Fair Value of Long-Term Debt			$565,209				$630,475

(a)	Consists of pollution control revenue bonds and environmental revenue bonds.

(b)

Pursuant to the Nuclear Waste Policy Act of 1982, Entergy’s nuclear owner/licensee subsidiaries have contracts with the DOE for spent nuclear fuel disposal service.  The contracts include a one-time fee for generation prior to April 7, 1983.  Entergy Arkansas is the only Entergy company that generated electric power with nuclear fuel prior to that date and includes the one-time fee, plus accrued interest, in long-term debt.

(c)	The bonds are secured by a series of collateral mortgage bonds.

The annual long-term debt maturities (excluding lease obligations and long-term DOE obligations) for debt outstanding as of December 31, 2019, for the next five years are as follows:

	Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
	(In Thousands)
2020		$—				$320,000				$—				$25,000				$—				$—
2021		$507,359				$360,200				$—				$20,000				$200,000				$131,600
2022		$—				$200,000				$—				$70,000				$50,289				$134,000
2023		$290,000				$379,185				$250,000				$100,000				$155,969				$250,000
2024		$375,000				$700,000				$100,000				$—				$—				$—

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Entergy Arkansas Securitization Bonds

In June 2010 the APSC issued a financing order authorizing the issuance of bonds to recover Entergy Arkansas’s January 2009 ice storm damage restoration costs, including carrying costs of $11.5 million and $4.6 million of up-front financing costs.  In August 2010, Entergy Arkansas Restoration Funding, LLC, a company wholly-owned and consolidated by Entergy Arkansas, issued $124.1 million of storm cost recovery bonds.  The bonds have a coupon of 2.30%.  Although the principal amount is not due until August 2021, Entergy Arkansas Restoration Funding expects to make principal payments on the bonds in the amount of $7.3 million for 2020. With the proceeds, Entergy Arkansas Restoration Funding purchased from Entergy Arkansas the storm recovery property, which is the right to recover from customers through a storm recovery charge amounts sufficient to service the securitization bonds.  The storm recovery property is reflected as a regulatory asset on the consolidated Entergy Arkansas balance sheet.  The creditors of Entergy Arkansas do not have recourse to the assets or revenues of Entergy Arkansas Restoration Funding, including the storm recovery property, and the creditors of Entergy Arkansas Restoration Funding do not have recourse to the assets or revenues of Entergy Arkansas.  Entergy Arkansas has no payment obligations to Entergy Arkansas Restoration Funding except to remit storm recovery charge collections.

Entergy Louisiana Securitization Bonds – Little Gypsy

In August 2011 the LPSC issued a financing order authorizing the issuance of bonds to recover Entergy Louisiana’s investment recovery costs associated with the canceled Little Gypsy repowering project.  In September 2011, Entergy Louisiana Investment Recovery Funding I, L.L.C., a company wholly-owned and consolidated by Entergy Louisiana, issued $207.2 million of senior secured investment recovery bonds.  The bonds have an interest rate of 2.04%.  Although the principal amount is not due until September 2023, Entergy Louisiana Investment Recovery Funding expects to make principal payments on the bonds over the next two years in the amounts of $23.2 million for 2020 and $11 million for 2021.  With the proceeds, Entergy Louisiana Investment Recovery Funding purchased from Entergy Louisiana the investment recovery property, which is the right to recover from customers through an investment recovery charge amounts sufficient to service the bonds.  In accordance with the financing order, Entergy Louisiana will apply the proceeds it received from the sale of the investment recovery property as a reimbursement for previously-incurred investment recovery costs.  The investment recovery property is reflected as a regulatory asset on the consolidated Entergy Louisiana balance sheet.  The creditors of Entergy Louisiana do not have recourse to the assets or revenues of Entergy Louisiana Investment Recovery Funding, including the investment recovery property, and the creditors of Entergy Louisiana Investment Recovery Funding do not have recourse to the assets or revenues of Entergy Louisiana.  Entergy Louisiana has no payment obligations to Entergy Louisiana Investment Recovery Funding except to remit investment recovery charge collections.

Entergy New Orleans Securitization Bonds - Hurricane Isaac

In May 2015 the City Council issued a financing order authorizing the issuance of securitization bonds to recover Entergy New Orleans’s Hurricane Isaac storm restoration costs of $31.8 million, including carrying costs, the costs of funding and replenishing the storm recovery reserve in the amount of $63.9 million, and approximately $3 million of up-front financing costs associated with the securitization. In July 2015, Entergy New Orleans Storm Recovery Funding I, L.L.C., a company wholly owned and consolidated by Entergy New Orleans, issued $98.7 million of storm cost recovery bonds. The bonds have a coupon of 2.67%. Although the principal amount is not due until June 2027, Entergy New Orleans Storm Recovery Funding expects to make principal payments on the bonds over the next five years in the amounts of $11.6 million for 2020, $11.9 million for 2021, $12.2 million for 2022, $12.5 million for 2023, and $6.2 million for 2024. With the proceeds, Entergy New Orleans Storm Recovery Funding purchased from Entergy New Orleans the storm recovery property, which is the right to recover from customers through a storm recovery charge amounts sufficient to service the securitization bonds. The storm recovery property is reflected as a regulatory asset on the consolidated Entergy New Orleans balance sheet. The creditors of Entergy New Orleans do not have recourse to the assets or revenues of Entergy New Orleans Storm Recovery Funding, including the storm recovery property, and the creditors of Entergy New Orleans Storm Recovery Funding do not have recourse to the

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assets or revenues of Entergy New Orleans. Entergy New Orleans has no payment obligations to Entergy New Orleans Storm Recovery Funding except to remit storm recovery charge collections.

Entergy Texas Securitization Bonds - Hurricane Rita

In April 2007 the PUCT issued a financing order authorizing the issuance of securitization bonds to recover $353 million of Entergy Texas’s Hurricane Rita reconstruction costs and up to $6 million of transaction costs, offset by $32 million of related deferred income tax benefits.  In June 2007, Entergy Gulf States Reconstruction Funding I, LLC, a company that is now wholly-owned and consolidated by Entergy Texas, issued $329.5 million of senior secured transition bonds (securitization bonds). As of December 31, 2019, $50.3 million at 5.93% remain outstanding. Entergy Gulf States Reconstruction Funding expects to make principal payments on the bonds over the next two years in the amounts of $32.8 million for 2020 and $17.5 million for 2021.

With the proceeds, Entergy Gulf States Reconstruction Funding purchased from Entergy Texas the transition property, which is the right to recover from customers through a transition charge amounts sufficient to service the securitization bonds.  The transition property is reflected as a regulatory asset on the consolidated Entergy Texas balance sheet.  The creditors of Entergy Texas do not have recourse to the assets or revenues of Entergy Gulf States Reconstruction Funding, including the transition property, and the creditors of Entergy Gulf States Reconstruction Funding do not have recourse to the assets or revenues of Entergy Texas.  Entergy Texas has no payment obligations to Entergy Gulf States Reconstruction Funding except to remit transition charge collections.

Entergy Texas Securitization Bonds - Hurricane Ike and Hurricane Gustav

In September 2009 the PUCT authorized the issuance of securitization bonds to recover $566.4 million of Entergy Texas’s Hurricane Ike and Hurricane Gustav restoration costs, plus carrying costs and transaction costs, offset by insurance proceeds.  In November 2009, Entergy Texas Restoration Funding, LLC (Entergy Texas Restoration Funding), a company wholly-owned and consolidated by Entergy Texas, issued $545.9 million of senior secured transition bonds (securitization bonds). As of December 31, 2019, $156 million at 4.38% remain outstanding. Entergy Texas Restoration Funding expects to make principal payments on the bonds over the next three years in the amount of $49.8 million for 2020, $52 million for 2021, and $54.3 million for 2022.

With the proceeds, Entergy Texas Restoration Funding purchased from Entergy Texas the transition property, which is the right to recover from customers through a transition charge amounts sufficient to service the securitization bonds.  The transition property is reflected as a regulatory asset on the consolidated Entergy Texas balance sheet.  The creditors of Entergy Texas do not have recourse to the assets or revenues of Entergy Texas Restoration Funding, including the transition property, and the creditors of Entergy Texas Restoration Funding do not have recourse to the assets or revenues of Entergy Texas.  Entergy Texas has no payment obligations to Entergy Texas Restoration Funding except to remit transition charge collections.

Grand Gulf Sale-Leaseback Transactions

In 1988, in two separate but substantially identical transactions, System Energy sold and leased back undivided ownership interests in Grand Gulf for the aggregate sum of $500 million.  The initial term of the leases expired in July 2015.  System Energy renewed the leases for fair market value with renewal terms expiring in July 2036. At the end of the new lease renewal terms, System Energy has the option to repurchase the leased interests in Grand Gulf or renew the leases at fair market value.  In the event that System Energy does not renew or purchase the interests, System Energy would surrender such interests and their associated entitlement of Grand Gulf’s capacity and energy.

System Energy is required to report the sale-leaseback as a financing transaction in its financial statements.  As such, it has recognized debt for the lease obligation and retained the portion of the plant subject to the sale-leaseback on its balance sheet. For financial reporting purposes, System Energy has recognized interest expense on the debt balance and depreciation on the applicable plant balance.  The lease payments are recognized as principal and interest

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payments on the debt balance. However, operating revenues include the recovery of the lease payments because the transactions are accounted for as a sale and leaseback for ratemaking purposes.  Consistent with a recommendation contained in a FERC audit report, System Energy initially recorded as a net regulatory asset the difference between the recovery of the lease payments and the amounts expensed for interest and depreciation and continues to record this difference as a regulatory asset or liability on an ongoing basis, resulting in a zero net balance for the regulatory asset at the end of the lease term.  The amount was a net regulatory liability of $55.6 million as of December 31, 2019 and 2018.

As of December 31, 2019, System Energy, in connection with the Grand Gulf sale and leaseback transactions, had future minimum lease payments that are recorded as long-term debt, as follows, which reflects the effect of the December 2013 renewal:

	Amount
	(In Thousands)
2020		$17,188
2021	17,188
2022	17,188
2023	17,188
2024	17,188
Years thereafter	206,250
Total	292,190
Less: Amount representing interest	257,844
Present value of net minimum lease payments		$34,346

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The number of shares and units authorized and outstanding and dollar value of preferred stock, preferred membership interests, and non-controlling interest for Entergy Corporation subsidiaries as of December 31, 2019 and 2018 are presented below.  

		Shares/Units Authorized						Shares/Units Outstanding
		2019			2018			2019			2018			2019				2018
Entergy Corporation														(Dollars in Thousands)
Utility:
Preferred Stock or Preferred Membership Interests without sinking fund:
Entergy Utility Holding Company, LLC, 7.5% Series (a)		110,000			110,000			110,000			110,000				$107,425				$107,425
Entergy Utility Holding Company, LLC, 6.25% Series (b)		15,000			15,000			15,000			15,000			14,366				14,366
Entergy Utility Holding Company, LLC, 6.75% Series (c)		75,000			75,000			75,000			75,000			73,370				73,362
Entergy Texas, 5.375% Series		1,400,000			—			1,400,000			—			35,000				—
Total Utility Preferred Stock or Preferred Membership Interests without sinking fund		1,600,000			200,000			1,600,000			200,000			230,161				195,153
Entergy Wholesale Commodities:
Preferred Stock without sinking fund:
Entergy Finance Holding, Inc. 8.75% (d)		250,000			250,000			250,000			250,000			24,249				24,249
Total Subsidiaries’ Preferred Stock or Preferred Membership Interests without sinking fund		1,850,000			450,000			1,850,000			450,000				$254,410				$219,402

(a)

In October 2015, Entergy Utility Holding Company, LLC issued 110,000 units of $1,000 liquidation value 7.5% Series A Preferred Membership Interests, all of which are outstanding as of December 31, 2019. The distributions are cumulative and payable quarterly. These units are redeemable on or after January 1, 2036, at Entergy Utility Holding Company, LLC’s option, at the fixed redemption price of $1,000 per unit. Dollar amount outstanding is net of $2,575 thousand of preferred stock issuance costs.

(b)

In November 2017, Entergy Utility Holding Company, LLC issued 15,000 units of $1,000 liquidation value 6.25% Series B Preferred Membership Interests, all of which are outstanding as of December 31, 2019. The distributions are cumulative and payable quarterly. These units are redeemable on or after February 28, 2038, at Entergy Utility Holding Company, LLC’s option, at the fixed redemption price of $1,000 per unit. Dollar amount outstanding is net of $634 thousand of preferred stock issuance costs.

(c)

In November 2018, Entergy Utility Holding Company, LLC issued 75,000 units of $1,000 liquidation value 6.75% Series C Preferred Membership Interests, all of which are outstanding as of December 31, 2019. The distributions are cumulative and payable quarterly. These units are redeemable on or after February 28, 2039, at Entergy Utility Holding Company, LLC’s option, at the fixed redemption price of $1,000 per unit. Dollar amount outstanding is net of $1,630 thousand of preferred stock issuance costs.

(d)

In December 2013, Entergy Finance Holding, Inc. issued 250,000 shares of $100 par value 8.75% Series Preferred Stock, all of which are outstanding as of December 31, 2019. The dividends are cumulative and payable quarterly. The preferred stock is redeemable on or after December 16, 2023, at Entergy Finance Holding, Inc.’s option, at the fixed redemption price of $100 per share. Dollar amount outstanding is net of $751 thousand of preferred stock issuance costs.

 

The number of shares authorized and outstanding and dollar value of preferred stock for Entergy Texas as of December 31, 2019 and 2018 are presented below.  

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		Shares Authorized and Outstanding														Call Price per Share as of December 31,
		2019			2018			2019				2018				2019
Entergy Texas Preferred Stock								(Dollars in Thousands)
Without sinking fund:
Cumulative, $25 par value:
5.375% Series (a)		1,400,000			—				$35,000				$—				$—
Total without sinking fund		1,400,000			—				$35,000				$—

(a)

In September 2019, Entergy Texas issued $35 million of 5.375% Series A Preferred Stock, a total of 1,400,000 shares with a liquidation value of $25 per share, all of which are outstanding as of December 31, 2019. The dividends are cumulative and payable quarterly. The preferred stock is redeemable on or after October 15, 2024 at Entergy Texas’s option, at a fixed redemption price of $25 per share.

Dividends and distributions paid on all of Entergy Corporation’s subsidiaries’ preferred stock and membership interests series may be eligible for the dividends received deduction.  

Presentation of Preferred Stock without Sinking Fund

Accounting standards regarding non-controlling interests and the classification and measurement of redeemable securities require the classification of preferred securities between liabilities and shareholders’ equity on the balance sheet if the holders of those securities have protective rights that allow them to gain control of the board of directors in certain circumstances.  These rights would have the effect of giving the holders the ability to potentially redeem their securities, even if the likelihood of occurrence of these circumstances is considered remote.  The outstanding preferred stock of Entergy Texas has protective rights with respect to unpaid dividends but provides for the election of board members that would not constitute a majority of the board, and the preferred stock of Entergy Texas is therefore classified as a component of equity.

The outstanding preferred securities of Entergy Utility Holding Company (a Utility subsidiary) and Entergy Finance Holding (an Entergy Wholesale Commodities subsidiary), whose preferred holders have protective rights, are presented between liabilities and equity on Entergy’s consolidated balance sheets.  The preferred dividends or distributions paid by all subsidiaries are reflected for all periods presented outside of consolidated net income.

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Common Stock

Common stock and treasury stock shares activity for Entergy for 2019, 2018, and 2017 is as follows:

	2019						2018						2017
	Common Shares Issued			Treasury Shares			Common Shares Issued			Treasury Shares			Common Shares Issued			Treasury Shares
Beginning Balance, January 1	261,587,009			72,530,866			254,752,788			74,235,135			254,752,788			75,623,363
Issuances:
Equity forwards settled	8,448,171			—			6,834,221			—			—			—
Employee Stock-Based Compensation Plans	—			(1,624,358	)		—			(1,683,174	)		—			(1,377,363	)
Directors’ Plan	—			(20,108	)		—			(21,095	)		—			(10,865	)
Ending Balance, December 31	270,035,180			70,886,400			261,587,009			72,530,866			254,752,788			74,235,135

Entergy Corporation reissues treasury shares to meet the requirements of the Stock Plan for Outside Directors (Directors’ Plan), four Equity Ownership Plans of Entergy Corporation and Subsidiaries, and certain other stock benefit plans.  The Directors’ Plan awards to non-employee directors a portion of their compensation in the form of a fixed dollar value of shares of Entergy Corporation common stock.

In October 2010 the Board granted authority for a $500 million share repurchase program.  As of December 31, 2019, $350 million of authority remains under the $500 million share repurchase program.

Dividends declared per common share were $3.66 in 2019, $3.58 in 2018, and $3.50 in 2017.

(System Energy)

System Energy paid its parent, Entergy Corporation, distributions out of its common stock of $56.5 million in 2018 and $21 million in 2017.

Equity Forward Sale Agreements

In June 2018, Entergy marketed an equity offering of 15.3 million shares of common stock. In lieu of issuing equity at the time of the offering, Entergy entered into forward sale agreements with various investment banks. The equity forwards required Entergy to, at its election prior to June 7, 2019, either (i) physically settle the transactions by issuing the total of 15.3 million shares of its common stock to the investment banks in exchange for net proceeds at the then-applicable forward sale price specified by the agreements (initially $74.45 per share) or (ii) net settle the transactions in whole or in part through the delivery or receipt of cash or shares. The forward sale price was subject to adjustment on a daily basis based on a floating interest rate factor and decreased by other fixed amounts specified in the agreements.

In December 2018, Entergy physically settled a portion of its obligations under the forward sale agreements by delivering 6,834,221 shares of common stock in exchange for cash proceeds of $500 million. The forward sale price used to determine the cash proceeds received by Entergy was calculated based on the initial forward sale price

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of $74.45 per share as adjusted in accordance with the forward sale agreements. Entergy incurred approximately $728 thousand of common stock issuance costs with the settlement.

In May 2019, Entergy physically settled its remaining obligations under the forward sale agreements by delivering 8,448,171 shares of common stock in exchange for cash proceeds of $608 million. The forward sale price used to determine the cash proceeds received by Entergy was calculated based on the initial forward sale price of $74.45 per share as adjusted in accordance with the forward sale agreements. Entergy incurred approximately $7 thousand of common stock issuance costs with the settlement.

Entergy used the net proceeds for general corporate purposes, which included repayment of commercial paper, outstanding loans under Entergy’s revolving credit facility, and other debt.

Retained Earnings and Dividends

Entergy implemented ASU No. 2016-01 “Financial Instruments (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities” effective January 1, 2018. The ASU requires investments in equity securities, excluding those accounted for under the equity method or resulting in consolidation of the investee, to be measured at fair value with changes recognized in net income. Entergy implemented this standard using a modified retrospective method, and recorded an adjustment increasing retained earnings and reducing accumulated other comprehensive income by $633 million as of January 1, 2018 for the cumulative effect of the unrealized gains and losses on investments in equity securities held by the decommissioning trust funds that do not meet the criteria for regulatory accounting treatment. See Note 16 to the financial statements for further discussion of effects of the new standard.

Entergy implemented ASU No. 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory” effective January 1, 2018. The ASU requires entities to recognize the income tax consequences of intra-entity asset transfers, other than inventory, at the time the transfer occurs. Entergy implemented this standard using a modified retrospective method, and recorded an adjustment decreasing retained earnings by $56 million as of January 1, 2018 for the cumulative effect of recording deferred tax assets on previously-recognized intra-entity asset transfers.

Entergy adopted ASU No. 2018-02, “Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income,” in the first quarter 2018. The ASU allows a one-time reclassification from accumulated other comprehensive income to retained earnings for certain tax effects resulting from the Tax Cuts and Jobs Act that would otherwise be stranded in accumulated other comprehensive income. Entergy’s policy for releasing income tax effects from accumulated other comprehensive income for available-for-sale securities is to use the portfolio approach. Entergy elected to reclassify the $15.5 million of stranded tax effects in accumulated other comprehensive income resulting from the Tax Cuts and Jobs Act to retained earnings ($32 million decrease) or the regulatory liability for income taxes ($16.5 million increase). Entergy’s reclassification only includes the effect of the change in the federal corporate income tax rate on accumulated other comprehensive income.

Entergy implemented ASU No. 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities” effective January 1, 2019. The ASU makes a number of amendments to hedge accounting, most significantly changing the recognition and presentation of highly effective hedges. Entergy implemented this standard using a modified retrospective method, and recorded an adjustment increasing retained earnings and increasing accumulated other comprehensive loss by approximately $8 million as of January 1, 2019 for the cumulative effect of the ineffectiveness portion of designated hedges on nuclear power sales.

Entergy implemented ASU 2017-08 “Receivables (Topic 310): Nonrefundable Fees and Other Costs” effective January 1, 2019. The ASU amends the amortization period for certain purchased callable debt securities held at a premium to the earliest call date. Entergy implemented this standard using the modified retrospective approach, and

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recorded an adjustment decreasing retained earnings and decreasing accumulated other comprehensive loss by approximately $1 million as of January 1, 2019 for the cumulative effect of the amended amortization period.

Entergy Corporation received dividend payments and distributions from subsidiaries totaling $124 million in 2019, $27 million in 2018, and $201 million in 2017.

Comprehensive Income

Accumulated other comprehensive income (loss) is included in the equity section of the balance sheets of Entergy and Entergy Louisiana. The following table presents changes in accumulated other comprehensive income (loss) for Entergy for the year ended December 31, 2019 by component:

	Cash flow hedges net unrealized gain (loss)				Pension and other postretirement liabilities				Net unrealized investment gain (loss)				Total Accumulated Other Comprehensive Income (Loss)
	(In Thousands)
Ending balance, December 31, 2018		($23,135	)			($531,922	)			($2,116	)			($557,173	)
Implementation of accounting standards	(7,685		)		—				879				(6,806		)
Beginning balance, January 1, 2019		($30,820	)			($531,922	)			($1,237	)			($563,979	)
Other comprehensive income (loss) before reclassifications	191,147				(93,696		)		32,914				130,365
Amounts reclassified from accumulated other comprehensive income (loss)	(76,121		)		68,546				(5,731		)		(13,306		)
Net other comprehensive income (loss) for the period	115,026				(25,150		)		27,183				117,059
Ending balance, December 31, 2019		$84,206				($557,072	)			$25,946				($446,920	)

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The following table presents changes in accumulated other comprehensive income (loss) for Entergy for the year ended December 31, 2018 by component:

	Cash flow hedges net unrealized gain (loss)				Pension and other postretirement liabilities				Net unrealized investment gain (loss)				Total Accumulated Other Comprehensive Income (Loss)
	(In Thousands)
Ending balance, December 31, 2017		($37,477	)			($531,099	)			$545,045				($23,531	)
Implementation of accounting standards	—				—				(632,617		)		(632,617		)
Beginning balance, January 1, 2018		($37,477	)			($531,099	)			($87,572	)			($656,148	)
Other comprehensive income (loss) before reclassifications	(31,933		)		26,702				(46,574		)		(51,805		)
Amounts reclassified from accumulated other comprehensive income (loss)	54,031				63,441				17,803				135,275
Net other comprehensive income (loss) for the period	22,098				90,143				(28,771		)		83,470
Reclassification pursuant to ASU 2018-02	(7,756		)		(90,966		)		114,227				15,505
Ending balance, December 31, 2018		($23,135	)			($531,922	)			($2,116	)			($557,173	)

The following table presents changes in accumulated other comprehensive income (loss) for Entergy Louisiana for the year ended December 31, 2019:

		Pension and Other Postretirement Liabilities
		(In Thousands)
Beginning balance, January 1, 2019			($6,153	)
Other comprehensive income (loss) before reclassifications		14,591
Amounts reclassified from accumulated other comprehensive income (loss)		(3,876		)
Net other comprehensive income (loss) for the period		10,715
Ending balance, December 31, 2019			$4,562

    

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The following table presents changes in accumulated other comprehensive income (loss) for Entergy Louisiana for the year ended December 31, 2018:

		Pension and Other Postretirement Liabilities
		(In Thousands)
Beginning balance, January 1, 2018			($46,400	)
Other comprehensive income (loss) before reclassifications		52,299
Amounts reclassified from accumulated other comprehensive income (loss)		(2,003		)
Net other comprehensive income (loss) for the period		50,296
Reclassification pursuant to ASU 2018-02			($10,049	)
Ending balance, December 31, 2018			($6,153	)

    

Total reclassifications out of accumulated other comprehensive income (loss) (AOCI) for Entergy for the years ended December 31, 2019 and 2018 are as follows:

		Amounts reclassified from AOCI								Income Statement Location
		2019				2018
		(In Thousands)
Cash flow hedges net unrealized gain (loss)
Power contracts			$96,549				($68,067	)		Competitive business operating revenues
Interest rate swaps		(194		)		(327		)		Miscellaneous - net
Total realized gain (loss) on cash flow hedges		96,355				(68,394		)
Income taxes		(20,234		)		14,363				Income taxes
Total realized gain (loss) on cash flow hedges (net of tax)			$76,121				($54,031	)
Pension and other postretirement liabilities
Amortization of prior-service costs			$21,300				$21,700			(a)
Amortization of loss		(83,246		)		(99,186		)		(a)
Settlement loss		(25,155		)		(3,207		)		(a)
Total		(87,101		)		(80,693		)
Income taxes		18,555				17,252				Income taxes
Total amortization and settlement loss (net of tax)			($68,546	)			($63,441	)
Net unrealized investment gain (loss)
Realized gain (loss)			$9,069				($28,170	)		Interest and investment income
Income taxes		(3,338		)		10,367				Income taxes
Total realized investment gain (loss) (net of tax)			$5,731				($17,803	)
Total reclassifications for the period (net of tax)			$13,306				($135,275	)

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(a)	These accumulated other comprehensive income (loss) components are included in the computation of net periodic pension and other postretirement cost. See Note 11 to the financial statements for additional details.

    

Total reclassifications out of accumulated other comprehensive income (loss) (AOCI) for Entergy Louisiana for the years ended December 31, 2019 and 2018 are as follows:

		Amounts reclassified from AOCI								Income Statement Location
		2019				2018
		(In Thousands)
Pension and other postretirement liabilities
Amortization of prior-service costs			$7,349				$7,735			(a)
Amortization of loss		(2,106		)		(5,025		)		(a)
Total amortization		5,243				2,710
Income taxes		(1,367		)		(707		)		Income taxes
Total amortization (net of tax)		3,876				2,003
Total reclassifications for the period (net of tax)			$3,876				$2,003

(a)	These accumulated other comprehensive income (loss) components are included in the computation of net periodic pension and other postretirement cost. See Note 11 to the financial statements for additional details.

    

Entergy and the Registrant Subsidiaries are involved in a number of legal, regulatory, and tax proceedings before various courts, regulatory commissions, and governmental agencies in the ordinary course of business.  While management is unable to predict with certainty the outcome of such proceedings, management does not believe that the ultimate resolution of these matters will have a material adverse effect on Entergy’s results of operations, cash flows, or financial condition.  Entergy discusses regulatory proceedings in Note 2 to the financial statements and discusses tax proceedings in Note 3 to the financial statements.

Vidalia Purchased Power Agreement

Entergy Louisiana has an agreement extending through the year 2031 to purchase energy generated by a hydroelectric facility known as the Vidalia project.  Entergy Louisiana made payments under the contract of approximately $135.5 million in 2019, $137.6 million in 2018, and $122.9 million in 2017.  If the maximum percentage (94%) of the energy is made available to Entergy Louisiana, current production projections would require estimated payments of approximately $131 million in 2020, and a total of $1.44 billion for the years 2021 through 2031.  Entergy Louisiana currently recovers the costs of the purchased energy through its fuel adjustment clause.

In an LPSC-approved settlement related to tax benefits from the tax treatment of the Vidalia contract, Entergy Louisiana agreed to credit rates by $11 million each year for up to 10 years, beginning in October 2002.  In October 2011 the LPSC approved a settlement under which Entergy Louisiana agreed to provide credits to customers by crediting billings an additional $20.235 million per year for 15 years beginning January 2012.  Entergy Louisiana recorded a regulatory charge and a corresponding regulatory liability to reflect this obligation.  The settlement agreement allowed for an adjustment to the credits if, among other things, 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

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corporate income tax rate from 35% to 21%, the Vidalia purchased power regulatory liability was reduced by $30.5 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.

ANO Damage, Outage, and NRC Reviews

In March 2013, during a scheduled refueling outage at ANO 1, a contractor-owned and operated heavy-lifting apparatus collapsed while moving the generator stator out of the turbine building.  The collapse resulted in the death of an ironworker and injuries to several other contract workers, caused ANO 2 to shut down, and damaged the ANO turbine building.  The total cost of assessment, restoration of off-site power, site restoration, debris removal, and replacement of damaged property and equipment was approximately $95 million.  Entergy Arkansas has pursued its options for recovering damages that resulted from the stator drop, including its insurance coverage and legal action. Entergy Arkansas collected $50 million in 2014 from Nuclear Electric Insurance Limited (NEIL), a mutual insurance company that provides property damage coverage to the members’ nuclear generating plants. Entergy Arkansas also collected a total of $21 million in 2018 as a result of stator-related settlements.

In addition, Entergy Arkansas incurred replacement power costs for ANO 2 power during its outage and incurred incremental replacement power costs for ANO 1 power because the outage extended beyond the originally-planned duration of the refueling outage.  In February 2014 the APSC authorized Entergy Arkansas to retain the $65.9 million in its deferred fuel balance with recovery to be reviewed in a later period after more information regarding various claims associated with the ANO stator incident is available.

In March 2015, after several NRC inspections and regulatory conferences, arising from the stator incident, the NRC placed ANO into the “multiple/repetitive degraded cornerstone column,” or Column 4, of the NRC’s Reactor Oversight Process Action Matrix. Entergy Arkansas incurred incremental costs of approximately $53 million in 2015 to prepare for the NRC inspections that began in early 2016 in order to address the issues required to move ANO back to “licensee response” or Column 1 of the NRC’s Reactor Oversight Process Action Matrix. Excluding remediation and response costs that resulted from the additional NRC inspection activities, Entergy Arkansas incurred approximately $44 million in 2016 and $7 million in 2017 in support of NRC inspection activities and to implement Entergy Arkansas’s performance improvement initiatives developed in 2015. In June 2018 the NRC moved ANO 1 and ANO 2 into the “licensee response column,” or Column 1, of the NRC’s Reactor Oversight Process Action Matrix.

In July 2017, Entergy Arkansas filed for a change in rates pursuant to its formula rate plan rider. In that proceeding, the APSC approved a settlement agreement agreed upon by the parties, including a provision that requires Entergy Arkansas to initiate a regulatory proceeding for the purpose of recovering funds currently withheld from rates and related to the stator incident, including the $65.9 million of deferred fuel and purchased energy costs and costs related to the incremental oversight previously noted, subject to certain timelines and conditions set forth in the settlement agreement.

 

Spent Nuclear Fuel Litigation

Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors.  Entergy’s nuclear owner/licensee subsidiaries have been charged fees for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982.  The affected Entergy companies entered into contracts with the DOE, whereby the DOE is to furnish disposal services at a cost of one mill per net kWh generated and sold after April 7, 1983, plus a one-time fee for generation prior to that date.  Entergy considers all costs incurred for the disposal of spent nuclear fuel, except accrued interest, to be proper components of nuclear fuel expense.  Provisions to recover such costs have been or will be made in applications to regulatory authorities for the Utility plants.  Following the defunding of the Yucca Mountain spent fuel repository program, the National Association of Regulatory Utility Commissioners and others sued the government seeking cessation of collection of the one mill per net kWh generated and sold after April 7, 1983 fee. In November 2013 the D.C. Circuit Court of

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Appeals ordered the DOE to submit a proposal to Congress to reset the fee to zero until the DOE complies with the Nuclear Waste Policy Act or Congress enacts an alternative waste disposal plan. In January 2014 the DOE submitted the proposal to Congress under protest, and also filed a petition for rehearing with the D.C. Circuit. The petition for rehearing was denied. The zero spent fuel fee went into effect prospectively in May 2014.

Because the DOE has not begun accepting spent fuel, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts. As a result of the DOE’s failure to begin disposal of spent nuclear fuel in 1998 pursuant to the Nuclear Waste Policy Act of 1982 and the spent fuel disposal contracts, Entergy’s nuclear owner/licensee subsidiaries have incurred and will continue to incur damages. Beginning in November 2003 these subsidiaries have pursued litigation to recover the damages caused by the DOE’s delay in performance. Following are details of final judgments recorded by Entergy in 2017, 2018, and 2019 related to Entergy’s nuclear owner licensee subsidiaries’ litigation with the DOE.

In September 2016 the U.S. Court of Federal Claims issued a judgment in the Entergy Nuclear Palisades case in the amount of $14 million. Entergy Nuclear Palisades recorded a receivable for that amount, and subsequently received payment from the U.S. Treasury in January 2017. The effects of recording the judgment were reductions to plant and other operation and maintenance expenses. The Palisades damages awarded included $11 million related to costs previously capitalized and $3 million related to costs previously recorded as other operation and maintenance expense. Of the $11 million, Entergy recorded $1 million as a reduction to previously-recorded depreciation expense. Entergy reduced its Palisades plant asset balance by the remaining $10 million. The Court previously issued a partial judgment in the case in the amount of $21 million, which was paid by the U.S. Treasury in October 2015.

In October 2016 the U.S. Court of Federal Claims issued a judgment in the second round Entergy Nuclear Indian Point 2 case in the amount of $34 million. Entergy Nuclear Indian Point 2 recorded a receivable for that amount, and subsequently received payment from the U.S. Treasury in January 2017. The effects of recording the judgment were reductions to plant and other operation and maintenance expenses. The Indian Point 2 damages awarded included $14 million related to costs previously capitalized, $15 million related to costs previously recorded as other operation and maintenance expense, $3 million related to previously recorded decommissioning expense, and $2 million related to costs previously recorded as taxes other than income taxes. Of the $14 million, Entergy recorded $3 million as a reduction to previously-recorded depreciation expense. Entergy reduced its Indian Point 2 plant asset balance by the remaining $11 million.

In September 2018 the DOE submitted an offer of judgment to resolve claims in the second round Entergy Nuclear Generation Company case involving Pilgrim. The $62 million offer was accepted by Entergy Nuclear Generation Company, and the U.S. Court of Federal Claims issued a judgment in that amount in favor of Entergy Nuclear Generation Company. Entergy received payment from the U.S. Treasury in October 2018. The effect in 2018 of recording the judgment was a reduction to plant and other operation and maintenance expenses. The Pilgrim damages awarded included $60 million related to costs previously capitalized and $2 million related to costs previously recorded as other operation and maintenance expense. Of the $60 million, Entergy recorded $4 million as a reduction to previously-recorded depreciation expense, a $10 million reduction to bring its remaining Pilgrim plant asset balance to zero, and the excess $46 million as a reduction to other operation and maintenance expense because Pilgrim’s plant asset balance is fully impaired.

In August 2019 the U.S. Court of Federal Claims issued a final judgment in the amount of $19 million in favor of Entergy Louisiana against the DOE in the second round River Bend damages case. Entergy Louisiana received payment from the U.S. Treasury in September 2019. The effects in 2019 of recording the judgment were reductions to plant, nuclear fuel expense, and other operation and maintenance expense. The River Bend damages awarded included $12 million related to costs previously recorded as nuclear fuel expense, $5 million related to costs previously recorded as other operation and maintenance expense, and $2 million in costs previously capitalized.

In December 2019 the DOE submitted an offer of judgment to resolve claims in the third round ANO damages case.  The $80 million offer was accepted by Entergy Arkansas, and the U.S. Court of Federal Claims issued a judgment

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in that amount in favor of Entergy Arkansas and against the DOE. Entergy Arkansas received payment from the U.S. Treasury in January 2020. The effects in 2019 of recording the judgment were reductions to plant, nuclear fuel expense, other operation and maintenance expense, depreciation expense, and taxes other than income taxes. The ANO damages awarded included $55 million in costs previously capitalized, $12 million related to costs previously recorded as nuclear fuel expense, $12 million related to costs previously recorded as other operation and maintenance expense, and $1 million related to costs previously recorded as taxes other than income taxes. Of the $55 million, Entergy Arkansas, recorded $5 million as a reduction to previously-recorded depreciation expense.

In December 2019 the Entergy FitzPatrick Properties (formerly Entergy Nuclear FitzPatrick) and the DOE entered into a settlement agreement and the U.S. Court of Federal Claims issued a judgment in the amount of $7 million in favor of Entergy FitzPatrick Properties against the DOE in the second round FitzPatrick damages case. Entergy received payment from the U.S. Treasury in January 2020. Substantially all of the FitzPatrick damages awarded relate to costs previously expensed as asset write-offs, impairments, and related charges, and in December 2019 Entergy recorded $7 million as a reduction to asset write-offs, impairments, and related charges.

Management cannot predict the timing or amount of any potential recoveries on other claims filed by Entergy subsidiaries, and cannot predict the timing of any eventual receipt from the DOE of the U.S. Court of Federal Claims damage awards.

Nuclear Insurance

Third Party Liability Insurance

The Price-Anderson Act requires that reactor licensees purchase insurance and participate in a secondary insurance pool that provides insurance coverage for the public in the event of a nuclear power plant accident.  The costs of this insurance are borne by the nuclear power industry.  Congress amended and renewed the Price-Anderson Act in 2005 for a term through 2025.  The Price-Anderson Act requires nuclear power plants to show evidence of financial protection in the event of a nuclear accident.  This protection must consist of two layers of coverage:

1.	The primary level is private insurance underwritten by American Nuclear Insurers (ANI) and provides public liability insurance coverage of $450 million for each operating reactor.  If this amount is not sufficient to cover claims arising from an accident, the second level, Secondary Financial Protection, applies.

2.

Within the Secondary Financial Protection level, each nuclear reactor has a contingent obligation to pay a retrospective premium, equal to its proportionate share of the loss in excess of the primary level, regardless of proximity to the incident or fault, up to a maximum of approximately $137.6 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.101 billion).  This retrospective premium is payable at a rate currently set at approximately $21 million per year per incident per nuclear power reactor.

3.

In the event that one or more acts of terrorism cause a nuclear power plant accident, which results in third-party damages – off-site property and environmental damage, off-site bodily injury, and on-site third-party bodily injury (i.e. contractors), the primary level provided by ANI combined with the Secondary Financial Protection would provide approximately $14 billion in coverage.  The Terrorism Risk Insurance Reauthorization Act of 2007 created a government program that provides for up to $100 billion in coverage in excess of existing coverage for a terrorist event. Under current law, the Terrorism Risk Insurance Act extends through 2020.

Currently, 98 nuclear reactors are participating in the Secondary Financial Protection program that provides approximately $14 billion in secondary layer insurance coverage to compensate the public in the event of a nuclear power reactor accident.  The Price-Anderson Act provides that all potential liability for a nuclear accident is limited to the amounts of insurance coverage available under the primary and secondary layers.

Entergy Arkansas and Entergy Louisiana each have two licensed reactors. System Energy has one licensed reactor (10% of Grand Gulf is owned by a non-affiliated company (Cooperative Energy) that would share on a pro-

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rata basis in any retrospective premium assessment to System Energy under the Price-Anderson Act).  The Entergy Wholesale Commodities segment includes the ownership, operation, and decommissioning of three nuclear power reactors and the ownership of the shutdown Indian Point 1 reactor and Big Rock Point facility. The Entergy Wholesale Commodities segment previously included two nuclear power reactors that were sold in 2019. Vermont Yankee was sold in January 2019 and Pilgrim was sold in August 2019.

Property Insurance

Entergy’s nuclear owner/licensee subsidiaries are members of NEIL, a mutual insurance company that provides property damage coverage, including decontamination and reactor stabilization, to the members’ nuclear generating plants.  The property damage insurance limits procured by Entergy for its Utility plants and Entergy Wholesale Commodity plants are in compliance with the financial protection requirements of the NRC.

The Utility plants’ (ANO 1 and 2, Grand Gulf, River Bend, and Waterford 3) property damage insurance limits are $1.5 billion per occurrence at each plant with an additional $100 million per occurrence that is shared among the plants. Property damage from earthquake and volcanic eruption is excluded from the first $500 million in coverage for all Utility plants. Property damage from flood is excluded from the first $500 million in coverage at ANO 1 and 2 and Grand Gulf. Property damage from flood for Waterford 3 and River Bend includes a deductible of $10 million plus an additional 10% of the amount of the loss in excess of $10 million, up to a maximum deductible of $50 million. Property damage from wind for all of the Utility nuclear plants includes a deductible of $10 million plus an additional 10% of the amount of the loss in excess of $10 million, up to a total maximum deductible of $50 million.

The Entergy Wholesale Commodities’ plants (Palisades, Indian Point 2, Indian Point 3, and Big Rock Point) have property damage insurance limits as follows: Big Rock Point - $50 million per occurrence; Palisades - $1.115 billion per occurrence; and Indian Point - $1.6 billion per occurrence. For losses that are considered non-nuclear in nature, the property damage insurance limit at Palisades and Indian Point is $500 million. Property damage from wind and flood at Indian Point includes a deductible of $10 million plus an additional 10% of the amount of the loss in excess of $10 million, up to a maximum deductible of $50 million, but property damage from earthquake and volcanic eruption at Indian Point is excluded from the first $500 million. Property damage from wind, flood, earthquake, and volcanic eruption at Palisades includes a deductible of $10 million plus an additional 10% of the amount of the loss in excess of $10 million, up to a maximum deductible of $50 million. Property damage from wind, flood, earthquake, and volcanic eruption at Big Rock Point includes a deductible of $10 million plus an additional 10% of the amount of the loss in excess of $10 million, up to a maximum deductible of $14 million.

The value of the insured property at the time of an accident at Palisades has been changed from replacement cost to actual cash value.

In addition, Waterford 3 and Grand Gulf are also covered under NEIL’s Accidental Outage Coverage program.  Due to Entergy’s gradual exit from the merchant/wholesale power business, Entergy no longer purchases Accidental Outage Coverage for its non-regulated, non-generation assets. Accidental outage coverage provides indemnification for the actual cost incurred in the event of an unplanned outage resulting from property damage covered under the NEIL Primary Property Insurance policy, subject to a deductible period.  The indemnification for the actual cost incurred is based on market power prices at the time of the loss. After the deductible period has passed, weekly indemnities for an unplanned outage, covered under NEIL’s Accidental Outage Coverage program, would be paid according to the amounts listed below:

•	100% of the weekly indemnity for each week for the first payment period of 52 weeks; then

•	80% of the weekly indemnity for each week for the second payment period of 52 weeks; and thereafter

•	80% of the weekly indemnity for an additional 58 weeks for the third and final payment period.

    

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Under the property damage and accidental outage insurance programs, all NEIL insured plants could be subject to assessments should losses exceed the accumulated funds available from NEIL.  Effective April 1, 2019, the maximum amounts of such possible assessments per occurrence were as follows:

	Assessments
	(In Millions)
Utility:
Entergy Arkansas	$36.2
Entergy Louisiana	$51.5
Entergy Mississippi	$0.12
Entergy New Orleans	$0.12
Entergy Texas	N/A
System Energy	$24.1
Entergy Wholesale Commodities	$—

Potential assessments for the Entergy Wholesale Commodities plants are covered by insurance obtained through NEIL’s reinsurers.

NRC regulations provide that the proceeds of this insurance must be used, first, to render the reactor safe and stable, and second, to complete decontamination operations.  Only after proceeds are dedicated for such use and regulatory approval is secured would any remaining proceeds be made available for the benefit of plant owners or their creditors.

In the event that one or more acts of terrorism causes property damage under one or more or all nuclear insurance policies issued by NEIL (including, but not limited to, those described above) within 12 months from the date the first property damage occurs, the maximum recovery under all such nuclear insurance policies shall be an aggregate not exceeding $3.24 billion plus the additional amounts recovered for such losses from reinsurance, indemnity, and any other sources applicable to such losses.  

Non-Nuclear Property Insurance

Entergy’s non-nuclear property insurance program provides coverage on a system-wide basis for Entergy’s non-nuclear assets. The insurance program provides coverage for property damage up to $400 million per occurrence in excess of a $20 million self-insured retention except for property damage caused by the following: earthquake shock, flood, and named windstorm, including associated storm surge. For earthquake shock and flood, the insurance program provides coverage up to $400 million on an annual aggregate basis in excess of a $40 million self-insured retention. For named windstorm and associated storm surge, the insurance program provides coverage up to $125 million on an annual aggregate basis in excess of a $40 million self-insured retention.  The coverage provided by the insurance program for the Entergy New Orleans gas distribution system is limited to $50 million per occurrence and is subject to the same annual aggregate limits and retentions listed above for earthquake shock, flood, and named windstorm, including associated storm surge.

Covered property generally includes power plants, substations, facilities, inventories, and gas distribution-related properties.  Excluded property generally includes transmission and distribution lines, poles, and towers. For substations valued at $5 million or less, coverage for named windstorm and associated storm surge is excluded.  This coverage is in place for Entergy Corporation, the Registrant Subsidiaries, and certain other Entergy subsidiaries, including the Entergy Wholesale Commodities segment.  Entergy also purchases $300 million in terrorism insurance coverage for its conventional property.  The Terrorism Risk Insurance Reauthorization Act of 2007 created a government program that provides for up to $100 billion in coverage in excess of existing coverage for a terrorist event. Under current law, the Terrorism Risk Insurance Act extends through 2020.

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Employment and Labor-related Proceedings

The Registrant Subsidiaries and other Entergy subsidiaries are responding to various lawsuits in both state and federal courts and to other labor-related proceedings filed by current and former employees, recognized bargaining representatives, and certain third parties.  Generally, the amount of damages being sought is not specified in these proceedings.  These actions include, but are not limited to, allegations of wrongful employment actions; wage disputes and other claims under the Fair Labor Standards Act or its state counterparts; claims of race, gender, age, and disability discrimination; disputes arising under collective bargaining agreements; unfair labor practice proceedings and other administrative proceedings before the National Labor Relations Board or concerning the National Labor Relations Act; claims of retaliation; claims of harassment and hostile work environment; and claims for or regarding benefits under various Entergy Corporation-sponsored plans. Entergy and the Registrant Subsidiaries are responding to these lawsuits and proceedings and deny liability to the claimants.  Management believes that loss exposure has been and will continue to be handled so that the ultimate resolution of these matters will not be material, in the aggregate, to the financial position, results of operation, or cash flows of Entergy or the Utility operating companies.

Asbestos Litigation (Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas)

Numerous lawsuits have been filed in federal and state courts, primarily by contractor employees who worked in the 1940-1980s timeframe, primarily against Entergy Texas, and to a lesser extent the other Utility operating companies, as premises owners of power plants, for damages caused by alleged exposure to asbestos.  Many other defendants are named in these lawsuits as well.  Currently, there are approximately 200 lawsuits involving approximately 400 claimants.  Management believes that adequate provisions have been established to cover any exposure.  Additionally, negotiations continue with insurers to recover reimbursements.  Management believes that loss exposure has been and will continue to be handled so that the ultimate resolution of these matters will not be material, in the aggregate, to the financial position, results of operation, or cash flows of the Utility operating companies.

Grand Gulf - Related Agreements

Unit Power Sales Agreement (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

System Energy has agreed to sell all of its share of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans in accordance with specified percentages (Entergy Arkansas-36%, Entergy Louisiana-14%, Entergy Mississippi-33%, and Entergy New Orleans-17%) as ordered by the FERC.  Charges under this agreement are paid in consideration for the purchasing companies’ respective entitlement to receive capacity and energy and are payable irrespective of the quantity of energy delivered.  The agreement will remain in effect until terminated by the parties and the termination is approved by the FERC, most likely upon Grand Gulf’s retirement from service.  In December 2016 the NRC granted the extension of Grand Gulf’s operating license to 2044. Monthly obligations are based on actual capacity and energy costs.  The average monthly payments for 2019 under the agreement were approximately $17.6 million for Entergy Arkansas, $7 million for Entergy Louisiana, $15.5 million for Entergy Mississippi, and $8.5 million for Entergy New Orleans. See Note 2 to the financial statements for discussion of the complaints filed with the FERC against System Energy seeking a reduction in the return on equity component of the Unit Power Sales Agreement.

Availability Agreement (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans are individually obligated to make payments or subordinated advances to System Energy in accordance with stated percentages (Entergy Arkansas-17.1%, Entergy Louisiana-26.9%, Entergy Mississippi-31.3%, and Entergy New Orleans-24.7%) in amounts that, when added to amounts received under the Unit Power Sales Agreement or otherwise, are adequate to cover all

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of System Energy’s operating expenses as defined, including an amount sufficient to amortize the cost of Grand Gulf 2 over 27 years (See Reallocation Agreement terms below) and expenses incurred in connection with a permanent shutdown of Grand Gulf.  System Energy has assigned its rights to payments and advances to certain creditors as security for certain obligations.  Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement have exceeded the amounts payable under the Availability Agreement.  Accordingly, no payments under the Availability Agreement have ever been required.  If Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy Louisiana and Entergy New Orleans could become subject to claims or demands by System Energy or its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments.

Reallocation Agreement (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans entered into the Reallocation Agreement relating to the sale of capacity and energy from Grand Gulf and the related costs, in which Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans agreed to assume all of Entergy Arkansas’s responsibilities and obligations with respect to Grand Gulf under the Availability Agreement.  The FERC’s decision allocating a portion of Grand Gulf capacity and energy to Entergy Arkansas supersedes the Reallocation Agreement as it relates to Grand Gulf.  Responsibility for any Grand Gulf 2 amortization amounts has been individually allocated (Entergy Louisiana-26.23%, Entergy Mississippi-43.97%, and Entergy New Orleans-29.80%) under the terms of the Reallocation Agreement.  However, the Reallocation Agreement does not affect Entergy Arkansas’s obligation to System Energy’s lenders under the assignments referred to in the preceding paragraph.  Entergy Arkansas would be liable for its share of such amounts if Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans were unable to meet their contractual obligations.  No payments of any amortization amounts will be required so long as amounts paid to System Energy under the Unit Power Sales Agreement, including other funds available to System Energy, exceed amounts required under the Availability Agreement, which is expected to be the case for the foreseeable future.

Accounting standards require companies to record liabilities for all legal obligations associated with the retirement of long-lived assets that result from the normal operation of the assets.  For Entergy, substantially all of its asset retirement obligations consist of its liability for decommissioning its nuclear power plants.  In addition, an insignificant amount of removal costs associated with non-nuclear power plants is also included in the decommissioning and asset retirement costs line item on the balance sheets.

 

These liabilities are recorded at their fair values (which are the present values of the estimated future cash outflows) in the period in which they are incurred, with an accompanying addition to the recorded cost of the long-lived asset.  The asset retirement obligation is accreted each year through a charge to expense, to reflect the time value of money for this present value obligation.  The accretion will continue through the completion of the asset retirement activity.  The amounts added to the carrying amounts of the long-lived assets will be depreciated over the useful lives of the assets.  The application of accounting standards related to asset retirement obligations is earnings neutral to the rate-regulated business of the Registrant Subsidiaries.

In accordance with ratemaking treatment and as required by regulatory accounting standards, the depreciation provisions for the Registrant Subsidiaries include a component for removal costs that are not asset retirement obligations under accounting standards.  In accordance with regulatory accounting principles, the Registrant Subsidiaries have recorded regulatory assets (liabilities) in the following amounts to reflect their estimates of the difference between estimated incurred removal costs and estimated removal costs recovered in rates:

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	December 31,
	2019		2018
	(In Millions)
Entergy Arkansas	$168.9		$138.3
Entergy Louisiana	($2.4)		($18.8)
Entergy Mississippi	$80.8		$63.5
Entergy New Orleans	$52.9		$49.3
Entergy Texas	$42.5		$50.9
System Energy	$75.9		$76.4

The cumulative decommissioning and retirement cost liabilities and expenses recorded in 2019 and 2018 by Entergy were as follows:

	Liabilities as of December 31, 2018				Accretion				Change in Cash Flow Estimate				Spending				Dispositions				Liabilities as of December 31, 2019
	(In Millions)
Entergy		$6,923.4				$414.0				$273.7				($45.6	)			($1,406.3	)			$6,159.2
Utility
Entergy Arkansas	1,048.4				68.0				126.2				—				—				1,242.6
Entergy Louisiana	1,280.3				69.5				147.5				—				—				1,497.3
Entergy Mississippi	9.2				0.5				—				—				—				9.7
Entergy New Orleans	3.3				0.2				—				—				—				3.5
Entergy Texas	7.2				0.4				—				—				—				7.6
System Energy	896.0				35.7				—				—				—				931.7
Entergy Wholesale Commodities
Big Rock Point	39.7				3.2				—				(2.6		)		—				40.3
Indian Point 1	227.9				19.5				—				(8.8		)		—				238.6
Indian Point 2	768.0				65.5				—				(4.5		)		—				829.0
Indian Point 3	750.6				62.5				—				(4.7		)		—				808.4
Palisades	508.0				42.9				—				(1.1		)		—				549.8
Pilgrim	816.5				44.1				—				(23.9		)		(836.7		)	(b)	—
Vermont Yankee	567.9				1.7				—				—				(569.6		)	(b)	—
Other (a)	0.4				0.1				—				—				—				0.5

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	Liabilities as of December 31, 2017				Accretion				Change in Cash Flow Estimate				Spending				Liabilities as of December 31, 2018
	(In Millions)
Entergy		$6,185.8				$423.5				$505.4				($191.3	)			$6,923.4
Utility
Entergy Arkansas	981.2				60.4				8.9				(2.1		)		1,048.4
Entergy Louisiana	1,140.5				63.2				85.4				(8.8		)		1,280.3
Entergy Mississippi	9.2				0.5				0.5				(1.0		)		9.2
Entergy New Orleans	3.1				0.2				—				—				3.3
Entergy Texas	6.8				0.4				—				—				7.2
System Energy	861.7				34.3				—				—				896.0
Entergy Wholesale Commodities
Big Rock Point	38.9				3.2				—				(2.4		)		39.7
Indian Point 1	217.6				18.6				—				(8.3		)		227.9
Indian Point 2	708.7				60.6				—				(1.3		)		768.0
Indian Point 3	694.5				58.0				—				(1.9		)		750.6
Palisades	470.4				39.6				—				(2.0		)		508.0
Pilgrim	651.4				58.6				117.5				(11.0		)		816.5
Vermont Yankee	401.5				25.9				293.0				(152.5		)		567.9			(c)
Other (a)	0.3				—				0.1				—				0.4

(a)	See “Coal Combustion Residuals” below for additional discussion regarding the asset retirement obligations related to coal combustion residuals management.

(b)	See Note 14 to the financial statements for discussion of the sale of the Pilgrim plant to Holtec International in August 2019 and the sale of the Vermont Yankee plant to NorthStar in January 2019.

(c)	The Vermont Yankee asset retirement obligation was classified as held for sale within other non-current liabilities on the consolidated balance sheet as of December 31, 2018.

Nuclear Plant Decommissioning

Entergy periodically reviews and updates estimated decommissioning costs.  The actual decommissioning costs may vary from the estimates because of the timing of plant decommissioning, regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment.  As described below, during 2019, 2018, and 2017, Entergy updated decommissioning cost estimates for certain nuclear power plants.

Utility

In the first quarter 2018, Entergy Louisiana recorded a revision to its estimated decommissioning cost liability for River Bend as a result of a revised decommissioning cost study. The revised estimate resulted in an $85.4 million increase in its decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.

In the first quarter 2019, Entergy Arkansas recorded a revision to its estimated decommissioning cost liabilities for ANO 1 and ANO 2 as a result of a revised decommissioning cost study. The revised estimates resulted in a $126.2

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million increase in its decommissioning cost liabilities, along with corresponding increases in the related asset retirement cost assets that will be depreciated over the remaining lives of the units.

In the second quarter 2019, Entergy Louisiana recorded a revision to its estimated decommissioning cost liability for Waterford 3 as a result of a revised decommissioning cost study. The revised estimate resulted in a $147.5 million increase in its decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining useful life of the unit.

Entergy Wholesale Commodities

Palisades

In the third quarter 2017, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Palisades. The revised estimate resulted in a $68.7 million reduction in its decommissioning cost liability, along with a corresponding reduction in the plant asset. The reduction in its estimated decommissioning cost liability resulted from the change in expectation regarding the timing of decommissioning cash flows due to the decision to continue to operate the plant until May 31, 2022.

Pilgrim

Entergy Nuclear Generation Company filed its Post-Shutdown Decommissioning Activities report (PSDAR) with the NRC in the fourth quarter 2018 for the Pilgrim plant in anticipation of its May 2019 shutdown. As part of the development of the PSDAR, Entergy obtained a revised decommissioning cost study in the third quarter 2018. The revised estimate resulted in a $117.5 million increase in the decommissioning cost liability and a corresponding impairment charge.

Vermont Yankee

In the fourth quarter 2018, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Vermont Yankee. The revised estimate resulted in a $293 million increase in the decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset. The revision was prompted by the progress of the Vermont Yankee sales transaction, which is described in Note 14 to the financial statements. Entergy accordingly evaluated the Vermont Yankee asset retirement obligation in light of the terms of the sale transaction, upon determining that Vermont Yankee was in held for sale status. Based on the terms of the sales agreement, which include Entergy receiving a note receivable from the purchaser, Entergy determined that $165 million of the asset retirement cost was impaired, and it was accordingly written down in the fourth quarter 2018. The Vermont Yankee plant was sold to NorthStar in January 2019.

NRC Filings Regarding Trust Funding Levels

Plant owners are required to provide the NRC with a biennial report (annually for units that have shut down or will shut down within five years), based on values as of December 31, addressing the owners’ ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, plant owners may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met.

As nuclear plants individually approach and begin decommissioning, filings will be submitted to the NRC for planned shutdown activities. These filings with the NRC also determine whether financial assurance may be required in addition to the nuclear decommissioning trust fund.

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Coal Combustion Residuals

In June 2010 the EPA issued a proposed rule on coal combustion residuals (CCRs) that contained two primary regulatory options: (1) regulating CCRs destined for disposal in landfills or received (including stored) in surface impoundments as so-called “special wastes” under the hazardous waste program of Resource Conservation and Recovery Act (RCRA) Subtitle C; or (2) regulating CCRs destined for disposal in landfills or surface impoundments as non-hazardous wastes under Subtitle D of RCRA.  Under both options, CCRs that are beneficially reused in certain processes would remain excluded from hazardous waste regulation. In April 2015 the EPA published the final CCR rule with the material being regulated under the second scenario presented above - as non-hazardous wastes regulated under RCRA Subtitle D. The final regulations create new compliance requirements including modified storage, new notification and reporting practices, product disposal considerations, and CCR unit closure criteria.  Entergy believes that on-site disposal options will be available at its facilities, to the extent needed for CCR that cannot be transferred for beneficial reuse. In December 2016, the Water Infrastructure Improvements for the Nation Act (WIIN Act) was signed into law, which authorizes states to regulate coal ash rather than leaving primary enforcement to citizen suit actions. States may submit to the EPA proposals for permit programs. In September 2017 the EPA agreed to reconsider certain provisions of the coal combustion residuals (CCR) rule in light of the WIIN Act. In March 2018 the EPA published its proposed revisions to the CCR rule with comments due at the end of April 2018. In July 2018 the EPA released its initial revisions extending certain deadlines and incorporating some risk-based standards.  The EPA is expected to release additional revisions in another rulemaking.  In August 2018 the D.C. Circuit vacated several provisions of the CCR rule on the basis that they were inconsistent with the Resource Conservation and Recovery Act and remanded the matter to the EPA to conduct further rulemaking. In August 2019 the EPA released its second set of proposed revisions to the CCR rule and plans at least three additional rulemakings.

In 2018 revisions to the CCR asset retirement obligations were made as a result of revised closure and post-closure cost estimates. The revised estimates resulted in increases of $8.9 million at Entergy Arkansas, $0.5 million at Entergy Mississippi, and $0.1 million at Entergy Wholesale Commodities in decommissioning cost liabilities, along with corresponding increases in related asset retirement cost assets that will be depreciated over the remaining useful lives of the respective units.

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Entergy implemented ASU 2016-02, “Leases (Topic 842),” effective January 1, 2019. The ASU’s core principle is that “a lessee should recognize the assets and liabilities that arise from leases.” The ASU considers that “all leases create an asset and a liability,” and accordingly requires recording the assets and liabilities related to all leases with a term greater than 12 months. Concurrent with the implementation of ASU 2016-02, Entergy implemented ASU 2018-01, “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842,” which provided Entergy the option to elect not to evaluate existing land easements that are not currently accounted for as leases under the previous lease standard, and ASU 2018-11, “Leases (Topic 842): Targeted Improvements,” which intended to simplify the transition requirement giving Entergy the option to apply the transition provisions of the new standard at the date of adoption instead of at the earliest comparative period. In implementing these ASUs, Entergy elected the options provided in both ASU 2018-01 and ASU 2018-11. This accounting was applied to all lease agreements using the modified retrospective method, which required an adjustment to retained earnings for the cumulative effect of adopting the standard as of the effective date, and when implemented with ASU 2018-11, allowed Entergy to recognize the leased assets and liabilities on its balance sheet beginning on January 1, 2019 without restating prior periods. In adopting the standard in January 2019, Entergy recognized right-of-use assets and corresponding lease liabilities totaling approximately $263 million, including $59 million for Entergy Arkansas, $51 million for Entergy Louisiana, $26 million for Entergy Mississippi, $7 million for Entergy New Orleans, and $16 million for Entergy Texas. Implementation of the standards had no material effect on consolidated net income; therefore, no adjustment to retained earnings was recorded. The adoption of the standards had no effect on cash flows.

General

As of December 31, 2019, Entergy and the Registrant Subsidiaries held operating and finance leases for fleet vehicles used in operations, real estate, and aircraft. Excluded are power purchase agreements not meeting the definition of a lease, nuclear fuel leases, and the Grand Gulf sale-leaseback which were determined not to be leases under the accounting standards.

Leases have remaining terms of one year to 60 years. Real estate leases generally include at least one five-year renewal option; however, renewal is not typically considered reasonably certain unless Entergy or a Registrant Subsidiary makes significant leasehold improvements or other modifications that would hinder its ability to easily move. In certain of the lease agreements for fleet vehicles used in operations, Entergy and the Registrant Subsidiaries provide residual value guarantees to the lessor. Due to the nature of the agreements and Entergy’s continuing relationship with the lessor, however, Entergy and the Registrant Subsidiaries expect to renegotiate or refinance the leases prior to conclusion of the lease. As such, Entergy and the Registrant Subsidiaries do not believe it is probable that they will be required to pay anything pertaining to the residual value guarantee, and the lease liabilities and right-of-use assets are measured accordingly.

Entergy incurred the following total lease costs for the year ended December 31, 2019:

		(In Thousands)
Operating lease cost			$63,566
Finance lease cost:
Amortization of right-of-use assets			$16,048
Interest on lease liabilities			$3,667

The lease costs disclosed above materially approximate the cash flows used by Entergy for leases with all costs included within operating activities on the Consolidated Statements of Cash Flows, except for the finance lease costs which are included in financing activities.

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The Registrant Subsidiaries incurred the following lease costs for the year ended December 31, 2019:

	Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas
	(In Thousands)
Operating lease cost		$13,213				$11,975				$6,927				$1,406				$4,259
Finance lease cost:
Amortization of right-of-use assets		$3,643				$5,940				$2,097				$1,042				$1,568
Interest on lease liabilities		$594				$895				$353				$168				$241

The lease costs disclosed above materially approximate the cash flows used by the Registrant Subsidiaries for leases with all costs included within operating activities on the respective Statements of Cash Flows, except for the finance lease costs which are included in financing activities.

Entergy has elected to account for short-term leases in accordance with policy options provided by accounting guidance; therefore, there are no related lease liabilities or right-of-use assets for the costs recognized above by Entergy or by its Registrant Subsidiaries in the table below.

Included within Property, Plant, and Equipment on Entergy’s consolidated balance sheet at December 31, 2019 are $234 million related to operating leases and $61 million related to finance leases.

Included within Utility Plant on the Registrant Subsidiaries’ respective balance sheets at December 31, 2019 are the following amounts:

	Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas
	(In Thousands)
Operating leases		$52,317				$36,034				$16,900				$3,878				$14,020
Finance leases		$11,216				$17,209				$6,869				$3,291				$5,273

The following lease-related liabilities are recorded within the respective Other lines on Entergy’s consolidated balance sheet as of December 31, 2019:

		(In Thousands)
Current liabilities:
Operating leases			$52,678
Finance leases			$11,413
Non-current liabilities:
Operating leases			$181,339
Finance leases			$53,396

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The following lease-related liabilities are recorded within the respective Other lines on the Registrant Subsidiaries’ respective balance sheets at December 31, 2019:

	Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas
	(In Thousands)
Current liabilities:
Operating leases		$11,443				$10,331				$5,633				$1,134				$3,698
Finance leases		$2,442				$3,919				$1,487				$647				$1,222
Non-current liabilities:
Operating leases		$40,880				$25,743				$11,232				$2,746				$10,364
Finance leases		$8,768				$13,376				$5,382				$2,644				$4,009

The following information contains the weighted average remaining lease term in years and the weighted average discount rate for the operating and finance leases of Entergy at December 31, 2019:

Weighted average remaining lease terms:
Operating leases		5.14
Finance leases		6.69
Weighted average discount rate:
Operating leases		3.86	%
Finance leases		4.60	%

The following information contains the weighted average remaining lease term in years and the weighted average discount rate for the operating and finance leases of the Registrant Subsidiaries at December 31, 2019:

	Entergy Arkansas			Entergy Louisiana			Entergy Mississippi			Entergy New Orleans			Entergy Texas
Weighted average remaining lease terms:
Operating leases	5.84			4.33			5.04			5.62			4.54
Finance leases	5.43			5.24			5.32			5.93			5.12
Weighted average discount rate:
Operating leases	3.67	%		3.65	%		3.75	%		3.88	%		3.73	%
Finance leases	3.68	%		3.65	%		3.67	%		3.74	%		3.82	%

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Maturity of the lease liabilities for Entergy as of December 31, 2019 are as follows:

Year		Operating Leases				Finance Leases
		(In Thousands)
2020			$62,124				$14,014
2021		56,386				12,457
2022		47,919				11,253
2023		37,228				10,121
2024		30,376				8,454
Years thereafter		29,138				20,010
Minimum lease payments		263,171				76,309
Less: amount representing interest		29,153				11,500
Present value of net minimum lease payments			$234,018				$64,809

Maturity of the lease liabilities for the Registrant Subsidiaries as of December 31, 2019 are as follows:

Operating Leases

Year		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas
		(In Thousands)
2020			$13,010				$11,376				$6,112				$1,248				$4,339
2021		11,165				9,645				4,983				991				3,611
2022		8,788				6,935				3,566				711				2,689
2023		7,193				4,916				1,454				549				2,336
2024		5,866				3,089				731				310				1,684
Years thereafter		12,021				2,972				1,972				522				1,119
Minimum lease payments		58,043				38,933				18,818				4,331				15,778
Less: amount representing interest		5,720				2,860				1,953				452				1,716
Present value of net minimum lease payments			$52,323				$36,073				$16,865				$3,879				$14,062

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Finance Leases

Year		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas
		(In Thousands)
2020			$2,772				$4,422				$1,692				$744				$1,382
2021		2,369				3,766				1,527				634				1,188
2022		2,079				3,325				1,334				581				981
2023		1,833				2,856				1,111				532				839
2024		1,489				2,092				838				449				648
Years thereafter		1,787				2,476				1,038				713				706
Minimum lease payments		12,329				18,937				7,540				3,653				5,744
Less: amount representing interest		1,119				1,641				670				362				512
Present value of net minimum lease payments			$11,210				$17,296				$6,870				$3,291				$5,232

In allocating consideration in lease contracts to the lease and non-lease components, Entergy and the Registrant Subsidiaries have made the accounting policy election to combine lease and non-lease components related to fleet vehicles used in operations, fuel storage agreements, and purchased power agreements and to allocate the contract consideration to both lease and non-lease components for real estate leases.

In accordance with ASU 2018-11, below is the lease disclosure from Note 10 to the financial statements in the Form 10-K for the year ended December 31, 2018.

General

As of December 31, 2018, Entergy had capital leases and non-cancelable operating leases for equipment, buildings, vehicles, and fuel storage facilities with minimum lease payments as follows (excluding power purchase agreement operating leases, nuclear fuel leases, and the Grand Gulf sale and leaseback transaction, all of which are discussed elsewhere):

Year		Operating Leases				Capital Leases
		(In Thousands)
2019			$94,043				$2,887
2020		82,191				2,887
2021		75,147				2,887
2022		60,808				2,887
2023		47,391				2,887
Years thereafter		88,004				16,117
Minimum lease payments		447,584				30,552
Less:  Amount representing interest		—				8,555
Present value of net minimum lease payments			$447,584				$21,997

Total rental expenses for all leases (excluding power purchase agreement operating leases, nuclear fuel leases, and the Grand Gulf and Waterford 3 sale and leaseback transactions) amounted to $47.8 million in 2018, $53.1 million in 2017, and $44.4 million in 2016.

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As of December 31, 2018, the Registrant Subsidiaries had non-cancelable operating leases for equipment, buildings, vehicles, and fuel storage facilities with minimum lease payments as follows (excluding power purchase agreement operating leases, nuclear fuel leases, and the Grand Gulf lease obligation, all of which are discussed elsewhere):

Operating Leases

Year		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas
		(In Thousands)
2019			$20,421				$25,970				$9,344				$2,493				$5,744
2020		13,918				21,681				8,763				2,349				4,431
2021		11,931				19,514				7,186				1,901				3,625
2022		9,458				15,756				5,675				1,314				2,218
2023		7,782				12,092				2,946				1,043				1,561
Years thereafter		23,297				22,003				4,417				2,323				2,726
Minimum lease payments			$86,807				$117,016				$38,331				$11,423				$20,305

Rental Expenses

Year		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
		(In Millions)
2018			$6.2				$20.2				$4.6				$2.5				$3.1				$1.9
2017			$7.5				$23.0				$5.6				$2.5				$3.4				$2.2
2016			$8.0				$17.8				$4.0				$0.9				$2.8				$1.6

In addition to the above rental expense, railcar operating lease payments and oil tank facilities lease payments are recorded in fuel expense in accordance with regulatory treatment.  Railcar operating lease payments were $2.8 million in 2018, $4 million in 2017, and $3.4 million in 2016 for Entergy Arkansas and $0.4 million in 2018, $0.3 million in 2017, and $0.3 million in 2016 for Entergy Louisiana.  Oil tank facilities lease payments for Entergy Mississippi were $0.1 million in 2018, $1.6 million in 2017, and $1.6 million in 2016.

Power Purchase Agreements

As of December 31, 2018, Entergy Texas had a power purchase agreement that is accounted for as an operating lease under the accounting standards. The lease payments are recovered in fuel expense in accordance with regulatory treatment. The minimum lease payments under the power purchase agreement are as follows:

Year		Entergy Texas (a)				Entergy
		(In Thousands)
2019			$31,159				$31,159
2020		31,876				31,876
2021		32,609				32,609
2022		10,180				10,180
Minimum lease payments			$105,824				$105,824

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(a)	Amounts reflect 100% of minimum payments. Under a separate contract, which expires May 31, 2022, Entergy Louisiana purchases 50% of the capacity and energy from the power purchase agreement from Entergy Texas.

Total capacity expense under the power purchase agreement accounted for as an operating lease at Entergy Texas was $30.5 million in 2018, $34.1 million in 2017, and $26.1 million in 2016.

Sales and Leaseback Transactions

Waterford 3 Lease Obligation

In 1989, in three separate but substantially identical transactions, Entergy Louisiana sold and leased back undivided interests in Waterford 3 for the aggregate sum of $353.6 million.  The leases were scheduled to expire in July 2017.  Entergy Louisiana was required to report the sale-leaseback as a financing transaction in its financial statements.

In December 2015, Entergy Louisiana agreed to purchase the undivided interests in Waterford 3 that were previously being leased. The purchase was accomplished in a two-step transaction in which Entergy Louisiana first acquired the equity participant’s beneficial interest in the leased assets, followed by a termination of the leases and transfer of the leased assets to Entergy Louisiana when the outstanding lessor debt is paid.

In March 2016, Entergy Louisiana completed the first step in the two-step transaction by acquiring the equity participant’s beneficial interest in the leased assets. Entergy Louisiana paid $60 million in cash and $52 million through the issuance of a non-interest bearing collateral trust mortgage note, payable in installments through July 2017. Entergy Louisiana continued to make payments on the lessor debt that remained outstanding and that matured in January 2017. The combination of payments on the $52 million collateral trust mortgage note issued and the debt service on the lessor debt was equal in timing and amount to the remaining lease payments due from the closing of the transaction through the end of the lease term in July 2017.

Throughout the term of the lease, Entergy Louisiana had accrued a liability for the amount it expected to pay to retain the use of the undivided interests in Waterford 3 at the end of the lease term. Since the sale-leaseback transaction was accounted for as a financing transaction, the accrual of this liability was accounted for as additional interest expense. As of December 2015, the balance of this liability was $62.7 million. Upon entering into the agreement to purchase the equity participant’s beneficial interest in the undivided interests, Entergy Louisiana reduced the balance of the liability to $60 million, and recorded the $2.7 million difference as a credit to interest expense. The $60 million remaining liability was eliminated upon payment of the cash portion of the purchase price in 2016.

As of December 31, 2016, Entergy Louisiana, in connection with the Waterford 3 lease obligation, had a future minimum lease payment of $57.5 million, including $2.3 million in interest, due January 2017 that was recorded as long-term debt.

In February 2017 the leases were terminated and the leased assets were conveyed to Entergy Louisiana.

Grand Gulf Lease Obligations

In 1988, in two separate but substantially identical transactions, System Energy sold and leased back undivided ownership interests in Grand Gulf for the aggregate sum of $500 million.  The initial term of the leases expired in July 2015.  System Energy renewed the leases in December 2013 for fair market value with renewal terms expiring in July 2036. At the end of the new lease renewal terms, System Energy has the option to repurchase the leased interests in Grand Gulf or renew the leases at fair market value.  In the event that System Energy does not renew or purchase the interests, System Energy would surrender such interests and their associated entitlement of Grand Gulf’s capacity and energy.

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System Energy is required to report the sale-leaseback as a financing transaction in its financial statements.  For financial reporting purposes, System Energy expenses the interest portion of the lease obligation and the plant depreciation.  However, operating revenues include the recovery of the lease payments because the transactions are accounted for as a sale and leaseback for ratemaking purposes.  Consistent with a recommendation contained in a FERC audit report, System Energy initially recorded as a net regulatory asset the difference between the recovery of the lease payments and the amounts expensed for interest and depreciation and continues to record this difference as a regulatory asset or liability on an ongoing basis, resulting in a zero net balance for the regulatory asset at the end of the lease term.  The amount was a net regulatory liability of $55.6 million as of December 31, 2018 and 2017.

As of December 31, 2018, System Energy, in connection with the Grand Gulf sale and leaseback transactions, had future minimum lease payments that are recorded as long-term debt, as follows, which reflects the effect of the December 2013 renewal:

	Amount
	(In Thousands)
2019		$17,188
2020	17,188
2021	17,188
2022	17,188
2023	17,188
Years thereafter	223,437
Total	309,377
Less: Amount representing interest	275,025
Present value of net minimum lease payments		$34,352

Qualified Pension Plans

Entergy has eight defined benefit qualified pension plans covering substantially all employees. The Entergy Corporation Retirement Plan for Non-Bargaining Employees (Non-Bargaining Plan I), the Entergy Corporation Retirement Plan for Bargaining Employees (Bargaining Plan I), the Entergy Corporation Retirement Plan II for Non-Bargaining Employees (Non-Bargaining Plan II), the Entergy Corporation Retirement Plan II for Bargaining Employees, the Entergy Corporation Retirement Plan III, and the Entergy Corporation Retirement Plan IV for Bargaining Employees are non-contributory final average pay plans and provide pension benefits that are based on employees’ credited service and compensation during employment.  Non-bargaining employees whose most recent date of hire is after June 30, 2014 participate in the Entergy Corporation Cash Balance Plan for Non-Bargaining Employees (Non-Bargaining Cash Balance Plan). Certain bargaining employees hired or rehired after June 30, 2014, or such later date provided for in their applicable collective bargaining agreements, participate in the Entergy Corporation Cash Balance Plan for Bargaining Employees (Bargaining Cash Balance Plan). The Registrant Subsidiaries participate in these four plans: Non-Bargaining Plan I, Bargaining Plan I, Non-Bargaining Cash Balance Plan, and Bargaining Cash Balance Plan.

The assets of the six final average pay defined benefit qualified pension plans are held in a master trust established by Entergy, and the assets of the two cash balance pension plans are held in a second master trust established by Entergy.  Each pension plan has an undivided beneficial interest in each of the investment accounts in its respective master trust that is maintained by a trustee.  Use of the master trusts permits the commingling of the trust assets of the pension plans of Entergy Corporation and its Registrant Subsidiaries for investment and administrative

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purposes.  Although assets in the master trusts are commingled, the trustee maintains supporting records for the purpose of allocating the trust level equity in net earnings (loss) and the administrative expenses of the investment accounts in each trust to the various participating pension plans in that particular trust.  The fair value of the trusts’ assets is determined by the trustee and certain investment managers.  For each trust, the trustee calculates a daily earnings factor, including realized and unrealized gains or losses, collected and accrued income, and administrative expenses, and allocates earnings to each plan in the master trusts on a pro rata basis.

Within each pension plan, the record of each Registrant Subsidiary’s beneficial interest in the plan assets is maintained by the plan’s actuary and is updated quarterly.  Assets for each Registrant Subsidiary are increased for investment net income and contributions, and are decreased for benefit payments.  A plan’s investment net income/loss (i.e. interest and dividends, realized and unrealized gains and losses and expenses) is allocated to the Registrant Subsidiaries participating in that plan based on the value of assets for each Registrant Subsidiary at the beginning of the quarter adjusted for contributions and benefit payments made during the quarter.

Entergy Corporation and its subsidiaries fund pension plans in an amount not less than the minimum required contribution under the Employee Retirement Income Security Act of 1974, as amended, and the Internal Revenue Code of 1986, as amended.  The assets of the plans include common and preferred stocks, fixed-income securities, interest in a money market fund, and insurance contracts.  The Registrant Subsidiaries’ pension costs are recovered from customers as a component of cost of service in each of their respective jurisdictions.

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Components of Qualified Net Pension Cost and Other Amounts Recognized as a Regulatory Asset and/or Accumulated Other Comprehensive Income (AOCI)

Entergy Corporation and its subsidiaries’ total 2019, 2018, and 2017 qualified pension costs and amounts recognized as a regulatory asset and/or other comprehensive income, including amounts capitalized, included the following components:

	2019				2018				2017
	(In Thousands)
Net periodic pension cost:
Service cost - benefits earned during the period		$134,193				$155,010				$133,641
Interest cost on projected benefit obligation	293,114				267,415				260,824
Expected return on assets	(414,947		)		(442,142		)		(408,225		)
Amortization of prior service cost	—				398				261
Recognized net loss	241,117				274,104				227,720
Settlement charges	23,492				828				—
Net periodic pension costs		$276,969				$255,613				$214,221
Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)
Arising this period:
Net loss		$614,600				$394,951				$368,067
Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:
Amortization of prior service cost	—				(398		)		(261		)
Amortization of net loss	(241,117		)		(274,104		)		(227,720		)
Settlement charge	(23,492		)		(828		)		—
Total		$349,991				$119,621				$140,086
Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax)		$626,960				$375,234				$354,307
Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year:
Prior service cost		$—				$—				$398
Net loss		$349,038				$233,677				$274,104

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The Registrant Subsidiaries’ total 2019, 2018, and 2017 qualified pension costs and amounts recognized as a regulatory asset and/or other comprehensive income, including amounts capitalized, for their employees included the following components:

2019		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
		(In Thousands)
Net periodic pension cost:
Service cost - benefits earned during the period			$21,043				$29,137				$6,516				$2,274				$5,401				$6,199
Interest cost on projected benefit obligation		56,701				63,529				16,272				7,495				14,451				13,456
Expected return on assets		(80,705		)		(90,607		)		(23,873		)		(10,785		)		(23,447		)		(18,710		)
Recognized net loss		47,361				46,571				12,416				6,117				9,335				11,400
Net pension cost			$44,400				$48,630				$11,331				$5,101				$5,740				$12,345
Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)
Arising this period:
Net loss			$118,898				$99,346				$41,088				$6,531				$10,869				$36,711
Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:
Amortization of net loss		(47,361		)		(46,571		)		(12,416		)		(6,117		)		(9,335		)		(11,400		)
Total			$71,537				$52,775				$28,672				$414				$1,534				$25,311
Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax)			$115,937				$101,405				$40,003				$5,515				$7,274				$37,656
Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year
Net loss			$67,588				$66,509				$18,994				$8,018				$13,060				$17,117

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2018		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
		(In Thousands)
Net periodic pension cost:
Service cost - benefits earned during the period			$24,757				$33,783				$7,286				$2,693				$6,356				$7,102
Interest cost on projected benefit obligation		52,017				59,761				15,075				7,253				13,390				12,907
Expected return on assets		(87,404		)		(99,236		)		(26,007		)		(11,973		)		(26,091		)		(19,963		)
Recognized net loss		53,650				57,800				14,438				7,816				10,503				14,859
Net pension cost			$43,020				$52,108				$10,792				$5,789				$4,158				$14,905
Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)
Arising this period:
Net (gain)/loss			$74,570				$41,642				$19,244				$2,351				$24,121				($2,359	)
Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:
Amortization of net loss		(53,650		)		(57,800		)		(14,438		)		(7,816		)		(10,503		)		(14,859		)
Total			$20,920				($16,158	)			$4,806				($5,465	)			$13,618				($17,218	)
Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax)			$63,940				$35,950				$15,598				$324				$17,776				($2,313	)
Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year
Net loss			$47,361				$46,571				$12,416				$6,117				$9,335				$11,400

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2017		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
		(In Thousands)
Net periodic pension cost:
Service cost - benefits earned during the period			$20,358				$27,698				$5,890				$2,500				$5,455				$6,145
Interest cost on projected benefit obligation		51,776				59,235				14,927				7,163				13,569				12,364
Expected return on assets		(81,707		)		(92,067		)		(24,526		)		(11,199		)		(24,722		)		(18,650		)
Recognized net loss		46,560				49,417				12,213				6,632				9,241				11,857
Net pension cost			$36,987				$44,283				$8,504				$5,096				$3,543				$11,716
Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)
Arising this period:
Net loss			$51,569				$57,510				$14,681				$8,601				$1,109				$27,733
Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:
Amortization of net loss		(46,560		)		(49,417		)		(12,213		)		(6,632		)		(9,241		)		(11,857		)
Total			$5,009				$8,093				$2,468				$1,969				($8,132	)			$15,876
Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax)			$41,996				$52,376				$10,972				$7,065				($4,589	)			$27,592
Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year
Net loss			$53,650				$57,800				$14,438				$7,816				$10,503				$14,859

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Qualified Pension Obligations, Plan Assets, Funded Status, Amounts Recognized in the Balance Sheet

Qualified pension obligations, plan assets, funded status, amounts recognized in the Consolidated Balance Sheets for Entergy Corporation and its Subsidiaries as of December 31, 2019 and 2018 are as follows:

	2019				2018
	(In Thousands)
Change in Projected Benefit Obligation (PBO)
Balance at January 1		$7,404,917				$7,987,087
Service cost	134,193				155,010
Interest cost	293,114				267,415
Actuarial (gain)/loss	1,292,767				(395,242		)
Benefits paid (including settlement lump sum benefit payments of ($68,203) in 2019 and ($1,794) in 2018)	(718,788		)		(609,353		)
Balance at December 31		$8,406,203				$7,404,917
Change in Plan Assets
Fair value of assets at January 1		$5,497,415				$6,071,316
Actual return on plan assets	1,093,114				(348,051		)
Employer contributions	399,419				383,503
Benefits paid (including settlement lump sum benefit payments of ($68,203) in 2019 and ($1,794) in 2018)	(718,788		)		(609,353		)
Fair value of assets at December 31		$6,271,160				$5,497,415
Funded status		($2,135,043	)			($1,907,502	)
Amount recognized in the balance sheet
Non-current liabilities		($2,135,043	)			($1,907,502	)
Amount recognized as a regulatory asset
Net loss		$2,831,408				$2,468,987
Amount recognized as AOCI (before tax)
Net loss		$724,575				$737,004

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Qualified pension obligations, plan assets, funded status, amounts recognized in the Balance Sheets for the Registrant Subsidiaries as of December 31, 2019 and 2018 are as follows:

2019		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
		(In Thousands)
Change in Projected Benefit Obligation (PBO)
Balance at January 1			$1,443,808				$1,599,916				$414,089				$191,190				$369,604				$339,034
Service cost		21,043				29,137				6,516				2,274				5,401				6,199
Interest cost		56,701				63,529				16,272				7,495				14,451				13,456
Actuarial loss		248,213				248,509				79,453				24,299				49,235				66,460
Benefits paid		(154,681		)		(156,617		)		(44,820		)		(18,296		)		(41,927		)		(31,542		)
Balance at December 31			$1,615,084				$1,784,474				$471,510				$206,962				$396,764				$393,607
Change in Plan Assets
Fair value of assets at January 1			$1,068,842				$1,215,926				$316,716				$145,968				$315,514				$245,516
Actual return on plan assets		210,020				239,770				62,238				28,552				61,814				48,460
Employer contributions		75,854				64,951				20,794				4,553				3,725				20,234
Benefits paid		(154,681		)		(156,617		)		(44,820		)		(18,296		)		(41,927		)		(31,542		)
Fair value of assets at December 31			$1,200,035				$1,364,030				$354,928				$160,777				$339,126				$282,668
Funded status			($415,049	)			($420,444	)			($116,582	)			($46,185	)			($57,638	)			($110,939	)
Amounts recognized in the balance sheet (funded status)
Non-current liabilities			($415,049	)			($420,444	)			($116,582	)			($46,185	)			($57,638	)			($110,939	)
Amounts recognized as regulatory asset
Net loss			$799,235				$759,228				$225,354				$91,862				$160,564				$193,870
Amounts recognized as AOCI (before tax)
Net loss			$—				$23,481				$—				$—				$—				$—

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2018		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
		(In Thousands)
Change in Projected Benefit Obligation (PBO)
Balance at January 1			$1,580,756				$1,785,700				$457,549				$217,896				$410,720				$384,049
Service cost		24,757				33,783				7,286				2,693				6,356				7,102
Interest cost		52,017				59,761				15,075				7,253				13,390				12,907
Actuarial gain		(79,621		)		(133,520		)		(26,611		)		(18,844		)		(21,656		)		(37,842		)
Benefits paid		(134,101		)		(145,808		)		(39,210		)		(17,808		)		(39,206		)		(27,182		)
Balance at December 31			$1,443,808				$1,599,916				$414,089				$191,190				$369,604				$339,034
Change in Plan Assets
Fair value of assets at January 1			$1,205,668				$1,365,741				$360,842				$165,747				$363,523				$274,432
Actual return on plan assets		(66,787		)		(75,926		)		(19,849		)		(9,221		)		(19,686		)		(15,520		)
Employer contributions		64,062				71,919				14,933				7,250				10,883				13,786
Benefits paid		(134,101		)		(145,808		)		(39,210		)		(17,808		)		(39,206		)		(27,182		)
Fair value of assets at December 31			$1,068,842				$1,215,926				$316,716				$145,968				$315,514				$245,516
Funded status			($374,966	)			($383,990	)			($97,373	)			($45,222	)			($54,090	)			($93,518	)
Amounts recognized in the balance sheet (funded status)
Non-current liabilities			($374,966	)			($383,990	)			($97,373	)			($45,222	)			($54,090	)			($93,518	)
Amounts recognized as regulatory asset
Net loss			$727,703				$686,138				$196,683				$91,448				$159,030				$168,559
Amounts recognized as AOCI  (before tax)
Net loss			$—				$43,796				$—				$—				$—				$—

Accumulated Pension Benefit Obligation

The accumulated benefit obligation for Entergy’s qualified pension plans was $7.8 billion and $6.9 billion at December 31, 2019 and 2018, respectively.

The qualified pension accumulated benefit obligation for each of the Registrant Subsidiaries for their employees as of December 31, 2019 and 2018 was as follows:

	December 31,
	2019				2018
	(In Thousands)
Entergy Arkansas		$1,519,998				$1,362,425
Entergy Louisiana		$1,643,759				$1,481,158
Entergy Mississippi		$438,817				$387,635
Entergy New Orleans		$192,561				$179,907
Entergy Texas		$371,589				$347,852
System Energy		$368,771				$317,848

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Other Postretirement Benefits

Entergy also currently offers retiree medical, dental, vision, and life insurance benefits (other postretirement benefits) for eligible retired employees.  Employees who commenced employment before July 1, 2014 and who satisfy certain eligibility requirements (including retiring from Entergy after a certain age and/or years of service with Entergy and immediately commencing their Entergy pension benefit), may become eligible for other postretirement benefits.

Effective January 1, 1993, Entergy adopted an accounting standard requiring a change from a cash method to an accrual method of accounting for postretirement benefits other than pensions.  Entergy Arkansas, Entergy Mississippi, Entergy New Orleans, and Entergy Texas have received regulatory approval to recover accrued other postretirement benefit costs through rates.  The LPSC ordered Entergy Louisiana to continue the use of the pay-as-you-go method for ratemaking purposes for postretirement benefits other than pensions.  However, the LPSC retains the flexibility to examine individual companies’ accounting for other postretirement benefits to determine if special exceptions to this order are warranted. Pursuant to regulatory directives, Entergy Arkansas, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy contribute the other postretirement benefit costs collected in rates into external trusts.  System Energy is funding, on behalf of Entergy Operations, other postretirement benefits associated with Grand Gulf.

Trust assets contributed by participating Registrant Subsidiaries are in master trusts, established by Entergy Corporation and maintained by a trustee.  Each participating Registrant Subsidiary holds a beneficial interest in the trusts’ assets.  The assets in the master trusts are commingled for investment and administrative purposes.  Although assets are commingled, supporting records are maintained for the purpose of allocating the beneficial interest in net earnings/(losses) and the administrative expenses of the investment accounts to the various participating plans and participating Registrant Subsidiaries. Beneficial interest in an investment account’s net income/(loss) is comprised of interest and dividends, realized and unrealized gains and losses, and expenses.  Beneficial interest from these investments is allocated to the plans and participating Registrant Subsidiary based on their portion of net assets in the pooled accounts.

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Components of Net Other Postretirement Benefit Cost and Other Amounts Recognized as a Regulatory Asset and/or AOCI

Entergy Corporation’s and its subsidiaries’ total 2019, 2018, and 2017 other postretirement benefit costs, including amounts capitalized and amounts recognized as a regulatory asset and/or other comprehensive income, included the following components:

	2019				2018				2017
	(In Thousands)
Other postretirement costs:
Service cost - benefits earned during the period		$18,699				$27,129				$26,915
Interest cost on accumulated postretirement benefit obligation (APBO)	47,901				50,725				55,838
Expected return on assets	(38,246		)		(41,493		)		(37,630		)
Amortization of prior service credit	(35,377		)		(37,002		)		(41,425		)
Recognized net loss	1,430				13,729				21,905
Net other postretirement benefit (income)/cost		($5,593	)			$13,088				$25,603
Other changes in plan assets and benefit obligations recognized as a regulatory asset and /or AOCI (before tax)
Arising this period:
Prior service credit for period		$—				$—				($2,564	)
Net gain	(38,526		)		(274,354		)		(66,922		)
Amounts reclassified from regulatory asset and /or AOCI to net periodic benefit cost in the current year:
Amortization of prior service credit	35,377				37,002				41,425
Amortization of net loss	(1,430		)		(13,729		)		(21,905		)
Total		($4,579	)			($251,081	)			($49,966	)
Total recognized as net periodic benefit (income)/cost, regulatory asset, and/or AOCI (before tax)		($10,172	)			($237,993	)			($24,363	)
Estimated amortization amounts from regulatory asset and/or AOCI to net periodic benefit (income)/cost in the following year
Prior service credit		($17,563	)			($35,377	)			($37,002	)
Net loss		$800				$1,430				$13,729

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Total 2019, 2018, and 2017 other postretirement benefit costs of the Registrant Subsidiaries, including amounts capitalized and deferred, for their employees included the following components:

2019		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
Other postretirement costs:
Service cost - benefits earned during the period			$2,363				$4,639				$1,046				$367				$943				$973
Interest cost on APBO		7,226				10,664				2,681				1,581				3,415				1,902
Expected return on assets		(15,962		)		—				(4,794		)		(4,947		)		(9,103		)		(2,788		)
Amortization of prior service credit		(4,950		)		(7,349		)		(1,756		)		(682		)		(2,243		)		(1,450		)
Recognized net (gain)/ loss		576				(695		)		723				231				485				354
Net other postretirement benefit (income)/cost			($10,747	)			$7,259				($2,100	)			($3,450	)			($6,503	)			($1,009	)
Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)
Arising this period:
Net gain			($26,707	)			($2,220	)			($11,950	)			($10,967	)			($6,406	)			($5,539	)
Amounts reclassified from regulatory asset and/or AOCI to net periodic benefit cost in the current year:
Amortization of prior service credit		4,950				7,349				1,756				682				2,243				1,450
Amortization of net (gain)/loss		(576		)		695				(723		)		(231		)		(485		)		(354		)
Total			($22,333	)			$5,824				($10,917	)			($10,516	)			($4,648	)			($4,443	)
Total recognized as net periodic other postretirement (income)/cost, regulatory asset, and/or AOCI (before tax)			($33,080	)			$13,083				($13,017	)			($13,966	)			($11,151	)			($5,452	)
Estimated amortization amounts from regulatory asset and/or AOCI to net periodic (income)/cost  in the following year
Prior service credit			($3,174	)			($3,142	)			($1,037	)			$—				($1,421	)			($747	)
Net (gain)/loss			$4				($1,030	)			$75				($246	)			$810				$51

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2018		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
		(In Thousands)
Other postretirement costs:
Service cost - benefits earned during the period			$3,170				$6,225				$1,284				$516				$1,319				$1,223
Interest cost on APBO		7,986				11,154				2,731				1,669				3,754				1,998
Expected return on assets		(17,368		)		—				(5,213		)		(5,250		)		(9,784		)		(3,130		)
Amortization of prior service credit		(5,110		)		(7,735		)		(1,823		)		(745		)		(2,316		)		(1,513		)
Recognized net loss		1,154				1,550				1,508				137				823				932
Net other postretirement benefit (income)/cost			($10,168	)			$11,194				($1,513	)			($3,673	)			($6,204	)			($490	)
Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)
Arising this period:
Net gain			($32,219	)			($73,249	)			($7,794	)			($981	)			($10,561	)			($6,680	)
Amounts reclassified from regulatory asset and/or AOCI to net periodic benefit cost in the current year:
Amortization of prior service credit		5,110				7,735				1,823				745				2,316				1,513
Amortization of net loss		(1,154		)		(1,550		)		(1,508		)		(137		)		(823		)		(932		)
Total			($28,263	)			($67,064	)			($7,479	)			($373	)			($9,068	)			($6,099	)
Total recognized as net periodic other postretirement (income)/cost, regulatory asset, and/or AOCI (before tax)			($38,431	)			($55,870	)			($8,992	)			($4,046	)			($15,272	)			($6,589	)
Estimated amortization amounts from regulatory asset and/or AOCI to net periodic (income)/cost  in the following year
Prior service credit			($4,950	)			($7,349	)			($1,756	)			($682	)			($2,243	)			($1,450	)
Net (gain)/loss			$576				($695	)			$723				$231				$485				$354

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2017		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
		(In Thousands)
Other postretirement costs:
Service cost - benefits earned during the period			$3,451				$6,373				$1,160				$567				$1,488				$1,278
Interest cost on APBO		9,020				12,101				2,759				1,874				4,494				2,236
Expected return on assets		(15,836		)		—				(4,801		)		(4,635		)		(8,720		)		(2,869		)
Amortization of prior service credit		(5,110		)		(7,735		)		(1,823		)		(745		)		(2,316		)		(1,513		)
Recognized net loss		4,460				1,859				1,675				418				3,303				1,560
Net other postretirement benefit (income)/cost			($4,015	)			$12,598				($1,030	)			($2,521	)			($1,751	)			$692
Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)
Arising this period:
Net (gain)/loss		(29,534		)		(1,256		)		506				(7,342		)		(22,255		)		(5,459		)
Amounts reclassified from regulatory asset and/or AOCI to net periodic benefit cost in the current year:
Amortization of prior service credit		5,110				7,735				1,823				745				2,316				1,513
Amortization of net loss		(4,460		)		(1,859		)		(1,675		)		(418		)		(3,303		)		(1,560		)
Total			($28,884	)			$4,620				$654				($7,015	)			($23,242	)			($5,506	)
Total recognized as net periodic other postretirement (income)/cost, regulatory asset, and/or AOCI (before tax)			($32,899	)			$17,218				($376	)			($9,536	)			($24,993	)			($4,814	)
Estimated amortization amounts from regulatory asset and/or AOCI to net periodic (income)/cost  in the following year
Prior service credit			($5,110	)			($7,735	)			($1,823	)			($745	)			($2,316	)			($1,513	)
Net loss			$1,154				$1,550				$1,508				$137				$823				$932

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Other Postretirement Benefit Obligations, Plan Assets, Funded Status, and Amounts Not Yet Recognized and Recognized in the Balance Sheet

Other postretirement benefit obligations, plan assets, funded status, and amounts not yet recognized and recognized in the Consolidated Balance Sheets of Entergy Corporation and its Subsidiaries as of December 31, 2019 and 2018 are as follows:

	2019				2018
	(In Thousands)
Change in APBO
Balance at January 1		$1,232,619				$1,563,487
Service cost	18,699				27,129
Interest cost	47,901				50,725
Plan participant contributions	38,640				37,049
Actuarial (gain)/loss	23,673				(346,429		)
Benefits paid	(109,223		)		(99,785		)
Medicare Part D subsidy received	594				443
Balance at December 31		$1,252,903				$1,232,619
Change in Plan Assets
Fair value of assets at January 1		$609,782				$659,327
Actual return on plan assets	100,445				(30,582		)
Employer contributions	46,618				43,773
Plan participant contributions	38,640				37,049
Benefits paid	(109,223		)		(99,785		)
Fair value of assets at December 31		$686,262				$609,782
Funded status		($566,641	)			($622,837	)
Amounts recognized in the balance sheet
Current liabilities		($48,040	)			($44,276	)
Non-current liabilities	(518,601		)		(578,561		)
Total funded status		($566,641	)			($622,837	)
Amounts recognized as a regulatory asset
Prior service credit		($11,899	)			($25,778	)
Net (gain)/loss	(5,081		)		51,774
		($16,980	)			$25,996
Amounts recognized as AOCI (before tax)
Prior service credit		($21,231	)			($42,730	)
Net gain	(16,670		)		(33,569		)
		($37,901	)			($76,299	)

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Other postretirement benefit obligations, plan assets, funded status, and amounts not yet recognized and recognized in the Balance Sheets of the Registrant Subsidiaries as of December 31, 2019 and 2018 are as follows:

2019		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
		(In Thousands)
Change in APBO
Balance at January 1			$187,830				$275,269				$68,976				$41,987				$88,310				$48,791
Service cost		2,363				4,639				1,046				367				943				973
Interest cost		7,226				10,664				2,681				1,581				3,415				1,902
Plan participant contributions		8,125				8,876				2,197				1,343				2,602				1,765
Actuarial (gain)/loss		166				(2,220		)		(3,778		)		(4,234		)		8,279				(891		)
Benefits paid		(20,048		)		(23,160		)		(5,159		)		(2,598		)		(8,830		)		(5,229		)
Medicare Part D subsidy received		82				107				16				14				23				37
Balance at December 31			$185,744				$274,175				$65,979				$38,460				$94,742				$47,348
Change in Plan Assets
Fair value of assets at January 1			$252,055				$—				$75,853				$81,774				$144,846				$43,670
Actual return on plan assets		42,835				—				12,966				11,680				23,788				7,436
Employer contributions		1,257				14,284				228				1,659				(596		)		829
Plan participant contributions		8,125				8,876				2,197				1,343				2,602				1,765
Benefits paid		(20,048		)		(23,160		)		(5,159		)		(2,598		)		(8,830		)		(5,229		)
Fair value of assets at December 31			$284,224				$—				$86,085				$93,858				$161,810				$48,471
Funded status			$98,480				($274,175	)			$20,106				$55,398				$67,068				$1,123
Amounts recognized in the balance sheet
Current liabilities			$—				($18,467	)			$—				$—				$—				$—
Non-current liabilities		98,480				(255,708		)		20,106				55,398				67,068				1,123
Total funded status			$98,480				($274,175	)			$20,106				$55,398				$67,068				$1,123
Amounts recognized in regulatory asset
Prior service credit			($6,515	)			$—				($3,108	)			$—				($1,422	)			($854	)
Net (gain)/loss		(18,262		)		—				3,272				(8,046		)		6,203				2,881
			($24,777	)			$—				$164				($8,046	)			$4,781				$2,027
Amounts recognized in AOCI (before tax)
Prior service credit			$—				($4,915	)			$—				$—				$—				$—
Net gain		—				(24,739		)		—				—				—				—
			$—				($29,654	)			$—				$—				$—				$—

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2018		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
		(In Thousands)
Change in APBO
Balance at January 1			$249,019				$345,389				$84,621				$53,548				$116,702				$61,381
Service cost		3,170				6,225				1,284				516				1,319				1,223
Interest cost		7,986				11,154				2,731				1,669				3,754				1,998
Plan participant contributions		8,136				8,162				2,233				1,171				2,565				1,837
Actuarial gain		(61,960		)		(73,249		)		(16,762		)		(10,847		)		(27,527		)		(11,985		)
Benefits paid		(18,581		)		(22,476		)		(5,145		)		(4,078		)		(8,516		)		(5,685		)
Medicare Part D subsidy received		60				64				14				8				13				22
Balance at December 31			$187,830				$275,269				$68,976				$41,987				$88,310				$48,791
Change in Plan Assets
Fair value of assets at January 1			$274,678				$—				$82,433				$85,504				$154,171				$49,124
Actual return on plan assets		(12,373		)		—				(3,755		)		(4,616		)		(7,182		)		(2,175		)
Employer contributions		195				14,314				87				3,793				3,808				569
Plan participant contributions		8,136				8,162				2,233				1,171				2,565				1,837
Benefits paid		(18,581		)		(22,476		)		(5,145		)		(4,078		)		(8,516		)		(5,685		)
Fair value of assets at December 31			$252,055				$—				$75,853				$81,774				$144,846				$43,670
Funded status			$64,225				($275,269	)			$6,877				$39,787				$56,536				($5,121	)
Amounts recognized in the balance sheet
Current liabilities			$—				($17,740	)			$—				$—				$—				$—
Non-current liabilities		64,225				(257,529		)		6,877				39,787				56,536				(5,121		)
Total funded status			$64,225				($275,269	)			$6,877				$39,787				$56,536				($5,121	)
Amounts recognized in regulatory asset
Prior service credit			($11,465	)			$—				($4,864	)			($681	)			($3,665	)			($2,304	)
Net loss		9,021				—				15,945				3,151				13,094				8,774
			($2,444	)			$—				$11,081				$2,470				$9,429				$6,470
Amounts recognized in AOCI (before tax)
Prior service credit			$—				($12,264	)			$—				$—				$—				$—
Net gain		—				(23,214		)		—				—				—				—
			$—				($35,478	)			$—				$—				$—				$—

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Non-Qualified Pension Plans

Entergy also sponsors non-qualified, non-contributory defined benefit pension plans that provide benefits to certain key employees.  Entergy recognized net periodic pension cost related to these plans of $22.6 million in 2019, $24.4 million in 2018, and $37.6 million in 2017.  In 2019, 2018, and 2017 Entergy recognized $7.4 million, $7.7 million, and $20.3 million, respectively in settlement charges related to the payment of lump sum benefits out of the plan that is included in the non-qualified pension plan cost above.  

The projected benefit obligation was $162.8 million as of December 31, 2019 of which $18.1 million was a current liability and $144.6 million was a non-current liability. The projected benefit obligation was $147 million as of December 31, 2018 of which $17 million was a current liability and $130 million was a non-current liability.  The accumulated benefit obligation was $143.4 million and $131.9 million as of December 31, 2019 and 2018, respectively. The unamortized prior service cost and net loss are recognized in regulatory assets ($58.8 million at December 31, 2019 and $51.9 million at December 31, 2018) and accumulated other comprehensive income before taxes ($24.9 million at December 31, 2019 and $19.2 million at December 31, 2018).

The following Registrant Subsidiaries participate in Entergy’s non-qualified, non-contributory defined benefit pension plans that provide benefits to certain key employees.  The net periodic pension cost for their employees for the non-qualified plans for 2019, 2018, and 2017, was as follows:

	Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas
	(In Thousands)
2019		$275				$159				$326				$20				$481
2018		$474				$180				$300				$81				$650
2017		$679				$185				$251				$73				$499

Included in the 2019 net periodic pension cost above are settlement charges of $40 thousand for Entergy Mississippi related to the lump sum benefits paid out of the plan. Included in the 2018 net periodic pension cost above are settlement charges of $30 thousand and $139 thousand for Entergy Arkansas and Entergy Texas, respectively, related to the lump sum benefits paid out of the plan. Included in the 2017 net periodic pension cost above are settlement charges of $269 thousand for Entergy Arkansas related to the lump sum benefits paid out of the plan.

The projected benefit obligation for their employees for the non-qualified plans as of December 31, 2019 and 2018 was as follows:

	Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas
	(In Thousands)
2019		$2,755				$1,682				$3,286				$231				$7,783
2018		$2,752				$1,881				$2,732				$206				$7,952

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The accumulated benefit obligation for their employees for the non-qualified plans as of December 31, 2019 and 2018 was as follows:

	Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas
	(In Thousands)
2019		$2,248				$1,682				$2,938				$230				$7,391
2018		$2,519				$1,881				$2,427				$206				$7,724

The following amounts were recorded on the balance sheet as of December 31, 2019 and 2018:

2019		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas
		(In Thousands)
Current liabilities			($249	)			($216	)			($357	)			($17	)			($723	)
Non-current liabilities		(2,506		)		(1,467		)		(2,930		)		(215		)		(7,060		)
Total funded status			($2,755	)			($1,683	)			($3,287	)			($232	)			($7,783	)
Regulatory asset/(liability)			$1,232				$3				$1,432				($559	)			($603	)

2018		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas
		(In Thousands)
Current liabilities			($198	)			($229	)			($128	)			($16	)			($672	)
Non-current liabilities		(2,554		)		(1,652		)		(2,604		)		(191		)		(7,280		)
Total funded status			($2,752	)			($1,881	)			($2,732	)			($207	)			($7,952	)
Regulatory asset/(liability)			$1,314				$79				$1,009				($579	)			($517	)
Accumulated other comprehensive income (before taxes)			$—				$5				$—				$—				$—

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Reclassification out of Accumulated Other Comprehensive Income (Loss)

Entergy and Entergy Louisiana reclassified the following costs out of accumulated other comprehensive income (loss) (before taxes and including amounts capitalized) as of December 31, 2019:

	Qualified Pension Costs				Other Postretirement Costs				Non-Qualified Pension Costs				Total
	(In Thousands)
Entergy
Amortization of prior service cost		$—				$21,498				($198	)			$21,300
Amortization of loss	(82,284		)		1,230				(2,192		)		(83,246		)
Settlement loss	(23,458		)		—				(1,697		)		(25,155		)
		($105,742	)			$22,728				($4,087	)			($87,101	)
Entergy Louisiana
Amortization of prior service cost		$—				$7,349				$—				$7,349
Amortization of loss	(2,795		)		695				(6		)		(2,106		)
		($2,795	)			$8,044				($6	)			$5,243

Entergy and Entergy Louisiana reclassified the following costs out of accumulated other comprehensive income (loss) (before taxes and including amounts capitalized) as of December 31, 2018:

	Qualified Pension Costs				Other Postretirement Costs				Non-Qualified Pension Costs				Total
	(In Thousands)
Entergy
Amortization of prior service cost		($398	)			$22,379				($281	)			$21,700
Amortization of loss	(87,828		)		(7,730		)		(3,628		)		(99,186		)
Settlement loss	(828		)		—				(2,379		)		(3,207		)
		($89,054	)			$14,649				($6,288	)			($80,693	)
Entergy Louisiana
Amortization of prior service cost		$—				$7,735				$—				$7,735
Amortization of loss	(3,468		)		(1,550		)		(7		)		(5,025		)
		($3,468	)			$6,185				($7	)			$2,710

Accounting for Pension and Other Postretirement Benefits

Accounting standards require an employer to recognize in its balance sheet the funded status of its benefit plans.  This is measured as the difference between plan assets at fair value and the benefit obligation.  Entergy uses a December 31 measurement date for its pension and other postretirement plans.  Employers are to record previously unrecognized gains and losses, prior service costs, and any remaining transition asset or obligation (that resulted from adopting prior pension and other postretirement benefits accounting standards) as comprehensive income and/or as a regulatory asset reflective of the recovery mechanism for pension and other postretirement benefit costs in the Registrant Subsidiaries’ respective regulatory jurisdictions.  For the portion of Entergy Louisiana that is not regulated, the unrecognized prior service cost, gains and losses, and transition asset/obligation for its pension and other postretirement benefit obligations are recorded as other comprehensive income.  Entergy Louisiana recovers other postretirement benefit costs on a pay-as-you-go basis and records the unrecognized prior service cost, gains and losses, and transition obligation for its other postretirement benefit obligation as other comprehensive income.  Accounting standards also require that changes in the funded status be recorded as other comprehensive income and/or a regulatory asset in the period in which the changes occur.

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With regard to pension and other postretirement costs, Entergy calculates the expected return on pension and other postretirement benefit plan assets by multiplying the long-term expected rate of return on assets by the market-related value (MRV) of plan assets.  In general, Entergy determines the MRV of its pension plan assets by calculating a value that uses a 20-quarter phase-in of the difference between actual and expected returns and for its other postretirement benefit plan assets Entergy generally uses fair value.

In accordance with ASU No. 2017-07, “Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”, the other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations and are presented by Entergy in miscellaneous - net in other income.

Qualified Pension and Other Postretirement Plans’ Assets

The Plan Administrator’s trust asset investment strategy is to invest the assets in a manner whereby long-term earnings on the assets (plus cash contributions) provide adequate funding for retiree benefit payments.  The mix of assets is based on an optimization study that identifies asset allocation targets in order to achieve the maximum return for an acceptable level of risk, while minimizing the expected contributions and pension and postretirement expense.

In the optimization studies, the Plan Administrator formulates assumptions about characteristics, such as expected asset class investment returns, volatility (risk), and correlation coefficients among the various asset classes.  The future market assumptions used in the optimization study are determined by examining historical market characteristics of the various asset classes and making adjustments to reflect future conditions expected to prevail over the study period.

The target asset allocation for pension adjusts dynamically based on the pension plans’ funded status. The current targets are shown below. The expectation is that the allocation to fixed income securities will increase as the pension plans’ funded status increases.  The following ranges were established to produce an acceptable, economically efficient plan to manage around the targets.

For postretirement assets the target and range asset allocations (as shown below) reflect recommendations made in the latest optimization study. The target asset allocations for postretirement assets adjust dynamically based on the funded status of each sub-account within each trust. The current weighted average targets shown below represent the aggregate of all targets for all sub-accounts within all trusts.

Entergy’s qualified pension and postretirement weighted-average asset allocations by asset category at December 31, 2019 and 2018 and the target asset allocation and ranges for 2018 are as follows:

Pension Asset Allocation		Target		Range				Actual 2019		Actual 2018
Domestic Equity Securities		39%		32%	to	46%		39%		40%
International Equity Securities		19%		15%	to	23%		19%		18%
Fixed Income Securities		42%		39%	to	45%		41%		41%
Other		0%		0%	to	10%		1%		1%

Postretirement Asset Allocation		Non-Taxable and Taxable
		Target		Range				Actual 2019		Actual 2018
Domestic Equity Securities		27%		22%	to	32%		29%		27%
International Equity Securities		18%		13%	to	23%		18%		17%
Fixed Income Securities		55%		50%	to	60%		53%		56%
Other		0%		0%	to	5%		0%		0%

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

The expected long-term rate of return for the qualified pension plans’ assets is based primarily on the geometric average of the historical annual performance of a representative portfolio weighted by the target asset allocation defined in the table above, along with other indications of expected return on assets. The time period reflected is a long-dated period spanning several decades.

The expected long-term rate of return for the non-taxable postretirement trust assets is determined using the same methodology described above for pension assets, but the aggregate asset allocation specific to the non-taxable postretirement assets is used.

For the taxable postretirement trust assets, the investment allocation includes tax-exempt fixed income securities.  This asset allocation, in combination with the same methodology employed to determine the expected return for other postretirement assets (as described above), and with a modification to reflect applicable taxes, is used to produce the expected long-term rate of return for taxable postretirement trust assets.

Concentrations of Credit Risk

Entergy’s investment guidelines mandate the avoidance of risk concentrations.  Types of concentrations specified to be avoided include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, geographic area and individual security issuance.  As of December 31, 2019, all investment managers and assets were materially in compliance with the approved investment guidelines, therefore there were no significant concentrations (defined as greater than 10 percent of plan assets) of credit risk in Entergy’s pension and other postretirement benefit plan assets.

Fair Value Measurements

Accounting standards provide the framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).

The three levels of the fair value hierarchy are described below:

•	Level 1 - Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in active markets that the Plan has the ability to access at the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

•

Level 2 - Level 2 inputs are inputs other than quoted prices included in Level 1 that are, either directly or indirectly, observable for the asset or liability at the measurement date.  Assets are valued based on prices derived by an independent party that uses inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads.  Prices are reviewed and can be challenged with the independent parties and/or overridden if it is believed such would be more reflective of fair value.  Level 2 inputs include the following:

-     quoted prices for similar assets or liabilities in active markets;

-     quoted prices for identical assets or liabilities in inactive markets;

-     inputs other than quoted prices that are observable for the asset or liability; or

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-     inputs that are derived principally from or corroborated by observable market data by correlation or other means.

If an asset or liability has a specified (contractual) term, the Level 2 input must be observable for substantially the full term of the asset or liability.

•	Level 3 - Level 3 refers to securities valued based on significant unobservable inputs.

    

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  The following tables set forth by level within the fair value hierarchy, measured at fair value on a recurring basis at December 31, 2019, and December 31, 2018, a summary of the investments held in the master trusts for Entergy’s qualified pension and other postretirement plans in which the Registrant Subsidiaries participate.

Qualified Defined Benefit Pension Plan Trusts

2019		Level 1				Level 2				Level 3				Total
		(In Thousands)
Equity securities:
Corporate stocks:
Preferred		$	10,379		(b)	$	—			—				$	10,379
Common		857,159			(b)	—			(b)	—				857,159
Common collective trusts (c)														2,698,697
Registered investment companies		132,389			(d)	—				—				132,389
Fixed income securities:
U.S. Government securities		—				805,671			(a)	—				805,671
Corporate debt instruments		—				762,577			(a)	—				762,577
Registered investment companies (e)		53,842			(d)	2,903			(d)	—				1,008,371
Other		73			(f)	43,106			(f)	—				43,179
Other:
Insurance company general account (unallocated contracts)		—				40,452			(g)	—				40,452
Total investments			$1,053,842				$1,654,709				$—				$6,358,874
Cash														1,407
Other pending transactions														(22,549		)
Less: Other postretirement assets included in total investments														(66,572		)
Total fair value of qualified pension assets															$6,271,160

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2018		Level 1				Level 2				Level 3				Total
		(In Thousands)
Short-term investments			$—				$7,715		(a)		$—				$7,715
Equity securities:
Corporate stocks:
Preferred			$8,250		(b)		$—				$—				$8,250
Common		695,003			(b)	—			(b)	—				695,003
Common collective trusts (c)														2,408,053
Registered investment companies		108,740			(d)	—				—				108,740
Fixed income securities:
U.S. Government securities		—			(b)	675,880			(a)	—				675,880
Corporate debt instruments		—				619,310			(a)	—				619,310
Registered investment companies (e)		29,374			(d)	2,697			(d)	—				931,439
Other		1,866			(f)	48,482			(f)	—				50,348
Other:
Insurance company general account (unallocated contracts)		—				39,322			(g)	—				39,322
Total investments			$843,233				$1,393,406				$—				$5,544,060
Cash														2,591
Other pending transactions														5,956
Less: Other postretirement assets included in total investments														(55,192		)
Total fair value of qualified pension assets															$5,497,415

Other Postretirement Trusts

2019		Level 1				Level 2				Level 3				Total
		(In Thousands)
Equity securities:
Common collective trust (c)															$289,398
Fixed income securities:
U.S. Government securities		49,930			(b)	89,297			(a)	—				139,227
Corporate debt instruments		—				130,333			(a)	—				130,333
Registered investment companies		1,877			(d)	—				—				1,877
Other		—				57,210			(f)	—				57,210
Total investments			$51,807				$276,840				$—				$618,045
Other pending transactions														1,645
Plus:  Other postretirement assets included in the investments of the qualified pension trust														66,572
Total fair value of other postretirement assets															$686,262

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2018		Level 1				Level 2				Level 3				Total
		(In Thousands)
Equity securities:
Common collective trust (c)															$244,729
Fixed income securities:
U.S. Government securities		63,174			(b)	80,039			(a)	—				143,213
Corporate debt instruments		—				105,989			(a)	—				105,989
Registered investment companies		2,442			(d)	—				—				2,442
Other		—				56,980			(f)	—				56,980
Total investments			$65,616				$243,008				$—				$553,353
Other pending transactions														1,237
Plus:  Other postretirement assets included in the investments of the qualified pension trust														55,192
Total fair value of other postretirement assets															$609,782

(a)	Certain preferred stocks and certain fixed income debt securities (corporate, government, and securitized) are stated at fair value as determined by broker quotes.

(b)	Common stocks, certain preferred stocks, and certain fixed income debt securities (government) are stated at fair value determined by quoted market prices.

(c)

The common collective trusts hold investments in accordance with stated objectives.  The investment strategy of the trusts is to capture the growth potential of equity markets by replicating the performance of a specified index.  Net asset value per share of common collective trusts estimate fair value. Certain of these common collective trusts are not publicly quoted and are valued by the fund administrators using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table, but are included in the total. In 2018 the fund administrator of these investments allowed trading three times in a 30-day period at the net asset value for certain of these common collective trusts.

(d)	Registered investment companies are money market mutual funds with a stable net asset value of one dollar per share. Registered investment companies may hold investments in domestic and international bond markets or domestic equities and estimate fair value using net asset value per share.

(e)	Certain of these registered investment companies are not publicly quoted and are valued by the fund administrators using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table, but are included in the total.

(f)	The other remaining assets are U.S. municipal and foreign government bonds stated at fair value as determined by broker quotes.

(g)	The unallocated insurance contract investments are recorded at contract value, which approximates fair value.  The contract value represents contributions made under the contract, plus interest, less funds used to pay benefits and contract expenses, and less distributions to the master trust.

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Estimated Future Benefit Payments

Based upon the assumptions used to measure Entergy’s qualified pension and other postretirement benefit obligations at December 31, 2019, and including pension and other postretirement benefits attributable to estimated future employee service, Entergy expects that benefits to be paid and the Medicare Part D subsidies to be received over the next ten years for Entergy Corporation and its subsidiaries will be as follows:

	Estimated Future Benefits Payments
	Qualified Pension				Non-Qualified Pension				Other Postretirement (before Medicare Subsidy)				Estimated Future Medicare D Subsidy Receipts
	(In Thousands)
Year(s)
2020		$548,493				$18,144				$81,100				$359
2021		$543,704				$15,724				$82,207				$398
2022		$549,488				$20,421				$82,619				$446
2023		$550,184				$19,720				$82,044				$491
2024		$554,602				$15,142				$80,649				$539
2025 - 2029		$2,604,810				$65,010				$373,404				$3,402

Based upon the same assumptions, Entergy expects that benefits to be paid and the Medicare Part D subsidies to be received over the next ten years for the Registrant Subsidiaries for their employees will be as follows:

Estimated Future Qualified Pension Benefits Payments		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
		(In Thousands)
Year(s)
2020			$117,460				$123,520				$37,805				$14,865				$33,558				$26,332
2021			$112,562				$124,235				$36,552				$14,598				$32,552				$26,529
2022			$112,749				$124,692				$35,779				$14,628				$32,041				$26,996
2023			$110,326				$123,347				$34,984				$14,472				$30,992				$27,040
2024			$108,186				$122,228				$33,842				$14,028				$29,124				$26,696
2025 - 2029			$512,732				$574,928				$152,681				$64,517				$127,736				$127,243

Estimated Future Non-Qualified Pension Benefits Payments		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas
		(In Thousands)
Year(s)
2020			$249				$216				$357				$17				$723
2021			$278				$200				$335				$17				$817
2022			$340				$184				$329				$17				$756
2023			$269				$168				$301				$21				$844
2024			$235				$154				$356				$19				$721
2025 - 2029			$1,152				$574				$1,510				$102				$2,970

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Estimated Future Other Postretirement Benefits Payments (before Medicare Part D Subsidy)		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
		(In Thousands)
Year(s)
2020			$13,088				$18,545				$4,046				$3,384				$6,292				$2,932
2021			$13,074				$18,703				$4,205				$3,255				$6,468				$3,044
2022			$12,801				$18,754				$4,261				$3,112				$6,520				$3,055
2023			$12,450				$18,588				$4,249				$2,997				$6,446				$2,990
2024			$12,155				$18,087				$4,250				$2,864				$6,239				$2,893
2025 - 2029			$55,553				$84,395				$20,672				$12,151				$29,004				$13,110

Estimated Future Medicare Part D Subsidy		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
		(In Thousands)
Year(s)
2020			$78				$78				$27				$15				$28				$13
2021			$86				$87				$28				$15				$31				$14
2022			$95				$95				$31				$17				$32				$16
2023			$104				$104				$32				$17				$35				$19
2024			$111				$114				$35				$17				$38				$22
2025 - 2029			$685				$719				$205				$94				$222				$152

Contributions

Entergy currently expects to contribute approximately $216.3 million to its qualified pension plans and approximately $49.1 million to other postretirement plans in 2020.  The expected 2020 pension and other postretirement plan contributions of the Registrant Subsidiaries for their employees are shown below.  The 2020 required pension contributions will be known with more certainty when the January 1, 2020 valuations are completed, which is expected by April 1, 2020.

The Registrant Subsidiaries expect to contribute approximately the following to the qualified pension and other postretirement plans for their employees in 2020:

	Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
	(In Thousands)
Pension Contributions		$32,512				$38,766				$7,768				$3,248				$3,549				$10,544
Other Postretirement Contributions		$509				$18,545				$130				$162				$61				$21

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Actuarial Assumptions

The significant actuarial assumptions used in determining the pension PBO and the other postretirement benefit APBO as of December 31, 2019 and 2018 were as follows:

	2019		2018
Weighted-average discount rate:
Qualified pension	3.26% - 3.43% Blended 3.39%		4.37% - 4.52% Blended 4.47%
Other postretirement	3.26%		4.42%
Non-qualified pension	2.72%		3.98%
Weighted-average rate of increase in future compensation levels	3.98% - 4.40%		3.98%
Assumed health care trend rate:
Pre-65	6.13%		6.59%
Post-65	6.25%		7.15%
Ultimate rate	4.75%		4.75%
Year ultimate rate is reached and beyond:
Pre-65	2027		2027
Post-65	2027		2026

The significant actuarial assumptions used in determining the net periodic pension and other postretirement benefit costs for 2019, 2018, and 2017 were as follows:

	2019		2018		2017
Weighted-average discount rate:
Qualified pension:
Service cost	4.57%		3.89%		4.75%
Interest cost	4.15%		3.44%		3.73%
Other postretirement:
Service cost	4.62%		3.88%		4.60%
Interest cost	4.01%		3.33%		3.61%
Non-qualified pension:
Service cost	3.94%		3.35%		3.65%
Interest cost	3.46%		2.76%		3.10%
Weighted-average rate of increase in future compensation levels	3.98%		3.98%		3.98%
Expected long-term rate of return on plan assets:
Pension assets	7.25%		7.50%		7.50%
Other postretirement non-taxable assets	6.5%-7.25%		6.50% - 7.50%		6.50% - 7.50%
Other postretirement taxable assets	5.50%		5.50%		5.75%
Assumed health care trend rate:
Pre-65	6.59%		6.95%		6.55%
Post-65	7.15%		7.25%		7.25%
Ultimate rate	4.75%		4.75%		4.75%
Year ultimate rate is reached and beyond:
Pre-65	2027		2027		2026
Post-65	2026		2027		2026

    

    

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With respect to the mortality assumptions, Entergy used the Pri-2012 Employee and Healthy Annuitant Tables with a fully generational MP-2019 projection scale, in determining its December 31, 2019 pension plans’ PBOs and the Pri.H 2012 (headcount weighted) Employee and Healthy Annuitant Tables with a fully generational MP-2019 projection scale, in determining its December 31, 2019 other postretirement benefit APBO. Entergy used the RP-2014 Employee and Healthy Annuitant Tables (adjusted to base year 2006) with a fully generational MP-2018 projection scale, in determining its December 31, 2018 pension plans’ PBOs and other postretirement benefit APBO. 

Entergy’s health care cost trend is affected by both medical cost inflation, and with respect to capped costs, the effects of general inflation. A one percentage point change in Entergy’s assumed health care cost trend rate for 2019 would have the following effects:

		1 Percentage Point Increase								1 Percentage Point Decrease
2019		Impact on the APBO				Impact on the sum of service costs and interest cost				Impact on the APBO				Impact on the sum of service costs and interest cost
		Increase /(Decrease) (In Thousands)
Entergy Corporation and its subsidiaries			$109,954				$7,310				($92,504	)			($5,970	)

The Registrant Subsidiaries’ health care cost trend is affected by both medical cost inflation, and with respect to capped costs, the effects of general inflation. A one percentage point change in the assumed health care cost trend rate for 2019 would have the following effects for the Registrant Subsidiaries for their employees:

		1 Percentage Point Increase								1 Percentage Point Decrease
2019		Impact on the APBO				Impact on the sum of service costs and interest cost				Impact on the APBO				Impact on the sum of service costs and interest cost
		Increase/(Decrease) (In Thousands)
Entergy Arkansas			$14,480				$908				($12,259	)			($748	)
Entergy Louisiana			$24,987				$1,769				($21,017	)			($1,443	)
Entergy Mississippi			$6,085				$420				($5,122	)			($343	)
Entergy New Orleans			$2,763				$179				($2,363	)			($148	)
Entergy Texas			$8,561				$482				($7,230	)			($397	)
System Energy			$4,876				$364				($4,048	)			($294	)

Defined Contribution Plans

Entergy sponsors the Savings Plan of Entergy Corporation and Subsidiaries (System Savings Plan).  The System Savings Plan is a defined contribution plan covering eligible employees of Entergy and certain of its subsidiaries. The participating Entergy subsidiary makes matching contributions to the System Savings Plan for all eligible participating employees in an amount equal to either 70% or 100% of the participants’ basic contributions, up to 6% of their eligible earnings per pay period.  The matching contribution is allocated to investments as directed by the employee.

Entergy also sponsors the Savings Plan of Entergy Corporation and Subsidiaries VI (established in April 2007) and the Savings Plan of Entergy Corporation and Subsidiaries VII (established in April 2007) to which matching contributions are also made.  The plans are defined contribution plans that cover eligible employees, as defined by each plan, of Entergy and certain of its subsidiaries. Effective as of the close of business on December 31, 2017, the Savings Plan of Entergy Corporation and Subsidiaries IV (Entergy Savings Plan IV) was merged into the System Savings Plan and all of the assets of Entergy Savings Plan IV were transferred to the System Savings Plan.   

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Entergy’s subsidiaries’ contributions to defined contribution plans collectively were $57.6 million in 2019, $54.3 million in 2018, and $49.1 million in 2017.  The majority of the contributions were to the System Savings Plan.

The Registrant Subsidiaries’ 2019, 2018, and 2017 contributions to defined contribution plans for their employees were as follows:

Year		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas
		(In Thousands)
2019			$4,111				$5,641				$2,424				$882				$2,136
2018			$3,985				$5,450				$2,307				$795				$1,992
2017			$3,741				$5,079				$2,133				$731				$1,865

Entergy grants stock options, restricted stock, performance units, and restricted stock units to key employees of the Entergy subsidiaries under its Equity Ownership Plans which are shareholder-approved stock-based compensation plans.  Effective May 3, 2019, Entergy’s shareholders approved the 2019 Omnibus Incentive Plan (2019 Plan).  The maximum number of common shares that can be issued from the 2019 Plan for stock-based awards is 7,300,000 all of which are available for incentive stock option grants.  The 2019 Plan applies to awards granted on or after May 3, 2019 and awards expire ten years from the date of grant. As of December 31, 2019, there were 7,266,822 authorized shares remaining for stock-based awards.

Stock Options

Stock options are granted at exercise prices that equal the closing market price of Entergy Corporation common stock on the date of grant.  Generally, stock options granted will become exercisable in equal amounts on each of the first three anniversaries of the date of grant.  Unless they are forfeited previously under the terms of the grant, options expire 10 years after the date of the grant if they are not exercised.

The following table includes financial information for stock options for each of the years presented:

	2019		2018		2017
	(In Millions)
Compensation expense included in Entergy’s consolidated net income	$3.8		$4.3		$4.4
Tax benefit recognized in Entergy’s consolidated net income	$1.0		$1.1		$1.7
Compensation cost capitalized as part of fixed assets and inventory	$1.4		$0.7		$0.7

Entergy determines the fair value of the stock option grants by considering factors such as lack of marketability, stock retention requirements, and regulatory restrictions on exercisability in accordance with accounting standards.  The stock option weighted-average assumptions used in determining the fair values are as follows:

	2019		2018		2017
Stock price volatility	17.23%		17.44%		18.39%
Expected term in years	7.32		7.33		7.35
Risk-free interest rate	2.50%		2.54%		2.31%
Dividend yield	4.50%		4.75%		4.75%
Dividend payment per share	$3.66		$3.58		$3.50

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Stock price volatility is calculated based upon the daily public stock price volatility of Entergy Corporation common stock over a period equal to the expected term of the award.  The expected term of the options is based upon historical option exercises and the weighted average life of options when exercised and the estimated weighted average life of all vested but unexercised options.  In 2008, Entergy implemented stock ownership guidelines for its senior executive officers.  These guidelines require an executive officer to own shares of Entergy Corporation common stock equal to a specified multiple of his or her salary.  Until an executive officer achieves this ownership position the executive officer is required to retain 75% of the net-of-tax net profit upon exercise of the option to be held in Entergy Corporation common stock.  The reduction in fair value of the stock options due to this restriction is based upon an estimate of the call option value of the reinvested gain discounted to present value over the applicable reinvestment period. 

A summary of stock option activity for the year ended December 31, 2019 and changes during the year are presented below:

	Number of Options			Weighted- Average Exercise Price		Aggregate Intrinsic Value		Weighted- Average Contractual Life
Options outstanding as of January 1, 2019	2,993,333			$75.14
Options granted	693,161			$89.19
Options exercised	(1,227,047	)		$76.35
Options forfeited/expired	(10,534	)		$81.68
Options outstanding as of December 31, 2019	2,448,913			$78.48		$101,178,880		7.03 years
Options exercisable as of December 31, 2019	1,160,665			$73.97		$53,192,483		5.47 years
Weighted-average grant-date fair value of options granted during 2019	$8.32

The weighted-average grant-date fair value of options granted during the year was $6.99 for 2018 and $6.54 for 2017.  The total intrinsic value of stock options exercised was $29 million during 2019, $19 million during 2018, and $11 million during 2017.  The intrinsic value, which has no effect on net income, of the outstanding stock options exercised is calculated by the positive difference between the weighted average exercise price of the stock options granted and Entergy Corporation’s common stock price as of December 31, 2019.  The aggregate intrinsic value of the stock options outstanding as of December 31, 2019 was $101 million. The intrinsic value of “in the money” stock options is $101 million as of December 31, 2019. Entergy recognizes compensation cost over the vesting period of the options based on their grant-date fair value.  The total fair value of options that vested was approximately $5 million during 2019, $4 million during 2018, and $6 million during 2017. Cash received from option exercises was $93 million for the year ended December 31, 2019. The tax benefits realized from options exercised was $7 million for the year ended December 31, 2019.

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The following table summarizes information about stock options outstanding as of December 31, 2019:

					Options Outstanding							Options Exercisable
Range of Exercise Price					As of December 31, 2019			Weighted-Average Remaining Contractual Life-Yrs.		Weighted Average Exercise Price		Number Exercisable as of December 31, 2019			Weighted Average Exercise Price
	$51	-	$64.99		244,200			3.72		$63.69		244,200			$63.69
	$65	-	$78.99		1,323,452			6.89		$73.97		694,093			$72.50
	$79	-	$91.99		881,261			8.15		$89.36		222,372			$89.85
	$51	-	$89.90		2,448,913			7.03		$78.48		1,160,665			$73.97

Stock-based compensation cost related to non-vested stock options outstanding as of December 31, 2019 not yet recognized is approximately $6 million and is expected to be recognized over a weighted-average period of 1.74 years.

Restricted Stock Awards

Entergy grants restricted stock awards earned under its stock benefit plans in the form of stock units. One-third of the restricted stock awards will vest upon each anniversary of the grant date and are expensed ratably over the three-year vesting period.  Shares of restricted stock have the same dividend and voting rights as other common stock and are considered issued and outstanding shares of Entergy upon vesting. In January 2019 the Board approved and Entergy granted 355,537 restricted stock awards under the 2015 Equity Ownership Plan.  The restricted stock awards were made effective as of January 31, 2019 and were valued at $89.19 per share, which was the closing price of Entergy Corporation’s common stock on that date.  

The following table includes information about the restricted stock awards outstanding as of December 31, 2019:

	Shares			Weighted-Average Grant Date Fair Value Per Share
Outstanding shares at January 1, 2019	693,527			$74.17
Granted	379,690			$88.75
Vested	(346,842	)		$72.96
Forfeited	(34,241	)		$78.66
Outstanding shares at December 31, 2019	692,134			$82.56

The following table includes financial information for restricted stock for each of the years presented:

	2019		2018		2017
	(In Millions)
Compensation expense included in Entergy’s consolidated net income	$20.2		$19.8		$19.7
Tax benefit recognized in Entergy’s consolidated net income	$5.1		$5.1		$7.6
Compensation cost capitalized as part of fixed assets and inventory	$7.1		$5.7		$5.2

The total fair value of the restricted stock awards granted was $34 million, $28 million, and $29 million for the years ended December 31, 2019, 2018, and 2017.

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The total fair value of the restricted stock awards vested was $25 million, $25 million, and $24 million for the years ended December 31, 2019, 2018, and 2017, respectively.

Long-Term Performance Unit Program

Entergy grants long-term incentive awards earned under its stock benefit plans in the form of performance units, which represents the value of, and are settled with, one share of Entergy Corporation common stock at the end of the three-year performance period, plus dividends accrued during the performance period on the number of performance units earned. The Long-Term Performance Unit Program specifies a minimum, target, and maximum achievement level, the achievement of which will determine the number of performance units that may be earned. Entergy measures performance by assessing Entergy’s total shareholder return relative to the total shareholder return of the companies in the Philadelphia Utility Index. For the 2019-2020 performance period, performance will be measured based eighty percent on relative total shareholder return and twenty percent on a cumulative adjusted earnings per share metric.

In January 2019 the Board approved and Entergy granted 180,824 performance units under the 2015 Equity Ownership and Long-Term Cash Incentive Plan.  The performance units were granted as of January 31, 2019, and eighty percent were valued at $102.07 per share based on various factors, primarily market conditions; and twenty percent were valued at $89.19 per share, the closing price of Entergy Corporation’s common stock on that date. Performance units have the same dividend and voting rights as other common stock, are considered issued and outstanding shares of Entergy upon vesting, and are expensed ratably over the 3-year vesting period, and compensation cost for the portion of the award based on cumulative adjusted earnings per share will be adjusted based on the number of units that ultimately vest.

The following table includes information about the long-term performance units outstanding at the target level as of December 31, 2019:

	Shares			Weighted-Average Grant Date Fair Value Per Share
Outstanding shares at January 1, 2019	566,626			$79.21
Granted	241,406			$96.18
Vested	(226,252	)		$84.52
Forfeited	(29,847	)		$87.43
Outstanding shares at December 31, 2019	551,933			$84.01

The following table includes financial information for the long-term performance units for each of the years presented:

	2019		2018				2017
	(In Millions)
Compensation expense included in Entergy’s consolidated net income	$11.1			$11.5				$10.8
Tax benefit recognized in Entergy’s consolidated net income	$2.8			$2.9				$4.2
Compensation cost capitalized as part of fixed assets and inventory	$4.0			$3.3				$3.0

    

The total fair value of the long-term performance units granted was $23 million, $16 million, and $19 million for the years ended December 31, 2019, 2018, and 2017, respectively.

In January 2019, Entergy issued 226,208 shares of Entergy Corporation common stock at a share price of $86.03 for awards earned and dividends accrued under the 2016-2018 Long-Term Performance Unit Program. In

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January 2018, Entergy issued 50,812 shares of Entergy Corporation common stock at a share price of $78.51 for awards earned and dividends accrued under the 2015-2017 Long-Term Performance Unit Program. In January 2017, Entergy issued 86,964 shares of Entergy Corporation common stock at a share price of $71.89 for awards earned and dividends accrued under the 2014-2016 Long-Term Performance Unit Program.

Restricted Stock Unit Awards

Entergy grants restricted stock unit awards earned under its stock benefit plans in the form of stock units that are subject to time-based restrictions.  The restricted stock units may be settled in shares of Entergy Corporation common stock or the cash value of shares of Entergy Corporation common stock at the time of vesting.  The costs of restricted stock unit awards are charged to income over the restricted period, which varies from grant to grant.  The average vesting period for restricted stock unit awards granted is 35 months.  As of December 31, 2019, there were 130,463 unvested restricted stock units that are expected to vest over an average period of 19 months.

The following table includes information about the restricted stock unit awards outstanding as of December 31, 2019:

	Shares			Weighted-Average Grant Date Fair Value Per Share
Outstanding shares at January 1, 2019	186,763			$76.43
Granted	26,700			$109.10
Vested	(83,000	)		$77.05
Outstanding shares at December 31, 2019	130,463			$82.72

The following table includes financial information for restricted stock unit awards for each of the years presented:

	2019		2018		2017
	(In Millions)
Compensation expense included in Entergy’s consolidated net income	$2.2		$2.9		$2.5
Tax benefit recognized in Entergy’s consolidated net income	$0.6		$0.7		$1.0
Compensation cost capitalized as part of fixed assets and inventory	$0.9		$0.7		$0.6

The total fair value of the restricted stock unit awards granted was $3 million, $2 million, and $3 million for the years ended December 31, 2019, 2018, and 2017, respectively.

The total fair value of the restricted stock unit awards vested was $6 million, $3 million, and $0.4 million for the years ended December 31, 2019, 2018, and 2017, respectively.

 

Entergy’s reportable segments as of December 31, 2019 are Utility and Entergy Wholesale Commodities.  Utility includes the generation, transmission, distribution, and sale of electric power in portions of Arkansas, Louisiana, Mississippi, and Texas, and natural gas utility service in portions of Louisiana.  Entergy Wholesale Commodities includes the ownership, operation, and decommissioning of nuclear power plants located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers.  Entergy Wholesale Commodities also includes the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers.  “All Other” includes the parent company, Entergy Corporation, and other business activity.

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Entergy’s segment financial information is as follows:

2019		Utility				Entergy Wholesale Commodities*				All Other				Eliminations				Consolidated
		(In Thousands)
Operating revenues			$9,583,985				$1,294,719				$21				($52	)			$10,878,673
Asset write-offs, impairments, and related charges			$—				$290,027				$—				$—				$290,027
Depreciation, amortization, & decommissioning			$1,493,167				$384,707				$2,944				$—				$1,880,818
Interest and investment income			$289,570				$414,636				$26,295				($182,589	)			$547,912
Interest expense			$589,395				$29,450				$178,575				($54,995	)			$742,425
Income taxes			$19,634				($161,295	)			($28,164	)			$—				($169,825	)
Consolidated net income (loss)			$1,425,643				$148,870				($188,675	)			($127,594	)			$1,258,244
Total assets			$49,557,664				$4,154,961				$514,020				($2,502,733	)			$51,723,912
Cash paid for long-lived asset additions			$4,527,045				$104,300				$160				$—				$4,631,505

2018		Utility				Entergy Wholesale Commodities*				All Other				Eliminations				Consolidated
		(In Thousands)
Operating revenues			$9,540,670				$1,468,905				$—				($123	)			$11,009,452
Asset write-offs, impairments, and related charges			$—				$532,321				$—				$—				$532,321
Depreciation, amortization, & decommissioning			$1,367,944				$388,732				$1,274				$—				$1,757,950
Interest and investment income			$203,936				$14,543				$31,602				($186,217	)			$63,864
Interest expense			$552,919				$33,694				$179,358				($58,623	)			$707,348
Income taxes			($732,548	)			($269,025	)			($35,253	)			$—				($1,036,826	)
Consolidated net income (loss)			$1,495,061				($340,641	)			($164,271	)			($127,594	)			$862,555
Total assets			$44,777,167				$5,459,275				$733,366				($2,694,742	)			$48,275,066
Cash paid for long-lived asset additions			$3,987,424				$283,707				$86				$—				$4,271,217

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2017		Utility				Entergy Wholesale Commodities*				All Other				Eliminations				Consolidated
		(In Thousands)
Operating revenues			$9,417,866				$1,656,730				$—				($115	)			$11,074,481
Asset write-offs, impairments, and related charges			$—				$538,372				$—				$—				$538,372
Depreciation, amortization, & decommissioning			$1,345,906				$448,079				$1,678				$—				$1,795,663
Interest and investment income			$218,317				$224,121				$21,669				($175,910	)			$288,197
Interest expense			$547,301				$23,714				$139,619				($48,291	)			$662,343
Income taxes			$794,616				($146,480	)			($105,566	)			$—				$542,570
Consolidated net income (loss)			$773,148				($172,335	)			($47,840	)			($127,620	)			$425,353
Total assets			$42,978,669				$5,638,009				$1,011,612				($2,921,141	)			$46,707,149
Investment in affiliates - at equity			$198				$—				$—				$—				$198
Cash paid for long-lived asset additions			$3,680,513				$320,667				$438				$—				$4,001,618

Businesses marked with * are sometimes referred to as the “competitive businesses.”  Eliminations are primarily intersegment activity.  Almost all of Entergy’s goodwill is related to the Utility segment.

In March 2017, Entergy sold the FitzPatrick plant, which it had intended to shut down, to Exelon. In January 2019, Entergy sold the Vermont Yankee plant, which it had previously shut down, to NorthStar. In August 2019, Entergy sold the Pilgrim plant, which it had previously shut down, to Holtec. Entergy has also announced plans to shut down Indian Point 2 in 2020, Indian Point 3 in 2021, and Palisades in 2022, and has purchase and sale agreements with Holtec for each of them expected to close after they are shut down. Management expects these transactions to result in the cessation of merchant power generation at all Entergy Wholesale Commodities nuclear power plants owned and operated by Entergy by 2022. Entergy will continue to have the obligation to decommission the nuclear plants pending their sales to third parties.

 

The decisions to shut down these plants and the related transactions resulted in asset impairments; employee retention and severance expenses and other benefits-related costs; and contracted economic development contributions. The employee retention and severance expenses and other benefits-related costs and contracted economic development contributions are included in "Other operation and maintenance" in the consolidated statement of operations.

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Total restructuring charges in 2019, 2018, and 2017 were comprised of the following:

		Employee retention and severance expenses and other benefits-related costs				Contracted economic development costs				Total
		(In Millions)
Balance as of December 31, 2016			$70				$21				$91
Restructuring costs accrued		113				—				113
Non-cash portion		—				(7		)		(7		)
Cash paid out		100				—				100
Balance as of December 31, 2017			$83				$14				$97
Restructuring costs accrued		139				—				139
Cash paid out		43				—				43
Balance as of December 31, 2018			$179				$14				$193
Restructuring costs accrued		91				—				91
Cash paid out		141				—				141
Balance as of December 31, 2019			$129				$14				$143

In addition, Entergy Wholesale Commodities incurred $290 million in 2019, $532 million in 2018, and $538 million in 2017 of impairment, loss on sales, and other related charges associated with these strategic decisions and transactions. See Note 14 to the financial statements for further discussion of these impairment charges.

Going forward, Entergy Wholesale Commodities expects to incur employee retention and severance expenses of approximately $75 million in 2020 and a total of approximately $55 million from 2021 through 2022 associated with these strategic transactions.

Geographic Areas

For the years ended December 31, 2019, 2018, and 2017, the amount of revenue Entergy derived from outside of the United States was insignificant.  As of December 31, 2019 and 2018, Entergy had no long-lived assets located outside of the United States.

Registrant Subsidiaries

Each of the Registrant Subsidiaries has one reportable segment, which is an integrated utility business, except for System Energy, which is an electricity generation business.  Each of the Registrant Subsidiaries’ operations is managed on an integrated basis by that company because of the substantial effect of cost-based rates and regulatory oversight on the business process, cost structures, and operating results.

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Acquisitions

Choctaw Generating Station

In October 2019, Entergy Mississippi purchased the Choctaw Generating Station, an 810 MW natural gas fired combined-cycle turbine plant located near French Camp, Mississippi, from a subsidiary of GenOn Energy Inc.  The purchase price for the Choctaw Generating Station was approximately $305 million.

Dispositions

Pilgrim

In July 2018, Entergy entered into a purchase and sale agreement with Holtec International to sell to a Holtec subsidiary 100% of the equity interests in Entergy Nuclear Generation Company, the owner of the Pilgrim plant. In August 2019 the NRC approved the sale of the plant to Holtec. The transaction closed in August 2019 for a purchase price of $1,000 (subject to adjustments for net liabilities and other amounts). The sale included the transfer of the Pilgrim nuclear decommissioning trust and obligation for spent fuel management and plant decommissioning. The transaction resulted in a loss of $190 million ($156 million net-of-tax) in the third quarter 2019. The disposition-date fair value of the nuclear decommissioning trust fund was approximately $1,030 million and the disposition-date fair value of the asset retirement obligation was $837 million. The transaction also included property, plant, and equipment with a net book value of zero, materials and supplies, and prepaid assets.

Willow Glen

In December 2018, Entergy Louisiana sold the Willow Glen Power Station, a non-operating gas plant. Entergy Louisiana sold Willow Glen for approximately $12 million in cash and the transfer of the obligation to decommission the plant. Entergy Louisiana recognized a regulatory liability of $5.7 million for return of removal costs previously collected in rates. Entergy Louisiana realized a pre-tax gain of $14.8 million on the sale. Entergy Louisiana recorded a $31.9 million regulatory liability to recognize the obligation to refund excess customer collections for decommissioning Willow Glen.

Vermont Yankee

In November 2016, Entergy entered into an agreement to sell 100% of the membership interests in Entergy Nuclear Vermont Yankee, LLC to a subsidiary of NorthStar. Entergy Nuclear Vermont Yankee was the owner of the Vermont Yankee plant. The sale of Entergy Nuclear Vermont Yankee to NorthStar included the transfer of the nuclear decommissioning trust fund and the asset retirement obligation for the spent fuel management and decommissioning of the plant.

In March 2018, Entergy and NorthStar entered into a settlement agreement and a Memorandum of Understanding with State of Vermont agencies and other interested parties that set forth the terms on which the agencies and parties support the Vermont Public Utility Commission’s approval of the transaction. The agreements provide additional financial assurance for decommissioning, spent fuel management and site restoration, and detail the site restoration standards. In October 2018 the NRC issued an order approving the application to transfer Vermont Yankee’s license to NorthStar for decommissioning. In December 2018, the Vermont Public Utility Commission issued an order approving the transaction consistent with the Memorandum of Understanding’s terms. On January 11, 2019, Entergy and NorthStar closed the transaction.

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Entergy Nuclear Vermont Yankee had an outstanding credit facility that was used to pay for dry fuel storage costs. This credit facility was guaranteed by Entergy Corporation. A subsidiary of Entergy assumed the obligations under the credit facility. At the closing of the sale transaction, NorthStar caused Entergy Nuclear Vermont Yankee, renamed NorthStar Vermont Yankee, to issue a $139 million promissory note to the Entergy subsidiary that assumed the credit facility obligations. The amount of the note included the balance outstanding on the credit facility, as well as borrowing fees and costs incurred by Entergy in connection with the credit facility.

With the receipt of the NRC and Vermont Public Utility Commission approvals and the resolution among the parties of the significant conditions of the sale, Entergy concluded that as of December 31, 2018 Vermont Yankee was in held for sale status. Entergy accordingly evaluated the Vermont Yankee asset retirement obligation in light of the terms of the sale transaction and evaluated the remaining values of the Vermont Yankee assets. These evaluations resulted in an increase in the asset retirement obligation and $173 million of asset impairment and related other charges in the fourth quarter 2018. See Note 9 to the financial statements for additional discussion of the asset retirement obligation. Upon closing of the transaction in January 2019, the Vermont Yankee decommissioning trust, along with the decommissioning obligation for the plant, was transferred to NorthStar. The assets and liabilities associated with the sale of Vermont Yankee were classified as held for sale on the Entergy Corporation and Subsidiaries Consolidated Balance Sheet as of December 31, 2018. As of December 31, 2018, the value of the decommissioning trust was $532 million. As of December 31, 2018, the asset retirement cost asset was $127 million, classified within other deferred debits, and the asset retirement cost obligation was $568 million, classified within other non-current liabilities.

The Vermont Yankee spent fuel disposal contract was assigned to NorthStar as part of the transaction. The Vermont Yankee transaction resulted in Entergy generating a net deferred tax asset in January 2019.  The deferred tax asset could not be fully realized by Entergy in the first quarter of 2019; accordingly, Entergy accrued a net tax expense of $29 million on the disposition of Vermont Yankee. The transaction also resulted in other charges of $5.4 million ($4.2 million net-of-tax) in the first quarter 2019.

FitzPatrick

In August 2016, Entergy entered into an agreement to sell the FitzPatrick plant, an 838 MW nuclear power plant that was owned by Entergy in the Entergy Wholesale Commodities segment. In March 2017 the NRC approved the sale of the plant to Exelon. The transaction closed in March 2017 for a purchase price of $110 million, which included a $10 million non-refundable signing fee paid in August 2016, in addition to the assumption by Exelon of certain liabilities related to the FitzPatrick plant, resulting in a pre-tax gain on the sale of $16 million. At the transaction close, Exelon paid an additional $8 million for the proration of certain expenses prepaid by Entergy. The disposition-date fair value of the decommissioning trust fund was $805 million, classified within other deferred debits, and the disposition-date fair value of the asset retirement obligation was $727 million, classified within other non-current liabilities. The transaction also included property, plant, and equipment with a net book value of zero, materials and supplies, and prepaid assets.

As part of the transaction, Entergy entered into a reimbursement agreement with Exelon pursuant to which Exelon reimbursed Entergy for specified out-of-pocket costs associated with Entergy’s operation of FitzPatrick prior to closing of the sale. In the first quarter 2017, Entergy billed Exelon for reimbursement of $98 million of other operation and maintenance expenses, $7 million in lost operating revenues, and $3 million in taxes other than income taxes, partially offset by a $10 million defueling credit to Exelon.

As discussed in Note 3 to the financial statements, as a result of the sale of FitzPatrick on March 31, 2017, Entergy redetermined the plant’s tax basis, resulting in a $44 million income tax benefit in the first quarter 2017.

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Impairment of Long-lived Assets

2017, 2018, and 2019 Impairments

Entergy continues to execute its strategy to shut down and sell all of the remaining plants in Entergy Wholesale Commodities’ merchant nuclear fleet, with planned shutdowns of Indian Point 2 by April 30, 2020, Indian Point 3 by April 30, 2021, and Palisades by May 31, 2022. The remaining three Entergy Wholesale Commodities’ nuclear plants, FitzPatrick, Vermont Yankee, and Pilgrim, have been sold. The FitzPatrick plant was classified as held-for-sale at December 31, 2016, and subsequently sold to Exelon in March 2017. The Vermont Yankee plant was classified as held-for-sale at December 31, 2018, and subsequently sold to NorthStar on January 11, 2019. The Pilgrim plant was sold to Holtec International on August 26, 2019.

Entergy Wholesale Commodities incurred $100 million in 2019, $532 million in 2018, and $538 million in 2017 of impairment charges related to nuclear fuel spending, nuclear refueling outage spending, expenditures for capital assets, and asset retirement obligation revisions. These costs were charged to expense as incurred as a result of the impaired fair value of the Entergy Wholesale Commodities nuclear plants’ long-lived assets due to the significantly reduced remaining estimated operating lives associated with management’s strategy to exit the Entergy Wholesale Commodities merchant power business. Entergy expects to continue to incur costs associated with nuclear fuel-related spending, expenditures for capital assets and, except for Palisades, expects to continue to charge these costs to expense as incurred because Entergy expects the value of the plants to continue to be impaired.

With respect to Palisades, Entergy and Consumers Energy had agreed to amend the existing PPA so that it would terminate early, on May 31, 2018. In September 2017, however, Entergy and Consumers Energy agreed to terminate the PPA amendment agreement. Entergy continues to operate Palisades under the current PPA with Consumers Energy, instead of shutting down in the fall of 2018 as previously planned. Entergy intends to shut down the Palisades plant permanently no later than May 31, 2022. As a result of the change in expected operating life of the Palisades plant, the expected probability-weighted undiscounted net cash flows as of September 30, 2017 exceeded the carrying value of the plant and related assets. Accordingly, nuclear fuel spending, nuclear refueling outage spending, and expenditures for capital assets incurred at Palisades after September 30, 2017 are no longer charged to expense as incurred, but recorded as assets and depreciated or amortized, subject to the typical periodic impairment reviews prescribed in the accounting rules.

The impairments and other related charges are recorded as a separate line item in Entergy’s consolidated statements of operations and are included within the results of the Entergy Wholesale Commodities segment. In addition to the impairments and other related charges, Entergy expects to incur additional charges through mid-2022 associated with these strategic transactions. See Note 13 to the financial statements for further discussion of these additional charges.

2018 Pilgrim Impairment

The Pilgrim plant ceased operations on May 31, 2019, at the end of its current fuel cycle. Entergy Nuclear Generation Company filed its Post-Shutdown Decommissioning Activities Report (PSDAR) with the NRC in the fourth quarter 2018 for the Pilgrim plant. As part of the development of the PSDAR, Entergy obtained a revised decommissioning cost study in the third quarter 2018. The revised estimate resulted in a $117.5 million increase in the decommissioning cost liability and a corresponding impairment charge in the third quarter 2018. As discussed above in Dispositions, on August 26, 2019, Entergy sold the Pilgrim plant to a Holtec International subsidiary.

2018 Vermont Yankee Impairment

As discussed above in Dispositions, on January 11, 2019, Entergy sold the Vermont Yankee plant to NorthStar. With the receipt of the NRC and Vermont Public Utility Commission approvals and the resolution among the parties of the significant conditions of the sale, Entergy concluded that as of December 31, 2018 Vermont Yankee was in held-

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for- sale status. Entergy accordingly evaluated the Vermont Yankee asset retirement obligation in light of the terms of the sale transaction, and evaluated the remaining values of the Vermont Yankee assets. These evaluations resulted in $173 million of asset impairment and related charges in the fourth quarter 2018. See Note 9 to the financial statements for additional discussion of the revision of the asset retirement obligation.

Market Risk

In the normal course of business, Entergy is exposed to a number of market risks.  Market risk is the potential loss that Entergy may incur as a result of changes in the market or fair value of a particular commodity or instrument.  All financial and commodity-related instruments, including derivatives, are subject to market risk including commodity price risk, equity price, and interest rate risk.  Entergy uses derivatives primarily to mitigate commodity price risk, particularly power price and fuel price risk.

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

As a wholesale generator, Entergy Wholesale Commodities’ core business is selling energy, measured in MWh, to its customers.  Entergy Wholesale Commodities enters into forward contracts with its customers and also sells energy and capacity in the day ahead or spot markets.  In addition to its forward physical power and gas contracts, Entergy Wholesale Commodities may also use a combination of financial contracts, including swaps, collars, and options, to mitigate commodity price risk.  When the market price falls, the combination of instruments is expected to settle in gains that offset lower revenue from generation, which results in a more predictable cash flow.

Entergy’s exposure to market risk is determined by a number of factors, including the size, term, composition, and diversification of positions held, as well as market volatility and liquidity.  For instruments such as options, the time period during which the option may be exercised and the relationship between the current market price of the underlying instrument and the option’s contractual strike or exercise price also affects the level of market risk.  A significant factor influencing the overall level of market risk to which Entergy is exposed is its use of hedging techniques to mitigate such risk.  Hedging instruments and volumes are chosen based on ability to mitigate risk associated with future energy and capacity prices; however, other considerations are factored into hedge product and volume decisions including corporate liquidity, corporate credit ratings, counterparty credit risk, hedging costs, firm settlement risk, and product availability in the marketplace.  Entergy manages market risk by actively monitoring compliance with stated risk management policies as well as monitoring the effectiveness of its hedging policies and strategies.  Entergy’s risk management policies limit the amount of total net exposure and rolling net exposure during the stated periods.  These policies, including related risk limits, are regularly assessed to ensure their appropriateness given Entergy’s objectives.

Derivatives

Some derivative instruments are classified as cash flow hedges due to their financial settlement provisions while others are classified as normal purchase/normal sale transactions due to their physical settlement provisions.  Normal purchase/normal sale risk management tools include power purchase and sales agreements, fuel purchase agreements, capacity contracts, and tolling agreements.  Financially-settled cash flow hedges can include natural gas and electricity swaps and options and interest rate swaps.  Entergy may enter into financially-settled swap and option contracts to manage market risk that may or may not be designated as hedging instruments.

Entergy enters into derivatives to manage natural risks inherent in its physical or financial assets or liabilities.

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Electricity over-the-counter instruments and futures contracts that financially settle against day-ahead power pool prices are used to manage price exposure for Entergy Wholesale Commodities generation.  The maximum length of time over which Entergy Wholesale Commodities is currently hedging the variability in future cash flows with derivatives for forecasted power transactions at December 31, 2019 is approximately 1.25 years.  Planned generation currently under contract from Entergy Wholesale Commodities nuclear power plants is 97% for 2020, of which approximately 65% is sold under financial derivatives and the remainder under normal purchase/normal sale contracts.  Total planned generation for 2020 is 17.8 TWh. 

Entergy may use standardized master netting agreements to help mitigate the credit risk of derivative instruments. These master agreements facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Cash, letters of credit, and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds an established threshold. The threshold represents an unsecured credit limit, which may be supported by a parental/affiliate guarantee, as determined in accordance with Entergy’s credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.

Certain of the agreements to sell the power produced by Entergy Wholesale Commodities power plants contain provisions that require an Entergy subsidiary to provide credit support to secure its obligations depending on the mark-to-market values of the contracts.  The primary form of credit support to satisfy these requirements is an Entergy Corporation guarantee.  As of December 31, 2019, there were no derivative contracts with counterparties in a liability position. In addition to the corporate guarantee, $11 million in cash collateral was required to be posted by the Entergy subsidiary to its counterparties and $1 million in cash collateral and $98 million in letters of credit were required to be posted by its counterparties to the Entergy subsidiary. As of December 31, 2018, derivative contracts with six counterparties were in a liability position (approximately $34 million total). In addition to the corporate guarantee, $19 million in cash collateral was required to be posted by the Entergy subsidiary to its counterparties. If the Entergy Corporation credit rating falls below investment grade, Entergy would have to post collateral equal to the estimated outstanding liability under the contract at the applicable date.   

Entergy manages fuel price volatility for its Louisiana jurisdictions (Entergy Louisiana and Entergy New Orleans) and Entergy Mississippi through the purchase of natural gas swaps and options that financially settle against either the average Henry Hub Gas Daily prices or the NYMEX Henry Hub. These swaps and options are marked-to-market through fuel expense with offsetting regulatory assets or liabilities. All benefits or costs of the program are recorded in fuel costs. The notional volumes of these swaps are based on a portion of projected annual exposure to gas price volatility for electric generation at Entergy Louisiana and Entergy Mississippi and projected winter purchases for gas distribution at Entergy New Orleans. The maximum length of time over which Entergy has executed natural gas swaps and options as of December 31, 2019 is 4.25 years for Entergy Louisiana and the maximum length of time over which Entergy has executed natural gas swaps as of December 31, 2019 is 10 months for Entergy Mississippi and 3 months Entergy New Orleans. The total volume of natural gas swaps and options outstanding as of December 31, 2019 is 40,926,000 MMBtu for Entergy, including 31,040,000 MMBtu for Entergy Louisiana, 9,330,000 MMBtu for Entergy Mississippi, and 556,000 MMBtu for Entergy New Orleans.  Credit support for these natural gas swaps and options is covered by master agreements that do not require Entergy to provide collateral based on mark-to-market value but do carry adequate assurance language that may lead to requests for collateral.

During the second quarter 2019, Entergy participated in the annual financial transmission rights auction process for the MISO planning year of June 1, 2019 through May 31, 2020. Financial transmission rights are derivative instruments that represent economic hedges of future congestion charges that will be incurred in serving Entergy’s customer load. They are not designated as hedging instruments. Entergy initially records financial transmission rights at their estimated fair value and subsequently adjusts the carrying value to their estimated fair value at the end of each accounting period prior to settlement. Unrealized gains or losses on financial transmission rights held by Entergy Wholesale Commodities are included in operating revenues. The Utility operating companies recognize regulatory liabilities or assets for unrealized gains or losses on financial transmission rights. The total volume of financial

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transmission rights outstanding as of December 31, 2019 is 48,825 GWh for Entergy, including 11,078 GWh for Entergy Arkansas, 22,282 GWh for Entergy Louisiana, 6,195 GWh for Entergy Mississippi, 2,331 GWh for Entergy New Orleans, and 6,741 GWh for Entergy Texas. Credit support for financial transmission rights held by the Utility operating companies is covered by cash and/or letters of credit issued by each Utility operating company as required by MISO. Credit support for financial transmission rights held by Entergy Wholesale Commodities is covered by cash. No cash or letters of credit were required to be posted for financial transmission rights exposure for Entergy Wholesale Commodities as of December 31, 2019 and December 31, 2018. Letters of credit posted with MISO covered the financial transmission rights exposure for Entergy Mississippi as of December 31, 2019 and Entergy Mississippi and Entergy Texas as of December 31, 2018.

The fair values of Entergy’s derivative instruments in the consolidated balance sheet as of December 31, 2019 are shown in the table below. Certain investments, including those not designated as hedging instruments, are subject to master netting agreements and are presented in the balance sheet on a net basis in accordance with accounting guidance for derivatives and hedging.

Instrument		Balance Sheet Location		Gross Fair Value (a)		Offsetting Position (b)		Net Fair Value (c) (d)		Business
				(In Millions)
Derivatives designated as hedging instruments
Assets:
Electricity swaps and options		Prepayments and other (current portion)		$92		($1)		$91		Entergy Wholesale Commodities
Electricity swaps and options		Other deferred debits and other assets (non-current portion)		$17		$—		$17		Entergy Wholesale Commodities
Liabilities:
Electricity swaps and options		Other current liabilities (current portion)		$1		($1)		$—		Entergy Wholesale Commodities

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Derivatives not designated as hedging instruments
Assets:
Electricity swaps and options		Prepayments and other (current portion)		$11		($1)		$10		Entergy Wholesale Commodities
Natural gas swaps and options		Other deferred debits and other assets (non-current portion)		$1		$—		$1		Utility
Financial transmission rights		Prepayments and other		$10		$—		$10		Utility and Entergy Wholesale Commodities
Liabilities:
Electricity swaps and options		Other current liabilities (current portion)		$2		($2)		$—		Entergy Wholesale Commodities
Natural gas swaps and options		Other current liabilities (current portion)		$5		$—		$5		Utility
Natural gas swaps and options		Other non-current liabilities (non-current portion)		$2		$—		$2		Utility

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The fair values of Entergy’s derivative instruments in the consolidated balance sheet as of December 31, 2018 are shown in the table below. Certain investments, including those not designated as hedging instruments, are subject to master netting agreements and are presented in the balance sheet on a net basis in accordance with accounting guidance for derivatives and hedging.

Instrument		Balance Sheet Location		Gross Fair Value (a)		Offsetting Position (b)		Net Fair Value (c) (d)		Business
				(In Millions)
Derivatives designated as hedging instruments
Assets:
Electricity swaps and options		Prepayments and other (current portion)		$32		($32)		$—		Entergy Wholesale Commodities
Electricity swaps and options		Other deferred debits and other assets (non-current portion)		$7		($7)		$—		Entergy Wholesale Commodities
Liabilities:
Electricity swaps and options		Other current liabilities (current portion)		$54		($33)		$21		Entergy Wholesale Commodities
Electricity swaps and options		Other non-current liabilities (non-current portion)		$20		($7)		$13		Entergy Wholesale Commodities

Derivatives not designated as hedging instruments
Assets:
Electricity swaps and options		Prepayments and other (current portion)		$4		($2)		$2		Entergy Wholesale Commodities
Electricity swaps and options		Other deferred debits and other assets (non-current portion)		$1		$—		$1		Entergy Wholesale Commodities
Natural gas swaps and options		Other deferred debits and other assets (non-current portion)		$2		$—		$2		Utility
Financial transmission rights		Prepayments and other		$16		($1)		$15		Utility and Entergy Wholesale Commodities
Liabilities:
Electricity swaps and options		Other current liabilities (current portion)		$1		($1)		$—		Entergy Wholesale Commodities
Natural gas swaps and options		Other current liabilities		$1		$—		$1		Utility

(a)	Represents the gross amounts of recognized assets/liabilities

(b)	Represents the netting of fair value balances with the same counterparty

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(c)	Represents the net amounts of assets/liabilities presented on the Entergy Corporation and Subsidiaries’ Consolidated Balance Sheet

(d)	Excludes cash collateral in the amount of $11 million posted and $1 million held as of December 31, 2019 and $19 million posted as of December 31, 2018. Also excludes letters of credit in the amount of $98 million held as of December 31, 2019 and $4 million posted as of December 31, 2018.

The effects of Entergy’s derivative instruments designated as cash flow hedges on the consolidated income statements for the years ended December 31, 2019, 2018, and 2017 are as follows:

Instrument		Amount of gain (loss) recognized in other comprehensive income		Income Statement location		Amount of gain (loss) reclassified from accumulated other comprehensive income into income (a)
		(In Millions)				(In Millions)
2019
Electricity swaps and options		$232		Competitive business operating revenues		$97
2018
Electricity swaps and options		($40)		Competitive business operating revenues		($68)
2017
Electricity swaps and options		$44		Competitive business operating revenues		$109

(a)	Before taxes of $20 million, ($14) million, and $38 million, for the years ended December 31, 2019, 2018, and 2017, respectively

Prior to the adoption of ASU 2017-12, Entergy measured its hedges for ineffectiveness. Any ineffectiveness was recognized in earnings during the period. The ineffective portion of cash flow hedges was recorded in competitive businesses operating revenues. The change in fair value of Entergy’s cash flow hedges due to ineffectiveness was ($5.9) million and ($3) million for the years ended December 31, 2018 and 2017, respectively.

   

Based on market prices as of December 31, 2019, unrealized gains (losses) recorded in accumulated other comprehensive income on cash flow hedges relating to power sales totaled $108 million of net unrealized losses.  Approximately $91 million is expected to be reclassified from accumulated other comprehensive income to operating revenues in the next twelve months.  The actual amount reclassified from accumulated other comprehensive income, however, could vary due to future changes in market prices. 

Entergy may effectively liquidate a cash flow hedge instrument by entering into a contract offsetting the original hedge, and then de-designating the original hedge in this situation.  Gains or losses accumulated in other comprehensive income prior to de-designation continue to be deferred in other comprehensive income until they are included in income as the original hedged transaction occurs. From the point of de-designation, the gains or losses on the original hedge and the offsetting contract are recorded as assets or liabilities on the balance sheet and offset as they flow through to earnings.

    

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The effects of Entergy’s derivative instruments not designated as hedging instruments on the consolidated income statements for the years ended December 31, 2019, 2018, and 2017 are as follows:

Instrument		Income Statement location		Amount of gain (loss) recorded in the income statement
				(In Millions)
2019
Natural gas swaps and options		Fuel, fuel-related expenses, and gas purchased for resale	(a)	($13)
Financial transmission rights		Purchased power expense	(b)	$94
Electricity swaps and options (c)		Competitive business operating revenues		$12
2018
Natural gas swaps		Fuel, fuel-related expenses, and gas purchased for resale	(a)	$8
Financial transmission rights		Purchased power expense	(b)	$131
Electricity swaps and options (c)		Competitive business operating revenues		$8
2017
Natural gas swaps		Fuel, fuel-related expenses, and gas purchased for resale	(a)	($31)
Financial transmission rights		Purchased power expense	(b)	$139

(a)

Due to regulatory treatment, the natural gas swaps and options are marked-to-market through fuel, fuel-related expenses, and gas purchased for resale and then such amounts are simultaneously reversed and recorded as an offsetting regulatory asset or liability.  The gains or losses recorded as fuel expenses when the swaps and options are settled are recovered or refunded through fuel cost recovery mechanisms.

(b)

Due to regulatory treatment, the changes in the estimated fair value of financial transmission rights for the Utility operating companies are recorded through purchased power expense and then such amounts are simultaneously reversed and recorded as an offsetting regulatory asset or liability.  The gains or losses recorded as purchased power expense when the financial transmission rights for the Utility operating companies are settled are recovered or refunded through fuel cost recovery mechanisms.

(c)	There were no gains (losses) recognized in accumulated other comprehensive income from electricity swaps and options.

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The fair values of the Registrant Subsidiaries’ derivative instruments not designated as hedging instruments on their balance sheets as of December 31, 2019 and 2018 are shown in the table below. Certain investments, including those not designated as hedging instruments, are subject to master netting agreements and are presented in the balance sheet on a net basis in accordance with accounting guidance for derivatives and hedging.

 

Instrument		Balance Sheet Location		Gross Fair Value (a)		Offsetting Position (b)		Net Fair Value (c) (d)		Registrant
				(In Millions)
2019
Assets:
Natural gas swaps and options		Other deferred debits and other assets		$0.8		$—		$0.8		Entergy Louisiana
Financial transmission rights		Prepayments and other		$3.4		($0.1)		$3.3		Entergy Arkansas
Financial transmission rights		Prepayments and other		$4.5		$—		$4.5		Entergy Louisiana
Financial transmission rights		Prepayments and other		$0.8		$—		$0.8		Entergy Mississippi
Financial transmission rights		Prepayments and other		$0.3		$—		$0.3		Entergy New Orleans
Financial transmission rights		Prepayments and other		$1.0		($0.1)		$0.9		Entergy Texas
Liabilities:
Natural gas swaps and options		Other current liabilities		$2.4		$—		$2.4		Entergy Louisiana
Natural gas swaps and options		Other non-current liabilities		$2.2		$—		$2.2		Entergy Louisiana
Natural gas swaps		Other current liabilities		$2.3		$—		$2.3		Entergy Mississippi
Natural gas swaps		Other current liabilities		$0.2		$—		$0.2		Entergy New Orleans

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Instrument		Balance Sheet Location		Gross Fair Value (a)		Offsetting Position (b)		Net Fair Value (c) (d)		Registrant
2018
Assets:
Natural gas swaps and options		Prepayments and other		$0.3		$—		$0.3		Entergy Louisiana
Natural gas swaps and options		Other deferred debits and other assets		$1.6		$—		$1.6		Entergy Louisiana
Financial transmission rights		Prepayments and other		$3.6		($0.2)		$3.4		Entergy Arkansas
Financial transmission rights		Prepayments and other		$8.4		($0.1)		$8.3		Entergy Louisiana
Financial transmission rights		Prepayments and other		$2.2		$—		$2.2		Entergy Mississippi
Financial transmission rights		Prepayments and other		$1.3		$—		$1.3		Entergy New Orleans
Liabilities:
Natural gas swaps and options		Other current liabilities		$1.1		$—		$1.1		Entergy Louisiana
Natural gas swaps		Other current liabilities		$0.1		$—		$0.1		Entergy New Orleans
Financial transmission rights		Other current liabilities		$0.9		($1.4)		($0.5)		Entergy Texas

(a)	Represents the gross amounts of recognized assets/liabilities

(b)	Represents the netting of fair value balances with the same counterparty

(c)	Represents the net amounts of assets/liabilities presented on the Registrant Subsidiaries’ balance sheets

(d)	As of December 31, 2019, letters of credit posted with MISO covered financial transmission rights exposure of $0.2 million for Entergy Mississippi. As of December 31, 2018, letters of credit posted with MISO covered financial transmission rights exposure of $0.2 million for Entergy Mississippi and $4.1 million for Entergy Texas.

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The effects of the Registrant Subsidiaries’ derivative instruments not designated as hedging instruments on their income statements for the years ended December 31, 2019, 2018, and 2017 are as follows:

Instrument		Income Statement Location		Amount of gain (loss) recorded in the income statement		Registrant
				(In Millions)
2019
Natural gas swaps and options		Fuel, fuel-related expenses, and gas purchased for resale		($5.3)	(a)	Entergy Louisiana
Natural gas swaps		Fuel, fuel-related expenses, and gas purchased for resale		($7.7)	(a)	Entergy Mississippi
Financial transmission rights		Purchased power		$22.3	(b)	Entergy Arkansas
Financial transmission rights		Purchased power		$46.7	(b)	Entergy Louisiana
Financial transmission rights		Purchased power		$6.8	(b)	Entergy Mississippi
Financial transmission rights		Purchased power		$2.7	(b)	Entergy New Orleans
Financial transmission rights		Purchased power		$15.7	(b)	Entergy Texas
2018
Natural gas swaps and options		Fuel, fuel-related expenses, and gas purchased for resale		$4.4	(a)	Entergy Louisiana
Natural gas swaps		Fuel, fuel-related expenses, and gas purchased for resale		$3.2	(a)	Entergy Mississippi
Natural gas swaps		Fuel, fuel-related expenses, and gas purchased for resale		$0.2	(a)	Entergy New Orleans
Financial transmission rights		Purchased power		$25.3	(b)	Entergy Arkansas
Financial transmission rights		Purchased power		$72.7	(b)	Entergy Louisiana
Financial transmission rights		Purchased power		$26.3	(b)	Entergy Mississippi
Financial transmission rights		Purchased power		$13.8	(b)	Entergy New Orleans
Financial transmission rights		Purchased power		($6.0)	(b)	Entergy Texas
2017
Natural gas swaps		Fuel, fuel-related expenses, and gas purchased for resale		($25.4)	(a)	Entergy Louisiana
Natural gas swaps		Fuel, fuel-related expenses, and gas purchased for resale		($5.2)	(a)	Entergy Mississippi
Natural gas swaps		Fuel, fuel-related expenses, and gas purchased for resale		($0.3)	(a)	Entergy New Orleans
Financial transmission rights		Purchased power		$41.7	(b)	Entergy Arkansas
Financial transmission rights		Purchased power		$45.8	(b)	Entergy Louisiana
Financial transmission rights		Purchased power		$18.9	(b)	Entergy Mississippi
Financial transmission rights		Purchased power		$9.1	(b)	Entergy New Orleans
Financial transmission rights		Purchased power		$22.3	(b)	Entergy Texas

(a)	Due to regulatory treatment, the natural gas swaps and options are marked-to-market through fuel, fuel-related expenses, and gas purchased for resale and then such amounts are simultaneously reversed and recorded as an

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offsetting regulatory asset or liability.  The gains or losses recorded as fuel expenses when the swaps and options are settled are recovered or refunded through fuel cost recovery mechanisms.

(b)

Due to regulatory treatment, the changes in the estimated fair value of financial transmission rights for the Utility operating companies are recorded through purchased power expense and then such amounts are simultaneously reversed and recorded as an offsetting regulatory asset or liability.  The gains or losses recorded as purchased power expense when the financial transmission rights for the Utility operating companies are settled are recovered or refunded through fuel cost recovery mechanisms.

Fair Values

The estimated fair values of Entergy’s financial instruments and derivatives are determined using historical prices, bid prices, market quotes, and financial modeling.  Considerable judgment is required in developing the estimates of fair value.  Therefore, estimates are not necessarily indicative of the amounts that Entergy could realize in a current market exchange.  Gains or losses realized on financial instruments other than those instruments held by the Entergy Wholesale Commodities business are reflected in future rates and therefore do not affect net income. Entergy considers the carrying amounts of most financial instruments classified as current assets and liabilities to be a reasonable estimate of their fair value because of the short maturity of these instruments.

Accounting standards define fair value as an exit price, or the price that would be received to sell an asset or the amount that would be paid to transfer a liability in an orderly transaction between knowledgeable market participants at the date of measurement.  Entergy and the Registrant Subsidiaries use assumptions or market input data that market participants would use in pricing assets or liabilities at fair value.  The inputs can be readily observable, corroborated by market data, or generally unobservable.  Entergy and the Registrant Subsidiaries endeavor to use the best available information to determine fair value.

Accounting standards establish a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy establishes the highest priority for unadjusted market quotes in an active market for the identical asset or liability and the lowest priority for unobservable inputs.  

The three levels of the fair value hierarchy are:

•

Level 1 - Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the entity has the ability to access at the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.  Level 1 primarily consists of individually owned common stocks, cash equivalents (temporary cash investments, securitization recovery trust account, and escrow accounts), debt instruments, and gas swaps traded on exchanges with active markets.  Cash equivalents includes all unrestricted highly liquid debt instruments with an original or remaining maturity of three months or less at the date of purchase.

•

Level 2 - Level 2 inputs are inputs other than quoted prices included in Level 1 that are, either directly or indirectly, observable for the asset or liability at the measurement date.  Assets are valued based on prices derived by independent third parties that use inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads.  Prices are reviewed and can be challenged with the independent parties and/or overridden by Entergy if it is believed such would be more reflective of fair value.  Level 2 inputs include the following:

–	quoted prices for similar assets or liabilities in active markets;

–	quoted prices for identical assets or liabilities in inactive markets;

–	inputs other than quoted prices that are observable for the asset or liability; or

–	inputs that are derived principally from or corroborated by observable market data by correlation or other means.

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Level 2 consists primarily of individually-owned debt instruments and gas swaps and options valued using observable inputs.

•

Level 3 - Level 3 inputs are pricing inputs that are generally less observable or unobservable from objective sources.  These inputs are used with internally developed methodologies to produce management’s best estimate of fair value for the asset or liability.  Level 3 consists primarily of financial transmission rights and derivative power contracts used as cash flow hedges of power sales at merchant power plants.

The values for power contract assets or liabilities are based on both observable inputs including public market prices and interest rates, and unobservable inputs such as implied volatilities, unit contingent discounts, expected basis differences, and credit adjusted counterparty interest rates.  They are classified as Level 3 assets and liabilities.  The valuations of these assets and liabilities are performed by the Business Unit Risk Control group and the Accounting Policy and Entergy Wholesale Commodities Accounting group.  The primary functions of the Business Unit Risk Control group include: gathering, validating and reporting market data, providing market risk analyses and valuations in support of Entergy Wholesale Commodities’ commercial transactions, developing and administering protocols for the management of market risks, and implementing and maintaining controls around changes to market data in the energy trading and risk management system.  The Business Unit Risk Control group is also responsible for managing the energy trading and risk management system, forecasting revenues, forward positions and analysis.  The Accounting Policy and Entergy Wholesale Commodities Accounting group performs functions related to market and counterparty settlements, revenue reporting and analysis and financial accounting. The Business Unit Risk Control group reports to the Vice President and Treasurer while the Accounting Policy and Entergy Wholesale Commodities Accounting group reports to the Chief Accounting Officer.

The amounts reflected as the fair value of electricity swaps are based on the estimated amount that the contracts are in-the-money at the balance sheet date (treated as an asset) or out-of-the-money at the balance sheet date (treated as a liability) and would equal the estimated amount receivable to or payable by Entergy if the contracts were settled at that date.  These derivative contracts include cash flow hedges that swap fixed for floating cash flows for sales of the output from the Entergy Wholesale Commodities business.  The fair values are based on the mark-to-market comparison between the fixed contract prices and the floating prices determined each period from quoted forward power market prices.  The differences between the fixed price in the swap contract and these market-related prices multiplied by the volume specified in the contract and discounted at the counterparties’ credit adjusted risk free rate are recorded as derivative contract assets or liabilities.  For contracts that have unit contingent terms, a further discount is applied based on the historical relationship between contract and market prices for similar contract terms.

The amounts reflected as the fair values of electricity options are valued based on a Black Scholes model, and are calculated at the end of each month for accounting purposes.  Inputs to the valuation include end of day forward market prices for the period when the transactions will settle, implied volatilities based on market volatilities provided by a third-party data aggregator, and U.S. Treasury rates for a risk-free return rate.  As described further below, prices and implied volatilities are reviewed and can be adjusted if it is determined that there is a better representation of fair value.  

On a daily basis, the Business Unit Risk Control group calculates the mark-to-market for electricity swaps and options.  The Business Unit Risk Control group also validates forward market prices by comparing them to other sources of forward market prices or to settlement prices of actual market transactions.  Significant differences are analyzed and potentially adjusted based on these other sources of forward market prices or settlement prices of actual market transactions.  Implied volatilities used to value options are also validated using actual counterparty quotes for Entergy Wholesale Commodities transactions when available and compared with other sources of market implied volatilities.  Moreover, on a quarterly basis, the Office of Corporate Risk Oversight confirms the mark-to-market calculations and prepares price scenarios and credit downgrade scenario analysis.  The scenario analysis is communicated to senior management within Entergy and within Entergy Wholesale Commodities.  Finally, for all proposed derivative transactions, an analysis is completed to assess the risk of adding the proposed derivative to Entergy

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Wholesale Commodities’ portfolio.  In particular, the credit and liquidity effects are calculated for this analysis.  This analysis is communicated to senior management within Entergy and Entergy Wholesale Commodities.

The values of financial transmission rights are based on unobservable inputs, including estimates of congestion costs in MISO between applicable generation and load pricing nodes based on the 50th percentile of historical prices.  They are classified as Level 3 assets and liabilities.  The valuations of these assets and liabilities are performed by the Business Unit Risk Control group.  The values are calculated internally and verified against the data published by MISO. Entergy’s Accounting Policy and Entergy Wholesale Commodities Accounting groups review these valuations for reasonableness, with the assistance of others within the organization with knowledge of the various inputs and assumptions used in the valuation. The Business Unit Risk Control groups report to the Vice President and Treasurer.  The Accounting Policy and Entergy Wholesale Commodities Accounting groups report to the Chief Accounting Officer.

The following tables set forth, by level within the fair value hierarchy, Entergy’s assets and liabilities that are accounted for at fair value on a recurring basis as of December 31, 2019 and December 31, 2018.  The assessment of the significance of a particular input to a fair value measurement requires judgment and may affect their placement within the fair value hierarchy levels.

2019		Level 1				Level 2				Level 3				Total
		(In Millions)
Assets:
Temporary cash investments			$391				$—				$—				$391
Decommissioning trust funds (a):
Equity securities		905				—				—				905
Debt securities		1,139				1,824				—				2,963
Common trusts (b)														2,536
Power contracts		—				—				118				118
Securitization recovery trust account		47				—				—				47
Escrow accounts		459				—				—				459
Gas hedge contracts		—				1				—				1
Financial transmission rights		—				—				10				10
			$2,941				$1,825				$128				$7,430
Liabilities:
Gas hedge contracts			$5				$2				$—				$7

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2018		Level 1				Level 2				Level 3				Total
		(In Millions)
Assets:
Temporary cash investments			$424				$—				$—				$424
Decommissioning trust funds (a):
Equity securities		1,686				—				—				1,686
Debt securities		1,259				1,625				—				2,884
Common trusts (b)														2,350
Power contracts		—				—				3				3
Securitization recovery trust account		51				—				—				51
Escrow accounts		403				—				—				403
Gas hedge contracts		—				2				—				2
Financial transmission rights		—				—				15				15
			$3,823				$1,627				$18				$7,818
Liabilities:
Power contracts			$—				$—				$34				$34
Gas hedge contracts		1				—				—				1
			$1				$—				$34				$35

(a)	The decommissioning trust funds hold equity and fixed income securities. Equity securities are invested to approximate the returns of major market indices.  Fixed income securities are held in various governmental and corporate securities.  See Note 16 to the financial statements for additional information on the investment portfolios.

(b)	Common trust funds are not publicly quoted and are valued by the fund administrators using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table. The fund administrator of these investments allows daily trading at the net asset value and trades settle at a later date.

The following table sets forth a reconciliation of changes in the net assets (liabilities) for the fair value of derivatives classified as Level 3 in the fair value hierarchy for the years ended December 31, 2019, 2018, and 2017:

	2019							2018							2017
	Power Contracts			Financial transmission rights				Power Contracts			Financial transmission rights				Power Contracts			Financial transmission rights
	(In Millions)
Balance as of January 1,		($31	)		$15				($65	)		$21				$5			$21
Total gains (losses) for the period (a)
Included in earnings	12			—				2			(1		)		(3		)	1
Included in other comprehensive income	232			—				(40		)	—				44			—
Included as a regulatory liability/asset	—			54				—			80				—			76
Issuances of financial transmission rights	—			35				—			46				—			62
Settlements	(95		)	(94		)		72			(131		)		(111		)	(139		)
Balance as of December 31,		$118			$10				($31	)		$15				($65	)		$21

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(a)	Change in unrealized gains or losses for the period included in earnings for derivatives held at the end of the reporting period is ($9.2) million, ($3.5) million, and $0.9 million for the years ended December 31, 2019, 2018, and 2017, respectively.

The following table sets forth a description of the types of transactions classified as Level 3 in the fair value hierarchy and significant unobservable inputs to each which cause that classification, as of December 31, 2019:

Transaction Type		Fair Value as of December 31, 2019		Significant Unobservable Inputs		Range from Average %		Effect on Fair Value
		(In Millions)						(In Millions)
Power contracts - electricity swaps		$118		Unit contingent discount		+/- 4.75%		$11

The values of financial transmission rights are based on unobservable inputs calculated internally and verified against historical pricing data published by MISO.

 

The following table sets forth an analysis of each of the types of unobservable inputs impacting the fair value of items classified as Level 3 within the fair value hierarchy, and the sensitivity to changes to those inputs:

Significant Unobservable Input		Transaction Type		Position		Change to Input		Effect on Fair Value
Unit contingent discount		Electricity swaps		Sell		Increase (Decrease)		Decrease (Increase)

The following table sets forth, by level within the fair value hierarchy, the Registrant Subsidiaries’ assets and liabilities that are accounted for at fair value on a recurring basis as of December 31, 2019 and December 31, 2018.  The assessment of the significance of a particular input to a fair value measurement requires judgment and may affect its placement within the fair value hierarchy levels.

Entergy Arkansas

2019		Level 1				Level 2				Level 3				Total
		(In Millions)
Assets:
Decommissioning trust funds (a):
Equity securities			$0.6				$—				$—				$0.6
Debt securities		108.7				304.1				—				412.8
Common trusts (b)														687.9
Securitization recovery trust account		4.0				—				—				4.0
Financial transmission rights		—				—				3.3				3.3
			$113.3				$304.1				$3.3				$1,108.6

2018		Level 1				Level 2				Level 3				Total
		(In Millions)
Assets:
Decommissioning trust funds (a):
Equity securities			$4.0				$—				$—				$4.0
Debt securities		94.8				286.5				—				381.3
Common trusts (b)														526.7
Securitization recovery trust account		4.7				—				—				4.7
Financial transmission rights		—				—				3.4				3.4
			$103.5				$286.5				$3.4				$920.1

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Entergy Louisiana

2019		Level 1				Level 2				Level 3				Total
		(In Millions)
Assets:
Temporary cash investments			$1.5				$—				$—				$1.5
Decommissioning trust funds (a):
Equity securities		4.3				—				—				4.3
Debt securities		180.8				420.7				—				601.5
Common trusts (b)														958.0
Escrow accounts		295.9				—				—				295.9
Securitization recovery trust account		3.7				—				—				3.7
Gas hedge contracts		—				0.8				—				0.8
Financial transmission rights		—				—				4.5				4.5
			$486.2				$421.5				$4.5				$1,870.2
Liabilities:
Gas hedge contracts			$2.4				$2.2				$—				$4.6

2018		Level 1				Level 2				Level 3				Total
		(In Millions)
Assets:
Temporary cash investments			$43.1				$—				$—				$43.1
Decommissioning trust funds (a):
Equity securities		13.3				—				—				13.3
Debt securities		162.0				370.9				—				532.9
Common trusts (b)														738.8
Escrow accounts		289.5				—				—				289.5
Securitization recovery trust account		3.6				—				—				3.6
Gas hedge contracts		—				1.9				—				1.9
Financial transmission rights		—				—				8.3				8.3
			$511.5				$372.8				$8.3				$1,631.4
Liabilities:
Gas hedge contracts			$0.7				$0.4				$—				$1.1

Entergy Mississippi

2019		Level 1				Level 2				Level 3				Total
		(In Millions)
Assets:
Temporary cash investments			$51.6				$—				$—				$51.6
Escrow accounts		80.2				—				—				80.2
Financial transmission rights		—				—				0.8				0.8
			$131.8				$—				$0.8				$132.6
Liabilities:
Gas hedge contracts			$2.3				$—				$—				$2.3

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2018		Level 1				Level 2				Level 3				Total
		(In Millions)
Assets:
Temporary cash investments			$36.9				$—				$—				$36.9
Escrow accounts		32.4				—				—				32.4
Financial transmission rights		—				—				2.2				2.2
			$69.3				$—				$2.2				$71.5

Entergy New Orleans

2019		Level 1				Level 2				Level 3				Total
		(In Millions)
Assets:
Temporary cash investments			$6.0				$—				$—				$6.0
Securitization recovery trust account		2.0				—				—				2.0
Escrow accounts		82.6				—				—				82.6
Financial transmission rights		—				—				0.3				0.3
			$90.6				$—				$0.3				$90.9
Liabilities:
Gas hedge contracts			$0.2				$—				$—				$0.2

2018		Level 1				Level 2				Level 3				Total
		(In Millions)
Assets:
Temporary cash investments			$19.7				$—				$—				$19.7
Securitization recovery trust account		2.2				—				—				2.2
Escrow accounts		80.9				—				—				80.9
Financial transmission rights		—				—				1.3				1.3
			$102.8				$—				$1.3				$104.1
Liabilities:
Gas hedge contracts			$0.1				$—				$—				$0.1

Entergy Texas

2019		Level 1				Level 2				Level 3				Total
		(In Millions)
Assets:
Temporary cash investments			$12.9				$—				$—				$12.9
Securitization recovery trust account		37.7				—				—				37.7
Financial transmission rights		—				—				0.9				0.9
			$50.6				$—				$0.9				$51.5

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2018		Level 1				Level 2				Level 3				Total
		(In Millions)
Assets:
Securitization recovery trust account			$40.2				$—				$—				$40.2
Liabilities:
Financial transmission rights			$—				$—				$0.5				$0.5

System Energy

2019		Level 1				Level 2				Level 3				Total
		(In Millions)
Assets:
Temporary cash investments			$68.4				$—				$—				$68.4
Decommissioning trust funds (a):
Equity securities		13.3				—				—				13.3
Debt securities		176.3				209.9				—				386.2
Common trusts (b)														654.6
			$258.0				$209.9				$—				$1,122.5

2018		Level 1				Level 2				Level 3				Total
		(In Millions)
Assets:
Temporary cash investments			$95.6				$—				$—				$95.6
Decommissioning trust funds (a):
Equity securities		4.4				—				—				4.4
Debt securities		224.5				139.7				—				364.2
Common trusts (b)														500.9
			$324.5				$139.7				$—				$965.1

(a)	The decommissioning trust funds hold equity and fixed income securities. Equity securities are invested to approximate the returns of major market indices.  Fixed income securities are held in various governmental and corporate securities.  See Note 16 to the financial statements for additional information on the investment portfolios.

(b)	Common trust funds are not publicly quoted and are valued by the fund administrators using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table. The fund administrator of these investments allows daily trading at the net asset value and trades settle at a later date.

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The following table sets forth a reconciliation of changes in the net assets for the fair value of derivatives classified as Level 3 in the fair value hierarchy for the year ended December 31, 2019.

	Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas
	(In Millions)
Balance as of January 1, 2019		$3.4				$8.3				$2.2				$1.3				($0.5	)
Issuances of financial transmission rights	9.6				18.7				3.9				2.7				0.1
Gains (losses) included as a regulatory liability/asset	12.6				24.2				1.5				(1.0		)		17.0
Settlements	(22.3		)		(46.7		)		(6.8		)		(2.7		)		(15.7		)
Balance as of December 31, 2019		$3.3				$4.5				$0.8				$0.3				$0.9

The following table sets forth a reconciliation of changes in the net assets (liabilities) for the fair value of derivatives classified as Level 3 in the fair value hierarchy for the year ended December 31, 2018.

	Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas
	(In Millions)
Balance as of January 1, 2018		$3.0				$10.2				$2.1				$2.2				$3.4
Issuances of financial transmission rights	11.8				20.0				4.5				3.7				6.1
Gains (losses) included as a regulatory liability/asset	13.9				50.8				21.9				9.2				(16.0		)
Settlements	(25.3		)		(72.7		)		(26.3		)		(13.8		)		6.0
Balance as of December 31, 2018		$3.4				$8.3				$2.2				$1.3				($0.5	)

The NRC requires Entergy subsidiaries to maintain nuclear decommissioning trusts to fund the costs of decommissioning ANO 1, ANO 2, River Bend, Waterford 3, Grand Gulf, Indian Point 1, Indian Point 2, Indian Point 3, and Palisades. Entergy’s nuclear decommissioning trust funds invest in equity securities, fixed-rate debt securities, and cash and cash equivalents.

Entergy implemented ASU No. 2016-01 “Financial Instruments (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities” effective January 1, 2018. The ASU requires investments in equity securities, excluding those accounted for under the equity method or resulting in consolidation of the investee, to be measured at fair value with changes recognized in net income. Entergy implemented this ASU using a modified retrospective method, and Entergy recorded an adjustment increasing retained earnings and increasing accumulated other comprehensive loss by $633 million as of January 1, 2018, for the cumulative effect of the unrealized gains and losses on investments in equity securities held by the decommissioning trust funds that do not meet the criteria for regulatory accounting treatment. Beginning in 2018, unrealized gains and losses on investments in equity securities held by the nuclear decommissioning trust funds are recorded in earnings as they occur rather than in other comprehensive income. In accordance with the regulatory treatment of the decommissioning trust funds of the

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Registrant Subsidiaries, an offsetting amount of unrealized gains/(losses) will continue to be recorded in other regulatory liabilities/assets.

As discussed in Note 14 to the financial statements, in January 2019, Entergy completed the transfer of the Vermont Yankee plant to NorthStar. As part of the transaction, Entergy transferred the Vermont Yankee decommissioning trust fund to NorthStar. As of December 31, 2018, the fair value of the decommissioning trust fund was $532 million.

As discussed in Note 14 to the financial statements, in August 2019, Entergy completed the transfer of the Pilgrim plant to Holtec. As part of the transaction, Entergy transferred the Pilgrim decommissioning trust fund to Holtec. The disposition-date fair value of the decommissioning trust fund was approximately $1,030 million.

Entergy records decommissioning trust funds on the balance sheet at their fair value.  Because of the ability of the Registrant Subsidiaries to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, the Registrant Subsidiaries have recorded an offsetting amount of unrealized gains/(losses) on investment securities in other regulatory liabilities/assets.  For the 30% interest in River Bend formerly owned by Cajun, Entergy Louisiana records an offsetting amount in other deferred credits for the unrealized trust earnings not currently expected to be needed to decommission the plant.  Decommissioning trust funds for the Entergy Wholesale Commodities nuclear plants do not meet the criteria for regulatory accounting treatment.  Accordingly, unrealized gains/(losses) recorded on the equity securities in the trust funds are recognized in earnings. Unrealized gains recorded on the available-for-sale debt securities in the trust funds are recognized in the accumulated other comprehensive income component of shareholders’ equity. Unrealized losses (where cost exceeds fair market value) on the available-for-sale debt securities in the trust funds are also recorded in the accumulated other comprehensive income component of shareholders’ equity unless the unrealized loss is other than temporary and therefore recorded in earnings.  A portion of Entergy’s decommissioning trust funds are held in a wholly-owned registered investment company, and unrealized gains and losses on both the equity and debt securities held in the registered investment company are recognized in earnings. Generally, Entergy records gains and losses on its debt and equity securities using the specific identification method to determine the cost basis of its securities.

The unrealized gains/(losses) recognized during the year ended December 31, 2019 on equity securities still held as of December 31, 2019 were $640 million. The equity securities are generally held in funds that are designed to approximate or somewhat exceed the return of the Standard Poor’s 500 Index. A relatively small percentage of the equity securities are held in funds intended to replicate the return of the Wilshire 4500 index or the Russell 3000 Index. The debt securities are generally held in individual government and credit issuances.

The available-for-sale securities held as of December 31, 2019 and 2018 are summarized as follows:

		Fair Value				Total Unrealized Gains				Total Unrealized Losses
		(In Millions)
2019
Debt Securities (a)			$2,456				$96				$6
2018
Debt Securities (a)			$2,495				$19				$35

(a)	Debt securities presented herein do not include the $507 million and $389 million of debt securities held in the wholly-owned registered investment company as of December 31, 2019 and 2018, respectively, which are not accounted for as available-for-sale.

    

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The unrealized gains/(losses) above are reported before deferred taxes of $13 million as of December 31, 2019 and ($1) million as of December 31, 2018 for debt securities. The amortized cost of available-for-sale debt securities was $2,366 million as of December 31, 2019 and $2,511 million as of December 31, 2018.  As of December 31, 2019, available-for-sale debt securities have an average coupon rate of approximately 3.27%, an average duration of approximately 6.62 years, and an average maturity of approximately 10.42 years.

The fair value and gross unrealized losses of available-for-sale debt securities, summarized by length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2019:

	Fair Value				Gross Unrealized Losses
	(In Millions)
Less than 12 months		$404				$5
More than 12 months	38				1
Total		$442				$6

The fair value and gross unrealized losses of available-for-sale debt securities, summarized by length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2018:

	Fair Value				Gross Unrealized Losses
	(In Millions)
Less than 12 months		$652				$9
More than 12 months	782				26
Total		$1,434				$35

The fair value of available-for-sale debt securities, summarized by contractual maturities, as of December 31, 2019 and 2018 are as follows:

	2019				2018
	(In Millions)
Less than 1 year		$128				$199
1 year - 5 years	807				1,066
5 years - 10 years	666				544
10 years - 15 years	125				77
15 years - 20 years	126				78
20 years+	604				531
Total		$2,456				$2,495

During the years ended December 31, 2019, 2018, and 2017, proceeds from the dispositions of available-for-sale securities amounted to $1,427 million, $2,406 million, and $3,163 million, respectively.  During the years ended December 31, 2019, 2018, and 2017, gross gains of $25 million, $7 million, and $149 million, respectively, and gross losses of $4 million, $47 million, and $13 million, respectively, related to available-for-sale securities were reclassified out of other comprehensive income or other regulatory liabilities/assets into earnings.

The fair values of the decommissioning trust funds related to the Entergy Wholesale Commodities nuclear plants as of December 31, 2019 are $556 million for Indian Point 1, $701 million for Indian Point 2, $930 million for Indian Point 3, and $498 million for Palisades. The fair values of the decommissioning trust funds related to the Entergy

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Wholesale Commodities nuclear plants as of December 31, 2018 are $471 million for Indian Point 1, $598 million for Indian Point 2, $781 million for Indian Point 3, $444 million for Palisades, $1,028 million for Pilgrim, and $532 million for Vermont Yankee. The fair values of the decommissioning trust funds for the Registrant Subsidiaries’ nuclear plants are detailed below.

Entergy Arkansas

Entergy Arkansas holds equity securities and available-for-sale debt securities in nuclear decommissioning trust accounts.  The available-for-sale securities held as of December 31, 2019 and 2018 are summarized as follows:

		Fair Value				Total Unrealized Gains				Total Unrealized Losses
		(In Millions)
2019
Debt Securities			$412.8				$9.9				$2.6
2018
Debt Securities			$381.3				$0.6				$8.2

The amortized cost of available-for-sale debt securities was $405.4 million as of December 31, 2019 and $389 million as of December 31, 2018.  As of December 31, 2019, the available-for-sale debt securities have an average coupon rate of approximately 2.79%, an average duration of approximately 6.83 years, and an average maturity of approximately 8.81 years.

The unrealized gains/(losses) recognized during the year ended December 31, 2019 on equity securities still held as of December 31, 2019 were $147.7 million. The equity securities are generally held in funds that are designed to approximate the return of the Standard & Poor’s 500 Index.  A relatively small percentage of the equity securities are held in funds intended to replicate the return of the Wilshire 4500 Index.

The fair value and gross unrealized losses of available-for-sale debt securities, summarized by length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2019:

	Fair Value				Gross Unrealized Losses
	(In Millions)
Less than 12 months		$104.8				$2.5
More than 12 months	7.7				0.1
Total		$112.5				$2.6

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The fair value and gross unrealized losses of available-for-sale debt securities, summarized by length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2018:

	Fair Value				Gross Unrealized Losses
	(In Millions)
Less than 12 months		$65.8				$0.5
More than 12 months	231.1				7.7
Total		$296.9				$8.2

The fair value of available-for-sale debt securities, summarized by contractual maturities, as of December 31, 2019 and 2018 are as follows:

	2019				2018
	(In Millions)
Less than 1 year		$44.1				$32.5
1 year - 5 years	109.1				170.3
5 years - 10 years	156.0				114.0
10 years - 15 years	31.3				10.3
15 years - 20 years	23.8				8.1
20 years+	48.5				46.1
Total		$412.8				$381.3

During the years ended December 31, 2019, 2018, and 2017, proceeds from the dispositions of available-for-sale securities amounted to $110.6 million, $82.1 million, and $339.4 million, respectively.  During the years ended December 31, 2019, 2018, and 2017, gross gains of $2.9 million, $0.1 million, and $17.7 million, respectively, and gross losses of $0.1 million, $2.9 million, and $0.6 million, respectively, related to available-for-sale securities were reclassified out of other regulatory liabilities/assets into earnings.

Entergy Louisiana

Entergy Louisiana holds equity securities and available-for-sale debt securities in nuclear decommissioning trust accounts.  The available-for-sale securities held as of December 31, 2019 and 2018 are summarized as follows:

		Fair Value				Total Unrealized Gains				Total Unrealized Losses
		(In Millions)
2019
Debt Securities			$601.5				$29.3				$0.8
2018
Debt Securities			$532.9				$4.1				$6.0

The amortized cost of available-for-sale debt securities was $573 million as of December 31, 2019 and $534.8 million as of December 31, 2018.  As of December 31, 2019, the available-for-sale debt securities have an average coupon rate of approximately 3.82%, an average duration of approximately 6.80 years, and an average maturity of approximately 13.26 years.

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The unrealized gains/(losses) recognized during the year ended December 31, 2019 on equity securities still held as of December 31, 2019 were $208.1 million. The equity securities are generally held in funds that are designed to approximate the return of the Standard & Poor’s 500 Index.  A relatively small percentage of the equity securities are held in funds intended to replicate the return of the Wilshire 4500 Index.

The fair value and gross unrealized losses of available-for-sale debt securities, summarized by length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2019:

	Fair Value				Gross Unrealized Losses
	(In Millions)
Less than 12 months		$71.2				$0.8
More than 12 months	7.9				—
Total		$79.1				$0.8

The fair value and gross unrealized losses of available-for-sale debt securities, summarized by length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2018:

	Fair Value				Gross Unrealized Losses
	(In Millions)
Less than 12 months		$170.1				$2.1
More than 12 months	145.8				3.9
Total		$315.9				$6.0

The fair value of available-for-sale debt securities, summarized by contractual maturities, as of December 31, 2019 and 2018 are as follows:

	2019				2018
	(In Millions)
Less than 1 year		$40.7				$31.1
1 year - 5 years	142.0				130.5
5 years - 10 years	132.4				111.0
10 years - 15 years	39.8				29.0
15 years - 20 years	49.2				37.1
20 years+	197.4				194.2
Total		$601.5				$532.9

During the years ended December 31, 2019, 2018, and 2017, proceeds from the dispositions of available-for-sale securities amounted to $186 million, $401.7 million, and $231.3 million, respectively.  During the years ended December 31, 2019, 2018, and 2017, gross gains of $4.8 million, $2.1 million, and $12 million, respectively, and gross losses of $0.3 million, $7.5 million, and $0.4 million, respectively, related to available-for-sale securities were reclassified out of other regulatory liabilities/assets into earnings.

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System Energy    

System Energy holds equity securities and available-for-sale debt securities in nuclear decommissioning trust accounts.  The available-for-sale securities held as of December 31, 2019 and 2018 are summarized as follows:

		Fair Value				Total Unrealized Gains				Total Unrealized Losses
		(In Millions)
2019
Debt Securities			$386.2				$15.1				$0.3
2018
Debt Securities			$364.2				$2.9				$5.8

The amortized cost of available-for-sale debt securities was $371.4 million as of December 31, 2019 and $367.1 million as of December 31, 2018.  As of December 31, 2019, the available-for-sale debt securities have an average coupon rate of approximately 3.12%, an average duration of approximately 6.75 years, and an average maturity of approximately 10.41 years.

The unrealized gains/(losses) recognized during the year ended December 31, 2019 on equity securities still held as of December 31, 2019 were $140.5 million. The equity securities are generally held in funds that are designed to approximate the return of the Standard & Poor’s 500 Index.  A relatively small percentage of the equity securities are held in funds intended to replicate the return of the Wilshire 4500 Index.

The fair value and gross unrealized losses of available-for-sale debt securities, summarized by length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2019:

	Fair Value				Gross Unrealized Losses
	(In Millions)
Less than 12 months		$56.9				$0.3
More than 12 months	0.3				—
Total		$57.2				$0.3

The fair value and gross unrealized losses of available-for-sale debt securities, summarized by length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2018:

	Fair Value				Gross Unrealized Losses
	(In Millions)
Less than 12 months		$89.7				$2.4
More than 12 months	79.8				3.4
Total		$169.5				$5.8

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The fair value of available-for-sale debt securities, summarized by contractual maturities, as of December 31, 2019 and 2018 are as follows:

	2019				2018
	(In Millions)
Less than 1 year		$8.5				$22.8
1 year - 5 years	154.6				188.0
5 years - 10 years	92.3				73.4
10 years - 15 years	13.4				5.2
15 years - 20 years	14.4				10.2
20 years+	103.0				64.6
Total		$386.2				$364.2

During the years ended December 31, 2019, 2018, and 2017, proceeds from the dispositions of available-for-sale securities amounted to $338.1 million, $361.9 million, and $565.4 million, respectively.  During the years ended December 31, 2019, 2018, and 2017, gross gains of $5.4 million, $0.5 million, and $1.4 million, respectively, and gross losses of $0.7 million, $6.1 million, and $3.3 million, respectively, related to available-for-sale securities were reclassified out of other regulatory liabilities/assets into earnings.

Other-than-temporary impairments and unrealized gains and losses

Under applicable authoritative accounting guidance, a variable interest entity (VIE) is an entity that conducts a business or holds property that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or where equity holders do not receive expected losses or returns. An entity may have an interest in a VIE through ownership or other contractual rights or obligations, and is required to consolidate a VIE if it is the VIE’s primary beneficiary. The primary beneficiary of a VIE is the entity that has the power to direct the activities of the VIE that most significantly affect the VIE’s economic performance and has the obligation to absorb losses or has the right to residual returns that would potentially be significant to the entity.

Entergy Arkansas, Entergy Louisiana, and System Energy consolidate the respective companies from which they lease nuclear fuel, usually in a sale and leaseback transaction. This is because Entergy directs the nuclear fuel companies with respect to nuclear fuel purchases, assists the nuclear fuel companies in obtaining financing, and, if financing cannot be arranged, the lessee (Entergy Arkansas, Entergy Louisiana, or System Energy) is responsible to repurchase nuclear fuel to allow the nuclear fuel company (the VIE) to meet its obligations. During the term of the

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arrangements, none of the Entergy operating companies have been required to provide financial support apart from their scheduled lease payments. See Note 4 to the financial statements for details of the nuclear fuel companies’ credit facility and commercial paper borrowings and long-term debt that are reported by Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy. These amounts also represent Entergy’s and the respective Registrant Subsidiary’s maximum exposure to losses associated with their respective interests in the nuclear fuel companies.

Entergy Gulf States Reconstruction Funding I, LLC, and Entergy Texas Restoration Funding, LLC, companies wholly-owned and consolidated by Entergy Texas, are variable interest entities and Entergy Texas is the primary beneficiary. In June 2007, Entergy Gulf States Reconstruction Funding issued senior secured transition bonds (securitization bonds) to finance Entergy Texas’s Hurricane Rita reconstruction costs. In November 2009, Entergy Texas Restoration Funding issued senior secured transition bonds (securitization bonds) to finance Entergy Texas’s Hurricane Ike and Hurricane Gustav restoration costs. With the proceeds, the variable interest entities purchased from Entergy Texas the transition property, which is the right to recover from customers through a transition charge amounts sufficient to service the securitization bonds. The transition property is reflected as a regulatory asset on the consolidated Entergy Texas balance sheet. The creditors of Entergy Texas do not have recourse to the assets or revenues of the variable interest entities, including the transition property, and the creditors of the variable interest entities do not have recourse to the assets or revenues of Entergy Texas. Entergy Texas has no payment obligations to the variable interest entities except to remit transition charge collections. See Note 5 to the financial statements for additional details regarding the securitization bonds.

Entergy Arkansas Restoration Funding, LLC, a company wholly-owned and consolidated by Entergy Arkansas, is a variable interest entity and Entergy Arkansas is the primary beneficiary. In August 2010, Entergy Arkansas Restoration Funding issued storm cost recovery bonds to finance Entergy Arkansas’s January 2009 ice storm damage restoration costs. With the proceeds, Entergy Arkansas Restoration Funding purchased from Entergy Arkansas the storm recovery property, which is the right to recover from customers through a storm recovery charge amounts sufficient to service the securitization bonds.  The storm recovery property is reflected as a regulatory asset on the consolidated Entergy Arkansas balance sheet. The creditors of Entergy Arkansas do not have recourse to the assets or revenues of Entergy Arkansas Restoration Funding, including the storm recovery property, and the creditors of Entergy Arkansas Restoration Funding do not have recourse to the assets or revenues of Entergy Arkansas.  Entergy Arkansas has no payment obligations to Entergy Arkansas Restoration Funding except to remit storm recovery charge collections. See Note 5 to the financial statements for additional details regarding the storm cost recovery bonds.

Entergy Louisiana Investment Recovery Funding I, L.L.C., a company wholly-owned and consolidated by Entergy Louisiana, is a variable interest entity and Entergy Louisiana is the primary beneficiary. In September 2011, Entergy Louisiana Investment Recovery Funding issued investment recovery bonds to recover Entergy Louisiana’s investment recovery costs associated with the canceled Little Gypsy repowering project.  With the proceeds, Entergy Louisiana Investment Recovery Funding purchased from Entergy Louisiana the investment recovery property, which is the right to recover from customers through an investment recovery charge amounts sufficient to service the bonds. The investment recovery property is reflected as a regulatory asset on the consolidated Entergy Louisiana balance sheet.  The creditors of Entergy Louisiana do not have recourse to the assets or revenues of Entergy Louisiana Investment Recovery Funding, including the investment recovery property, and the creditors of Entergy Louisiana Investment Recovery Funding do not have recourse to the assets or revenues of Entergy Louisiana.  Entergy Louisiana has no payment obligations to Entergy Louisiana Investment Recovery Funding except to remit investment recovery charge collections. See Note 5 to the financial statements for additional details regarding the investment recovery bonds.

Entergy New Orleans Storm Recovery Funding I, L.L.C., a company wholly-owned and consolidated by Entergy New Orleans, is a variable interest entity, and Entergy New Orleans is the primary beneficiary. In July 2015, Entergy New Orleans Storm Recovery Funding issued storm cost recovery bonds to recover Entergy New Orleans’s Hurricane Isaac storm restoration costs, including carrying costs, the costs of funding and replenishing the storm recovery reserve, and up-front financing costs associated with the securitization. With the proceeds, Entergy New Orleans Storm Recovery Funding purchased from Entergy New Orleans the storm recovery property, which is the right to recover from customers through a storm recovery charge amounts sufficient to service the securitization bonds. The

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storm recovery property is reflected as a regulatory asset on the consolidated Entergy New Orleans balance sheet. The creditors of Entergy New Orleans do not have recourse to the assets or revenues of Entergy New Orleans Storm Recovery Funding, including the storm recovery property, and the creditors of Entergy New Orleans Storm Recovery Funding do not have recourse to the assets or revenues of Entergy New Orleans. Entergy New Orleans has no payment obligations to Entergy New Orleans Storm Recovery Funding except to remit storm recovery charge collections. See Note 5 to the financial statements for additional details regarding the securitization bonds.

System Energy is considered to hold a variable interest in the lessor from which it leases an undivided interest in the Grand Gulf nuclear plant.  System Energy is the lessee under this arrangement, which is described in more detail in Note 10 to the financial statements. System Energy made payments on its lease, including interest, of $17.2 million in 2019, $17.2 million in 2018, and $17.2 million in 2017.  The lessor is a bank acting in the capacity of owner trustee for the benefit of equity investors in the transaction pursuant to trust agreement entered solely for the purpose of facilitating the lease transaction.  It is possible that System Energy may be considered as the primary beneficiary of the lessor, but it is unable to apply the authoritative accounting guidance with respect to this VIE because the lessor is not required to, and could not, provide the necessary financial information to consolidate the lessor.  Because System Energy accounts for this leasing arrangement as a capital financing, however, System Energy believes that consolidating the lessor would not materially affect the financial statements.  In the unlikely event of default under a lease, remedies available to the lessor include payment by the lessee of the fair value of the undivided interest in the plant, payment of the present value of the basic rent payments, or payment of a predetermined casualty value.  System Energy believes, however, that the obligations recorded on the balance sheet materially represent its potential exposure to loss.

Entergy has also reviewed various lease arrangements, power purchase agreements, including agreements for renewable power, and other agreements that represent variable interests in other legal entities which have been determined to be variable interest entities.  In these cases, Entergy has determined that it is not the primary beneficiary of the related VIE because it does not have the power to direct the activities of the VIE that most significantly affect the VIE’s economic performance, or it does not have the obligation to absorb losses or the right to residual returns that would potentially be significant to the entity, or both.

Each Registrant Subsidiary purchases electricity from or sells electricity to the other Registrant Subsidiaries, or both, under rate schedules filed with the FERC.  The Registrant Subsidiaries receive management, technical, advisory, operating, and administrative services from Entergy Services; and receive management, technical, and operating services from Entergy Operations.  These transactions are on an “at cost” basis.

As described in Note 1 to the financial statements, all of System Energy’s operating revenues consist of billings to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.

As described in Note 4 to the financial statements, the Registrant Subsidiaries participate in Entergy’s money pool and earn interest income from the money pool.  As described in Note 2 to the financial statements, Entergy Louisiana receives preferred membership interest distributions from Entergy Holdings Company.

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The tables below contain the various affiliate transactions of the Utility operating companies, System Energy, and other Entergy affiliates.

Intercompany Revenues

	Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
	(In Millions)
2019		$117.5				$277.8				$1.4				$—				$51.6				$584.1
2018		$104.3				$299.0				$2.5				$—				$58.8				$456.7
2017		$127.8				$282.4				$1.7				$—				$57.9				$633.5

Intercompany Operating Expenses

	Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
	(In Millions)
2019		$534.0				$665.4				$306.7				$292.1				$255.0				$156.2
2018		$471.9				$627.8				$266.8				$256.4				$240.2				$176.5
2017		$510.2				$619.5				$310.5				$286.1				$234.6				$197.0

Intercompany Interest and Investment Income

	Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
					(In Millions)
2019		$0.4				$128.5				$0.4				$—				$0.4				$1.0
2018		$0.4				$128.2				$—				$—				$0.2				$1.2
2017		$—				$128.0				$—				$0.2				$—				$0.9

Transactions with Equity Method Investees

EWO Marketing, LLC, an indirect wholly-owned subsidiary of Entergy, paid capacity charges and gas transportation to RS Cogen in the amounts of $24.5 million in 2019, $24 million in 2018, and $24.6 million in 2017.

Entergy’s operating transactions with its other equity method investees were not significant in 2019, 2018, or 2017.

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Entergy implemented ASU 2014-09, “Revenue from Contracts with Customers (Topic 606),” effective January 1, 2018. Topic 606 requires entities to “recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.” The ASU details a five-step model that should be followed to achieve the core principle. This accounting was applied to all contracts using the modified retrospective method, which requires an adjustment to retained earnings for the cumulative effect of adopting the standard as of the effective date. Because the standard did not result in any material change in Entergy’s revenue recognition no adjustment to retained earnings was required upon implementation. Similarly, there was no effect on revenues recognized under Topic 606 for the year ended December 31, 2018.

Revenues from electric service and the sale of natural gas are recognized when services are transferred to the customer in an amount equal to what Entergy has the right to bill the customer because this amount represents the value of services provided to customers.

Entergy’s total revenues for the years ended December 31, 2019 and 2018 are as follows:

		2019				2018
		(In Thousands)
Utility:
Residential			$3,531,500				$3,565,522
Commercial		2,475,586				2,426,477
Industrial		2,541,287				2,499,227
Governmental		228,470				225,882
Total billed retail		8,776,843				8,717,108
Sales for resale (a)		285,722				299,567
Other electric revenues (b)		343,143				326,910
Revenues from contracts with customers		9,405,708				9,343,585
Other revenues (c)		24,270				40,526
Total electric revenues		9,429,978				9,384,111
Natural gas		153,954				156,436
Entergy Wholesale Commodities:
Competitive businesses sales from    contracts with customers (a)		1,164,552				1,547,994
Other revenues (c)		130,189				(79,089		)
Total competitive businesses revenues		1,294,741				1,468,905
Total operating revenues			$10,878,673				$11,009,452

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The Registrant Subsidiaries’ total revenues for the year ended December 31, 2019 were as follows:

2019		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas
		(In Thousands)
Residential			$795,269				$1,270,478				$562,219				$245,081				$658,453
Commercial		538,850				947,412				444,173				202,138				343,013
Industrial		520,958				1,450,966				164,491				31,824				373,048
Governmental		20,795				71,046				44,300				70,865				21,464
Total billed retail		1,875,872				3,739,902				1,215,183				549,908				1,395,978
Sales for resale (a)		257,864				333,395				39,295				38,626				59,074
Other electric revenues (b)		112,618				135,783				58,269				9,842				32,424
Revenues from contracts         with customers		2,246,354				4,209,080				1,312,747				598,376				1,487,476
Other revenues (c)		13,240				13,947				10,296				(3,959		)		1,479
Total electric revenues		2,259,594				4,223,027				1,323,043				594,417				1,488,955
Natural gas		—				62,148				—				91,806				—
Total operating revenues			$2,259,594				$4,285,175				$1,323,043				$686,223				$1,488,955

    

The Registrant Subsidiaries’ total revenues for the year ended December 31, 2018 were as follows:

2018		Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas
		(In Thousands)
Residential			$807,098				$1,244,413				$578,568				$261,585				$673,858
Commercial		425,523				941,321				461,832				217,182				380,619
Industrial		434,387				1,462,462				175,056				33,371				393,951
Governmental		16,537				68,587				43,747				72,058				24,953
Total billed retail		1,683,545				3,716,783				1,259,203				584,196				1,473,381
Sales for resale (a)		248,861				356,603				25,812				29,506				97,478
Other electric revenues (b)		111,875				144,978				39,897				4,718				31,413
Revenues from contracts         with customers		2,044,281				4,218,364				1,324,912				618,420				1,602,272
Other revenues (c)		16,362				14,177				10,200				6,313				3,630
Total electric revenues		2,060,643				4,232,541				1,335,112				624,733				1,605,902
Natural gas		—				63,779				—				92,657				—
Total operating revenues			$2,060,643				$4,296,320				$1,335,112				$717,390				$1,605,902

(a)

Sales for resale and competitive businesses sales include day-ahead sales of energy in a market administered by an ISO. These sales represent financially binding commitments for the sale of physical energy the next day. These sales are adjusted to actual power generated and delivered in the real time market. Given the short duration of these transactions, Entergy does not consider them to be derivatives subject to fair value adjustments, and includes them as part of customer revenues.

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(b)	Other electric revenues consist primarily of transmission and ancillary services provided to participants of an ISO-administered market and unbilled revenue.

(c)	Other revenues include the settlement of financial hedges, occasional sales of inventory, alternative revenue programs, provisions for revenue subject to refund, and late fees.

Electric Revenues

Entergy’s primary source of revenue is from retail electric sales sold under tariff rates approved by regulators in its various jurisdictions. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas generate, transmit, and distribute electric power primarily to retail customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy’s Utility operating companies provide power to customers on demand throughout the month, measured by a meter located at the customer’s property. Approved rates vary by customer class due to differing requirements of the customers and market factors involved in fulfilling those requirements. Entergy issues monthly bills to customers at rates approved by regulators for power and related services provided during the previous billing cycle.

To the extent that deliveries have occurred but a bill has not been issued, Entergy’s Utility operating companies record an estimate for energy delivered since the latest billings. The Utility operating companies calculate the estimate based upon several factors including billings through the last billing cycle in a month, actual generation in the month, historical line loss factors, and market prices of power in the respective jurisdiction. The inputs are revised as needed to approximate actual usage and cost. Each month, estimated unbilled amounts are recorded as unbilled revenue and accounts receivable, and the prior month’s estimate is reversed. Price and volume differences resulting from factors such as weather affect the calculation of unbilled revenues from one period to the other.

Entergy may record revenue based on rates that are subject to refund. Such revenues are reduced by estimated refund amounts when Entergy believes refunds are probable based on the status of rate proceedings as of the date financial statements are prepared. Because these refunds will be made through a reduction in future rates, and not as a reduction in bills previously issued, they are presented as other revenues in the table above.

System Energy’s only source of revenue is the sale of electric power and capacity generated from its 90% interest in the Grand Gulf nuclear plant to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. System Energy issues monthly bills to its affiliated customers equal to its actual operating costs plus a return on common equity approved by the FERC.

Entergy’s Utility operating companies also sell excess power not needed for its own customers, primarily through transactions with MISO, a regional transmission organization that maintains functional control over the combined transmission systems of its members and manages one of the largest energy markets in the U.S. In the MISO market, Entergy offers its generation and bids its load into the market. MISO settles these offers and bids based on locational marginal prices. These represent pricing for energy at a given location based on a market clearing price that takes into account physical limitations on the transmission system, generation, and demand throughout the MISO region. MISO evaluates each market participant’s energy offers and demand bids to economically and reliably dispatch the entire MISO system. Entergy nets purchases and sales within the MISO market and reports in operating revenues when in a net selling position and in operating expenses when in a net purchasing position.

Natural Gas

Entergy Louisiana and Entergy New Orleans also distribute natural gas to retail customers in and around Baton Rouge, Louisiana, and New Orleans, Louisiana, respectively. Gas transferred to customers is measured by a meter at the customer’s property. Entergy issues monthly invoices to customers at rates approved by regulators for the volume of gas transferred to date.

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Competitive Businesses Revenues

The Entergy Wholesale Commodities segment derives almost all of its revenue from sales of electric power and capacity produced by its operating plants to wholesale customers. The majority of Entergy Wholesale Commodities’ revenues are from Entergy’s nuclear power plants located in the northern United States. Entergy issues monthly invoices to the counterparties for these electric sales at the respective contracted or ISO market rate of electricity and related services provided during the previous month.

Most of the Palisades nuclear plant output is sold under a 15-year PPA with Consumers Energy, executed as part of the acquisition of the plant in 2007 and expiring in 2022. Prices under the PPA range from $43.50/MWh in 2007 to $61.50/MWh in 2022, and the average price under the PPA is $51/MWh. Entergy issues monthly invoices to Consumers Energy for electric sales based on the actual output of electricity and related services provided during the previous month at the contract price.  The PPA was at below-market prices at the time of the acquisition and Entergy amortizes a liability to revenue over the life of the agreement.  The amount amortized each period is based upon the present value, calculated at the date of acquisition, of each year’s difference between revenue under the agreement and revenue based on estimated market prices.  Amounts amortized to revenue were $10 million in 2019, $6 million in 2018, and $28 million in 2017.  Amounts to be amortized to revenue through the remaining life of the agreement will be approximately $11 million in 2020, $12 million in 2021, and $5 million in 2022.

Practical Expedients and Exceptions

Entergy has elected not to disclose the value of unsatisfied performance obligations for contracts with an original expected term of one year or less, or for revenue recognized in an amount equal to what Entergy has the right to bill the customer for services performed.

Most of Entergy’s contracts, except in a few cases where there are defined minimums or stated terms, are on demand. This results in customer bills that vary each month based on an approved tariff and usage. Entergy imposes monthly or annual minimum requirements on some customers primarily as credit and cost recovery guarantees and not as pricing for unsatisfied performance obligations. These minimums typically expire after the initial term or when specified costs have been recovered. The minimum amounts are part of each month’s bill and recognized as revenue accordingly. Some of the subsidiaries within the Entergy Wholesale Commodities segment have operations and maintenance services contracts that have fixed components and terms longer than one year. The total fixed consideration related to these unsatisfied performance obligations, however, is not material to Entergy revenues.

Recovery of Fuel Costs

Entergy’s Utility operating companies’ rate schedules include either fuel adjustment clauses or fixed fuel factors, which allow either current recovery in billings to customers or deferral of fuel costs until the costs are billed to customers. Where the fuel component of revenues is based on a pre-determined fuel cost (fixed fuel factor), the fuel factor remains in effect until changed as part of a general rate case, fuel reconciliation, or fixed fuel factor filing. System Energy’s operating revenues are intended to recover from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans operating expenses and capital costs attributable to Grand Gulf. The capital costs are based on System Energy’s common equity funds allocable to its net investment in Grand Gulf, plus System Energy’s effective interest cost for its debt allocable to its investment in Grand Gulf.

Taxes Imposed on Revenue-Producing Transactions

Governmental authorities assess taxes that are both imposed on and concurrent with a specific revenue-producing transaction between a seller and a customer, including, but not limited to, sales, use, value added, and some excise taxes.  Entergy presents these taxes on a net basis, excluding them from revenues.

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Operating results for the four quarters of 2019 and 2018 for Entergy Corporation and subsidiaries were:

	Operating Revenues				Operating Income (Loss)				Consolidated Net Income (Loss)				Net Income (Loss) Attributable to Entergy Corporation
	(In Thousands)
2019:
First Quarter		$2,609,584				$283,254				$258,646				$254,537
Second Quarter		$2,666,209				$338,775				$240,533				$236,424
Third Quarter		$3,140,575				$519,929				$369,459				$365,240
Fourth Quarter		$2,462,305				$248,539				$389,606				$385,025
2018:
First Quarter		$2,723,881				$335,664				$136,200				$132,761
Second Quarter		$2,668,770				$91,597				$248,860				$245,421
Third Quarter		$3,104,319				$271,035				$539,818				$536,379
Fourth Quarter		$2,512,482				($228,931	)			($62,323	)			($65,900	)

Earnings (loss) per average common share

	2019								2018
	Basic				Diluted				Basic				Diluted
First Quarter		$1.34				$1.32				$0.73				$0.73
Second Quarter		$1.22				$1.22				$1.36				$1.34
Third Quarter		$1.84				$1.82				$2.96				$2.92
Fourth Quarter		$1.96				$1.94				($0.37	)			($0.36	)

Results of operations for 2019 include: 1) a loss of $190 million ($156 million net-of-tax) as a result of the sale of the Pilgrim plant in August 2019; 2) a $156 million reduction in income tax expense recognized by Entergy Wholesale Commodities as a result of an internal restructuring; and 3) impairment charges of $100 million ($79 million net-of-tax) due to costs being charged directly to expense as incurred as a result of the impaired value of the Entergy Wholesale Commodities nuclear plants’ long-lived assets due to the significantly reduced remaining estimated operating lives associated with management’s strategy to exit the Entergy Wholesale Commodities’ merchant power business. See Note 3 to the financial statements for further discussion of the internal restructuring. See Note 14 to the financial statements for further discussion of the sale of the Pilgrim plant.

    

Results of operations for 2018 include: 1) $532 million ($421 million net-of-tax) of impairment charges due to costs being charged directly to expense as incurred as a result of the impaired value of the Entergy Wholesale Commodities nuclear plants’ long-lived assets due to the significantly reduced remaining estimated operating lives associated with management’s strategy to exit the Entergy Wholesale Commodities’ merchant power business; 2) a $170 million reduction of income tax expense and a regulatory liability of $40 million ($30 million net-of-tax) as a result of customer credits recognized by Utility, as a result of an internal restructuring; 3) a $107 million reduction of income tax expense, recognized by Entergy Wholesale Commodities, as a result of a restructuring of the investment holdings in one of its nuclear plant decommissioning trust funds; 4) a $52 million income tax benefit, recognized by Entergy Louisiana, as a result of the settlement of the 2012-2013 IRS audit, associated with the Hurricane Katrina and Hurricane Rita contingent sharing obligation associated with the Louisiana Act 55 financing; and 5) a $23 million

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reduction of income tax expense, recognized by Entergy Wholesale Commodities, as a result of a state income tax audit. See Note 14 to the financial statements for further discussion of the impairment and related charges. See Notes 2 and 3 to the financial statements for further discussion of the internal restructuring and customer credits. See Note 3 to the financial statements for further discussion of the IRS audit settlement, the state income tax audit, and restructuring of the decommissioning trust fund investment holdings.

The business of the Utility operating companies is subject to seasonal fluctuations with the peak periods occurring during the third quarter.  Operating results for the Registrant Subsidiaries for the four quarters of 2019 and 2018 were:

Operating Revenues

	Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
	(In Thousands)
2019:
First Quarter		$545,812				$959,330				$282,244				$163,194				$340,474				$140,104
Second Quarter		$542,929				$1,106,317				$302,737				$175,793				$363,580				$139,009
Third Quarter		$687,526				$1,231,677				$398,732				$194,204				$442,877				$145,472
Fourth Quarter		$483,327				$987,851				$339,330				$153,032				$342,024				$148,825
2018:
First Quarter		$551,024				$1,029,344				$315,743				$188,275				$348,940				$148,443
Second Quarter		$494,605				$1,072,788				$353,689				$178,446				$403,486				$112,456
Third Quarter		$568,399				$1,206,612				$367,734				$200,182				$477,231				$78,965
Fourth Quarter		$446,615				$987,576				$297,946				$150,487				$376,245				$116,843

Operating Income (Loss)

	Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
	(In Thousands)
2019:
First Quarter		$42,471				$153,944				$30,792				$16,136				$16,741				$31,368
Second Quarter		$69,774				$241,520				$45,607				$17,509				$36,022				$24,300
Third Quarter		$182,176				$336,754				$87,024				$28,876				$69,510				$29,086
Fourth Quarter		$32,576				$164,424				$40,331				$6,164				$24,229				$30,231
2018:
First Quarter		$66,647				$141,319				$41,432				$17,869				$41,082				$30,941
Second Quarter		$26,501				$150,160				($63,801	)			$27,943				$58,637				$23,406
Third Quarter		$34,785				$236,518				$45,215				$21,544				$99,966				($17,879	)
Fourth Quarter		($82,704	)			$147,774				$23,600				$6,836				$6,741				$7,212

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Net Income

	Entergy Arkansas				Entergy Louisiana				Entergy Mississippi				Entergy New Orleans				Entergy Texas				System Energy
	(In Thousands)
2019:
First Quarter		$39,121				$127,633				$15,398				$9,023				$21,342				$23,578
Second Quarter		$50,299				$183,084				$26,667				$13,003				$38,936				$24,472
Third Quarter		$149,716				$255,260				$56,237				$24,908				$73,224				$25,031
Fourth Quarter		$23,828				$125,560				$21,623				$5,695				$25,895				$26,039
2018:
First Quarter		$36,255				$111,593				$22,843				$10,882				$17,350				$22,308
Second Quarter		$82,556				$184,358				$38,242				$18,269				$30,789				$23,387
Third Quarter		$128,890				$218,308				$50,733				$21,407				$65,846				$22,972
Fourth Quarter		$5,006				$161,355				$14,260				$2,594				$48,250				$25,442

Earnings Applicable to Common Equity/Stock

	Entergy Arkansas				Entergy Mississippi				Entergy New Orleans				Entergy Texas
	(In Thousands)
2019:
First Quarter		$39,121				$15,398				$9,023				$21,342
Second Quarter		$50,299				$26,667				$13,003				$38,936
Third Quarter		$149,716				$56,237				$24,908				$73,114
Fourth Quarter		$23,828				$21,623				$5,695				$25,425
2018:
First Quarter		$35,898				$22,605				$10,882				$17,350
Second Quarter		$82,199				$38,003				$18,269				$30,789
Third Quarter		$128,533				$50,495				$21,407				$65,846
Fourth Quarter		$4,828				$14,141				$2,594				$48,250

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•	The Utility business segment includes the generation, transmission, distribution, and sale of electric power in portions of Arkansas, Mississippi, Texas, and Louisiana, including the City of New Orleans; and operation of a small natural gas distribution business.

•

The Entergy Wholesale Commodities business segment includes the ownership, operation, and decommissioning of nuclear power plants located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers. Entergy Wholesale Commodities also provides services to other nuclear power plant owners and owns interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Wholesale Commodities Exit from the Merchant Power Business” for discussion of the operation and planned shutdown and sale of each of the Entergy Wholesale Commodities nuclear power plants.

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(a)	Includes the effect of intercompany eliminations.

(a)	Major industrial customers are primarily in the petroleum refining and chemical industries.

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(a)	Based on 2020 test year.

(b)	Based on December 31, 2018 test year and excludes approximately $800 million for the St. Charles Power Station, included in capacity rider, and $300 million of transmission plant, included in transmission rider.

(c)	Based on September 30, 2018 test year.

(d)	Based on 2019 forward test year.

(e)	Based on December 31, 2018 test year and known and measurables through December 31, 2019.

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(f)	Based on December 31, 2017 test year.

(g)	Based on calculation as of December 31, 2019.

(h)	See Note 2 to the financial statements for discussion of ongoing proceedings at the FERC challenging System Energy’s authorized return on common equity and capital structure.

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(a)	“Owned and Leased Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.

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•	Entergy Louisiana’s June 2005 purchase of the 718 MW, gas-fired Perryville plant, of which 35% of the output is sold to Entergy Texas;

•	Entergy Arkansas’s September 2008 purchase of the 789 MW, combined-cycle, gas-fired Ouachita Generating Facility. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, owns one-third of the facility;

•	Entergy Arkansas’s November 2012 purchase of the 620 MW, combined-cycle, gas-fired Hot Spring Energy facility;

•	Entergy Mississippi’s November 2012 purchase of the 450 MW, combined-cycle, gas-fired Hinds Energy facility;

•	Entergy Louisiana’s construction of the 560 MW, combined-cycle, gas turbine Ninemile 6 generating facility at its existing Ninemile Point electric generating station. The facility began commercial operation in December 2014;

•	Entergy Louisiana’s construction of the 980 MW, combined-cycle, gas turbine St. Charles generating facility at its existing Little Gypsy electric generating station. The facility began commercial operation in May 2019;

•	Entergy Texas’s construction of the 993 MW, combined-cycle, gas turbine Montgomery County generating facility at its existing Lewis Creek electric generating station. Entergy Texas received regulatory approval from the PUCT in July 2017 and the facility is scheduled to be in service by mid-2021;

•	Entergy Louisiana’s construction of the 994 MW, combined-cycle, gas turbine Lake Charles generating facility at its existing Nelson electric generating station. Entergy Louisiana received regulatory approval from the LPSC in July 2017 and the facility is scheduled to be in service by mid-2020;

•

In October 2018, Entergy Mississippi signed an asset acquisition agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic facility located in Sunflower County, Mississippi. In December 2018, Entergy Mississippi filed for regulatory approval. A hearing before the MPSC is targeted to occur by the second quarter 2020, and closing is expected to occur by the end of 2021;

•	In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar energy facility that will be sited on approximately 800 acres in White County near Searcy, Arkansas. In May 2019, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction

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•	Entergy New Orleans’s construction of the 20 MW, self-build solar project New Orleans Solar Station located at the NASA Michoud Facility. In August 2019, Entergy New Orleans received regulatory approval and the facility is scheduled to be in service as early as late-2020.

•	River Bend 30% life-of-unit PPA between Entergy Louisiana and Entergy New Orleans for 100 MW related to Entergy Louisiana’s unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun;

•	Entergy Arkansas wholesale base load capacity life-of-unit PPAs executed in 2003 totaling approximately 220 MW between Entergy Arkansas and Entergy Louisiana (110 MW) and between Entergy Arkansas and Entergy New Orleans (110 MW) related to the sale of a portion of Entergy Arkansas’s coal and nuclear base load resources (which had not been included in Entergy Arkansas’s retail rates);

•	In December 2009, Entergy Texas and Exelon Generation Company, LLC executed a 10-year agreement for 150-300 MW from the Frontier Generating Station located in Grimes County, Texas;

•	In May 2011, Entergy Texas and Calpine Energy Services, L.P. executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. Entergy Louisiana purchases 50% of the facility’s capacity and energy from Entergy Texas. In July 2014, LS Power purchased the Carville Energy Center and replaced Calpine Energy Services as the counterparty to the agreement;

•

In September 2012, Entergy Gulf States Louisiana executed a 20-year agreement for 28 MW, with the potential to purchase an additional 9 MW when available, from Rain CII Carbon LLC’s petroleum coke calcining facility in Sulphur, Louisiana. The facility began commercial operation in May 2013. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with the facility;

•	In March 2013, Entergy Gulf States Louisiana executed a 20-year agreement for 8.5 MW from Agrilectric Power Partners, LP’s refurbished rice hull-fueled electric generation facility located in Lake Charles, Louisiana. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with Agrilectric;

•	In September 2013, Entergy Louisiana executed a 10-year agreement with TX LFG Energy, LP, a wholly-owned subsidiary of Montauk Energy Holdings, LLC, to purchase approximately 3 MW from its landfill gas-fueled power generation facility located in Cleveland, Texas;

•	Entergy Mississippi’s cost-based purchase, beginning in January 2013, of 90 MW from Entergy Arkansas’s share of Grand Gulf (only 60 MW of this PPA came through the RFP process). Cost recovery for the 90 MW was approved by the MPSC in January 2013;

•	In April 2015, Entergy Arkansas and Stuttgart Solar, LLC executed a 20-year agreement for 81 MW from a solar photovoltaic electric generation facility located near Stuttgart, Arkansas. The APSC approved the project and deliveries pursuant to that agreement commenced in June 2018;

•	In November 2016, Entergy Louisiana and LS Power executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. The transaction received regulatory approval and will begin in June 2022;

•	In November 2016, Entergy Louisiana and Occidental Chemical Corporation executed a 10-year agreement for 500 MW from the Taft Cogeneration facility located in Hahnville, Louisiana. The transaction received regulatory approval and began in June 2018;

•	In June 2017, Entergy Arkansas and Chicot Solar, LLC executed a 20-year agreement for 100 MW from a solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and will begin in August 2020;

•	In February 2018, Entergy Louisiana and LA3 West Baton Rouge, LLC (Capital Region Solar project) executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the agreement is expected to begin in second quarter 2020;

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•	In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019; and

•	In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019.

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(a)	Hydroelectric power provided less than 1% of Entergy Arkansas’s generation in 2019 and is expected to provide less than 1% of its generation in 2020.

(b)	Solar power provided less than 1% of Entergy Mississippi’s and Entergy New Orleans's generation in 2019 and is expected to provide less than 1% of each of Entergy Mississippi’s and Entergy New Orleans's generation in 2020.

(c)

Capacity and energy from System Energy’s interest in Grand Gulf is allocated as follows under the Unit Power Sales Agreement: Entergy Arkansas - 36%; Entergy Louisiana - 14%; Entergy Mississippi - 33%; and Entergy New Orleans - 17%.  Pursuant to purchased power agreements, Entergy Arkansas is selling a portion of its owned capacity and energy from Grand Gulf to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.

(d)	Excludes MISO purchases.

(e)	In December 2013, Entergy integrated its transmission system into the MISO RTO. Entergy offers all of its generation into the MISO energy market on a day-ahead and real-time basis and bids for power in the MISO energy market to serve the demand of its customers, with MISO making dispatch decisions. The MISO purchases metric provided for 2019 is not projected for 2020.

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•	mining and milling of uranium ore to produce a concentrate;

•	conversion of the concentrate to uranium hexafluoride gas;

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•	enrichment of the uranium hexafluoride gas;

•	fabrication of nuclear fuel assemblies for use in fueling nuclear reactors; and

•	disposal of spent fuel.

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•	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.

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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.

•	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.

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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.

•	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.

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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.

(a)	The Indian Point 2 and Indian Point 3 plants are expected to cease operation by April 30, 2020 and April 30, 2021, respectively.

(b)	The Palisades plant is expected to cease operations no later than May 31, 2022.

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(a)	“Net Owned Capacity” refers to the nameplate rating on the generating unit.

(b)	The owned MW capacity is the portion of the plant capacity owned by Entergy Wholesale Commodities.  For a complete listing of Entergy’s jointly-owned generating stations, refer to “Jointly-Owned Generating Stations” in Note 1 to the financial statements.

(c)	Indirectly owned through interests in unconsolidated joint ventures.

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•	the transmission and wholesale sale of electric energy in interstate commerce;

•	the reliability of the high voltage interstate transmission system through reliability standards;

•	sale or acquisition of certain assets;

•	securities issuances;

•	the licensing of certain hydroelectric projects;

•	certain other activities, including accounting policies and practices of electric and gas utilities; and

•	changes in control of FERC jurisdictional entities or rate schedules.

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•	utility service;

•	utility service areas;

•	retail rates and charges, including depreciation rates;

•	fuel cost recovery, including audits of the energy cost recovery rider;

•	terms and conditions of service;

•	service standards;

•	the acquisition, sale, or lease of any public utility plant or property constituting an operating unit or system;

•	certificates of convenience and necessity and certificates of environmental compatibility and public need, as applicable, for generating and transmission facilities;

•	avoided cost payments to Qualifying Facilities;

•	net energy metering;

•	integrated resource planning;

•	utility mergers and acquisitions and other changes of control; and

•	the issuance and sale of certain securities.

•	utility service;

•	retail rates and charges, including depreciation rates;

•	fuel cost recovery, including audits of the fuel adjustment clause and purchased gas adjustment charge;

•	terms and conditions of service;

•	service standards;

•	certification of certain transmission projects;

•	certification of capacity acquisitions, both for owned capacity and purchase power contracts;

•	procurement process to acquire over 50 MW;

•	audits of the environmental adjustment charge, avoided cost payment to Qualifying Facilities, and energy efficiency rider;

•	integrated resource planning;

•	net energy metering; and

•	utility mergers and acquisitions and other changes of control.

•	utility service;

•	utility service areas;

•	retail rates and charges, including depreciation rates;

•	fuel cost recovery, including audits of the energy cost recovery mechanism;

•	terms and conditions of service;

•	service standards;

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•	certification of generating facilities and certain transmission projects;

•	avoided cost payments to Qualifying Facilities;

•	integrated resource planning;

•	net energy metering; and

•	utility mergers, acquisitions, and other changes of control.

•	utility service;

•	retail rates and charges, including depreciation rates;

•	fuel cost recovery, including audits of the fuel adjustment charge and purchased gas adjustment charge;

•	terms and conditions of service;

•	service standards;

•	audit of the environmental adjustment charge;

•	certification of the construction or extension of any new plant, equipment, property, or facility that comprises more than 2% of the utility’s rate base;

•	integrated resource planning;

•	net energy metering;

•	issuance and sale of certain securities; and

•	utility mergers and acquisitions and other changes of control.

•	retail rates and charges, including depreciation rates, and terms and conditions of service in unincorporated areas of its service territory, and in municipalities that have ceded jurisdiction to the PUCT;

•	fuel recovery, including reconciliations (audits) of the fuel adjustment charges;

•	service standards;

•	certification of certain transmission and generation projects;

•	utility service areas, including extensions into new areas;

•	avoided cost payments to Qualifying Facilities; and

•	utility mergers, sales/acquisitions/leases of plants over $10 million, sales of greater than 50% voting stock of utilities, and transfers of controlling interest in or operation of utilities.

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•	New source review and preconstruction permits for new sources of criteria air pollutants, greenhouse gases, and significant modifications to existing facilities;

•	Acid rain program for control of sulfur dioxide (SO2) and nitrogen oxides (NOx);

•	Nonattainment area programs for control of criteria air pollutants, which could include fee assessments for air pollutant emission sources under Section 185 of the Clean Air Act if attainment is not reached in a timely manner;

•	Hazardous air pollutant emissions reduction programs;

•	Interstate Air Transport;

•	Operating permit programs and enforcement of these and other Clean Air Act programs;

•	Regional Haze programs; and

•	New and existing source standards for greenhouse gas and other air emissions.

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•	designation by the EPA and state environmental agencies of areas that are not in attainment with national ambient air quality standards;

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introduction of bills in Congress and development of regulations by the EPA proposing further limits on NOx, SO2, mercury, and carbon dioxide and other air emissions.  New legislation or regulations applicable to stationary sources could take the form of market-based cap-and-trade programs, direct requirements for the installation of air emission controls onto air emission sources, or other or combined regulatory programs;

•	efforts in Congress or at the EPA to establish a federal carbon dioxide emission tax, control structure or unit performance standards;

•	revisions to the estimates of the Social Cost of Carbon and its use for regulatory impact analysis of Federal laws and regulations;

•	implementation of the Regional Greenhouse Gas Initiative by several states in the northeastern United States and similar actions in other regions of the United States;

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•	efforts on the state and federal level to codify renewable portfolio standards, clean energy standards, or a similar mechanism requiring utilities to produce or purchase a certain percentage of their power from defined renewable energy sources or energy sources with lower emissions;

•	efforts to develop more stringent state water quality standards, effluent limitations for Entergy’s industry sector, stormwater runoff control regulations, and cooling water intake structure requirements;

•	efforts to restrict the previously-approved continued use of oil-filled equipment containing certain levels of PCBs;

•	efforts by certain external groups to encourage reporting and disclosure of carbon dioxide emissions and risk;

•	the listing of additional species as threatened or endangered, the protection of critical habitat for these species, and developments in the legal protection of eagles and migratory birds; and

•	the regulation of the management, disposal, and beneficial reuse of coal combustion residuals.

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•	acquired businesses or assets may not produce revenues, earnings or cash flow at anticipated levels;

•	acquired businesses or assets could have environmental, permitting or other problems for which contractual protections prove inadequate;

•	Entergy and/or its subsidiaries may assume liabilities that were not disclosed to them, that exceed their estimates, or for which their rights to indemnification from the seller are limited;

•	Entergy may experience issues integrating businesses into its internal controls over financial reporting;

•	the disposition of a business, including Entergy’s planned exit from the merchant power business, could divert management’s attention from other business concerns;

•	Entergy and/or its subsidiaries may be unable to obtain the necessary regulatory or governmental approvals to close a transaction, such approvals may be granted subject to terms that are unacceptable to them, or Entergy or its subsidiaries otherwise may be unable to achieve anticipated regulatory treatment of any such transaction or acquired business or assets; and

•	Entergy or its subsidiaries otherwise may be unable to achieve the full strategic and financial benefits that they anticipate from the transaction, or such benefits may be delayed or may not occur at all.

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•	a decrease of $20.2 million in nuclear generation expenses primarily due to a lower scope of work performed in 2019 as compared to 2018;

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the effects of recording in 2019 a final judgment to resolve claims in the ANO damages case against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $11.9 million of spent nuclear fuel storage costs previously recorded as other operation and maintenance expense. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and

•	a decrease of $5.5 million in vegetation maintenance costs.

•	an $11.2 million write-off in 2019 of specific costs related to the potential construction of scrubbers at the White Bluff plant;

•	an increase of $8.5 million in information technology expenses primarily due to higher costs related to applications and infrastructure support, enhanced cyber security, and upgrades and maintenance;

•	an increase of $7.4 million due to spending on initiatives to explore new customer products and services; and

•	an increase of $5.5 million in compensation and benefits costs primarily due to higher incentive-based compensation accruals in 2019 as compared to prior year.

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•	a decrease in the return of unprotected excess accumulated deferred income taxes to customers in 2019 as compared to 2018. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act;

•	payments in 2018 of $135 million to the other Utility operating companies as a result of a compliance filing made in response to the FERC’s October 2018 order in the opportunity sales proceeding. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding;

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income tax refunds of $34 million in 2019 compared to income tax payments of $44.4 million in 2018. Entergy Arkansas had income tax refunds in 2019 and income tax payments in 2018 in accordance with an intercompany income tax allocation agreement. The income tax refunds in 2019 resulted from the utilization of Entergy Arkansas’s net operating losses. The income tax payments in 2018 primarily resulted from the settlement of the 2012-2013 audit;

•	a decrease of $44.1 million in spending on nuclear refueling outages in 2019; and

•	the timing of recovery of fuel and purchased power costs.

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•	a decrease of $32.1 million in nuclear construction expenditures primarily due to a lower scope of work performed on various nuclear projects in 2019 as compared to 2018;

•	a decrease of $25.8 million in transmission construction expenditures primarily due to a lower scope of work performed on various projects in 2019 as compared to 2018; and

•	a decrease of $13 million as a result of fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and service deliveries, and the timing of cash payments during the nuclear fuel cycle.

•	a $350 million capital contribution from Entergy Corporation in May 2018 in anticipation of the return of unprotected excess accumulated deferred income taxes to customers and upcoming planned capital investments;

•	the issuance of $250 million of 4.0% Series first mortgage bonds in May 2018;

•	money pool activity;

•	net repayments of long-term borrowings of $44.5 million in 2019 compared to net long-term borrowings of $34.7 million in 2018 on the Entergy Arkansas nuclear fuel company variable interest entity credit facility; and

•	an increase of $23.2 million in common equity distributions paid in 2019 primarily to maintain Entergy Arkansas’s capital structure.

•	the issuance of $350 million of 4.20% Series mortgage bonds in March 2019;

•	net repayments of short-term borrowings of $50 million on the Entergy Arkansas nuclear fuel company variable interest entity credit facility in 2018; and

•	the redemption of $31.4 million of preferred stock in 2018 in connection with the internal restructuring. See Note 2 to the financial statements for further discussion of the internal restructuring and Note 6 to the financial statements for details of preferred stock activity.

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(a)	Calculation excludes the securitization bonds, which are non-recourse to Entergy Arkansas.

•	construction and other capital investments;

•	debt maturities or retirements;

•	working capital purposes, including the financing of fuel and purchased power costs; and

•	distribution and interest payments.

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(a)	Includes estimated interest payments.  Long-term debt is discussed in Note 5 to the financial statements.

(b)	Lease obligations are discussed in Note 10 to the financial statements.

(c)	Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services.  For Entergy Arkansas, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which are discussed in Note 8 to the financial statements.

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•	internally generated funds;

•	cash on hand;

•	debt or preferred membership interest issuances;

•	capital contributions; and

•	bank financing under new or existing facilities.

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•	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.

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•	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.

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•	a $14.8 million gain in 2018 from the sale of Willow Glen Power Station;

•	an increase of $12.7 million in information technology costs primarily due to higher costs related to applications and infrastructure support, enhanced cyber security, and upgrades and maintenance;

•	an increase of $12.4 million in spending on initiatives to explore new customer products and services; and

•	an increase of $9.6 million in compensation and benefits costs primarily due to higher incentive-based compensation accruals in 2019 as compared to prior year.

•	a decrease of $8.5 million in nuclear generation expenses primarily due to a lower scope of work performed during plant outages in 2019 as compared to 2018; and

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the effects of recording in 2019 the final judgment to resolve claims in the River Bend damages case against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of $5.2 million of spent nuclear fuel storage costs previously recorded as other operation and maintenance expense. See Note 8 to the financial statements for a discussion of the spent nuclear fuel litigation.

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•	income tax payments of $15.3 million in 2019 compared to $105.2 million in income tax refunds in 2018. Entergy Louisiana had income tax payments in 2019 and income tax refunds in 2018 in accordance with an intercompany tax allocation agreement. The income tax refunds in 2018 resulted from the utilization of Entergy Louisiana’s net operating losses;

•	an increase of $65.2 million in spending on nuclear refueling outages;

•	the receipt of $58.6 million in 2018 from Entergy Arkansas as a result of a compliance filing made in response to the FERC’s October 2018 order in the Entergy Arkansas opportunity sales proceeding. The $58.6 million was credited to Entergy Louisiana customers in 2019. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding;

•	the timing of payments to vendors;

•	an increase of $25.7 million in storm expenses in 2019;

•	an increase of $24.5 million in interest paid; and

•	the timing of collection of receivables from customers.

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•	an increase of $63.6 million in transmission expenditures primarily due to a higher scope of work performed in 2019 as compared to the same period in 2018;

•	an increase of $63.1 million in distribution construction expenditures primarily due to investment in the reliability and infrastructure of Entergy Louisiana’s distribution system, including increased spending on advanced metering infrastructure; and

•	an increase of $46.5 million in storm spending in 2019.

•	the issuance of $750 million of 4.00% Series mortgage bonds in March 2018. A portion of the proceeds was used to repay $375 million of 6.0% Series mortgage bonds in May 2018;

•	the issuance of $600 million of 4.20% Series mortgage bonds in August 2018. A portion of the proceeds was used to repay $300 million of 6.5% Series mortgage bonds in September 2018; and

•	an increase of $80 million in common equity distributions in 2019 primarily to maintain Entergy Louisiana’s capital structure.

•	the issuance of $525 million of 4.20% Series mortgage bonds in March 2019;

•	money pool activity; and

•	net repayments of short-term borrowings of $43.5 million in 2018 on the nuclear fuel company variable interest entities’ credit facilities.

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(a)	Calculation excludes the securitization bonds, which are non-recourse to Entergy Louisiana.

•	construction and other capital investments;

•	debt maturities or retirements;

•	working capital purposes, including the financing of fuel and purchased power costs; and

•	distribution and interest payments.

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(a)	Includes estimated interest payments.  Long-term debt is discussed in Note 5 to the financial statements.

(b)	Lease obligations are discussed in Note 10 to the financial statements.

(c)

Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services.  For Entergy Louisiana, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Vidalia purchased power agreement and the Unit Power Sales Agreement, both of which are discussed in Note 8 to the financial statements.

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•	internally generated funds;

•	cash on hand;

•	debt or preferred membership interest issuances;

•	capital contributions; and

•	bank financing under new or existing facilities.

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•	short-term borrowings not to exceed an aggregate amount of $450 million at any time outstanding;

•	long-term borrowings and security issuances; and

•	borrowings by its nuclear fuel company variable interest entities.

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•	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 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; and

•	a transmission recovery mechanism providing for the opportunity to recover certain transmission related expenditures in excess of $100 million 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.

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•	an increase of $4.7 million in spending on initiatives to explore new customer products and services; and

•	an increase of $4.6 million in information technology costs primarily due to higher costs related to applications and infrastructure support, enhanced cyber security, and upgrades and maintenance.

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•	the timing of collection of receivables from customers;

•	the receipt of $36.2 million from Entergy Arkansas as a result of a compliance filing made in response to the FERC’s October 2018 order in the Entergy Arkansas opportunity sales proceeding. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding; and

•	$26.2 million in proceeds from the sale of fuel oil inventory in 2018.

•	the purchase of the Choctaw Generating Station in October 2019 for approximately $305 million. See Note 14 to the financial statements for further discussion of the Choctaw Generating Station purchase;

•	an increase of $34.9 million primarily due to investment in the infrastructure of Entergy Mississippi’s distribution system, including increased spending on advanced metering infrastructure; and

•	an increase of $15.6 million in storm spending in 2019.

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•	the issuance of $435 million of 3.85% Series mortgage bonds in 2019 compared to the issuance of $55 million of 4.52% Series mortgage bonds 2018;

•	a capital contribution of $130 million in October 2019 in anticipation of the purchase of the Choctaw Generating Station in October 2019; and

•	the redemption of $20 million of preferred stock in 2018 in connection with the internal restructuring. See Note 2 to the financial statements for further discussion of the internal restructuring and Note 6 to the financial statements for details of preferred stock activity.

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•	construction and other capital investments;

•	debt maturities or retirements;

•	working capital purposes, including the financing of fuel and purchased power costs; and

•	distributions and interest payments.

(a)	Includes estimated interest payments.  Long-term debt is discussed in Note 5 to the financial statements.

(b)	Lease obligations are discussed in Note 10 to the financial statements.

(c)	Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services.  For Entergy Mississippi, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which is discussed in Note 8 to the financial statements.

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•	internally generated funds;

•	cash on hand;

•	debt or preferred membership interest issuances;

•	capital contributions; and

•	bank financing under new or existing facilities.

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•	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.

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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.

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•	a decrease of $9.2 million as a result of the deferral in 2019 of 2018 costs related to the rate case and a system conversion for Algiers customers as a result of the 2018 combined rate case resolution approved by the City

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•	a decrease of $2.9 million in distribution expenses primarily due to lower contract labor costs.

•	an increase of $2.9 million in spending on initiatives to explore new customer products and services;

•	an increase of $2.8 million in information technology costs primarily due to higher software maintenance costs and higher contract costs;

•	an increase of $2 million in customer service costs primarily due to higher labor costs, including contract labor; and

•	an increase of $1.8 million in energy efficiency costs.

•	an increase in allowance for equity funds used during construction resulting from higher construction work in progress in 2019, including the New Orleans Power Station project; and

•	the accrual in fourth quarter 2018 of a $5 million settlement offer in the New Orleans Power Station show cause proceeding. See “Liquidity and Capital Resources - Uses of Capital - New Orleans Power Station” below for discussion of the New Orleans Power Station proceedings.

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•	an increase of $15.6 million in transmission construction expenditures primarily due to a higher scope of work performed in 2019 as compared to 2018, including investment in Entergy New Orleans’s system reliability and infrastructure; and

•	an increase of $10.7 million in distribution construction expenditures primarily due to investment in the reliability and infrastructure of Entergy New Orleans’s distribution system, including increased spending on advanced metering infrastructure.

•	proceeds from a $70 million 3.0% unsecured term loan due May 2022 in December 2019;

•	$23.8 million in common equity distributions in 2018. There were no common equity distributions made in 2019 in anticipation of planned capital investments; and

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•	net borrowings of $20 million in 2019 on Entergy New Orleans’s credit facility.

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•	construction and other capital investments;

•	working capital purposes, including the financing of fuel and purchased power costs;

•	debt maturities or retirements; and

•	distribution and interest payments.

(a)	Includes estimated interest payments.  Long-term debt is discussed in Note 5 to the financial statements.

(b)	Lease obligations are discussed in Note 10 to the financial statements.

(c)	Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services.  For Entergy New Orleans, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which is discussed in Note 8 to the financial statements.

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•	internally generated funds;

•	cash on hand;

•	debt and preferred membership interest issuances;

•	capital contributions; and

•	bank financing under new or existing facilities.

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•	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.

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•	an increase of $5.1 million in information technology costs primarily due to higher costs related to applications

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•	an increase of $4.7 million in spending on initiatives to explore new customer products and services;

•	an increase of $3.9 million in fossil-fueled generation expenses primarily due to a higher scope of work performed during plant outages in 2019 as compared to 2018; and

•	an increase of $3.4 million in distribution operations and asset management costs primarily due to higher contract costs for meter reading services and higher advanced metering customer education costs.

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•	an increase of $243.3 million in fossil-fueled generation construction expenditures primarily due to increased spending on the Montgomery County Power Station;

•	an increase of $153.4 million in transmission construction expenditures primarily due to a higher scope of work performed in 2019 as compared to 2018;

•	an increase of $47.1 million in distribution construction expenditures primarily due to investment in the reliability and infrastructure of Entergy Texas’s distribution system, including increased spending on advanced metering infrastructure, and increased storm spending; and

•	money pool activity.

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•	the issuance of $300 million of 4.0% Series mortgage bonds and $400 million of 4.5% Series mortgage bonds in January 2019;

•	the issuance of $300 million of 3.55% Series mortgage bonds in September 2019;

•	capital contributions of $185 million in 2019 received from Entergy Corporation in anticipation of upcoming construction expenditures, including Montgomery County Power Station; and

•	the issuance of $35 million aggregate liquidation value 5.375% Series A preferred stock in September 2019.

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•	construction and other capital investments;

•	debt maturities or retirements;

•	working capital purposes, including the financing of fuel and purchased power costs; and

•	dividend and interest payments.

(a)	Includes estimated interest payments.  Long-term debt is discussed in Note 5 to the financial statements.

(b)	Lease obligations are discussed in Note 10 to the financial statements.

(c)	Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services.  For Entergy Texas, it primarily includes unconditional fuel and purchased power obligations.

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•	internally generated funds;

•	cash on hand;

•	debt or preferred stock issuances;

•	capital contributions; and

•	bank financing under new or existing facilities.

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•	the decrease in the return of the unprotected excess accumulated deferred income taxes in 2018;

•	a decrease in spending of $48.5 million on nuclear refueling outages in 2019 as compared to prior year; and

•	a decrease of $51.7 million in income taxes paid in 2019. System Energy made income tax payments of $54 million in 2018 in accordance with an intercompany income tax allocation agreement.

•	a decrease of $102.7 million as a result of fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle;

•	money pool activity; and

•	a decrease of $28.4 million in nuclear construction expenditures as a result of spending in 2018 on Grand Gulf outage projects.

•	the issuance in March 2018 of $100 million of 3.42% Series J notes by the System Energy nuclear fuel company variable interest entity;

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•	an increase of $56.5 million in common stock dividends and distributions in 2019. Common stock dividends and distributions were lower in 2018 in anticipation of the excess accumulated deferred income taxes being returned to customers as a result of the Tax Cuts and Jobs Act; and

•	net repayments of $82.3 million of long-term borrowings in 2019 compared to net borrowings of $63.9 million of long-term borrowings in 2018 on the nuclear fuel company variable interest entity’s credit facility.

•	the payment in October 2018, at maturity, of $85 million of the System Energy nuclear fuel company variable interest entity’s 3.78% Series I notes; and

•	net repayments of short-term borrowings of $17.8 million in 2018 on the nuclear fuel company variable interest entity’s credit facility.

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•	construction and other capital investments;

•	debt maturities or retirements;

•	working capital purposes, including the financing of fuel costs; and

•	dividend, distribution, and interest payments.

(a)	Includes estimated interest payments.  Long-term debt is discussed in Note 5 to the financial statements.

(b)	Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For System Energy, it includes nuclear fuel purchase obligations.

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•	internally generated funds;

•	cash on hand;

•	debt issuances; and

•	bank financing under new or existing facilities.

•	short-term borrowings not to exceed an aggregate amount of $200 million at any time outstanding;

•	long-term borrowings and security issuances; and

•	borrowings by its nuclear fuel company variable interest entity.

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(a)	In addition, this officer is an executive officer and/or director of various other wholly owned subsidiaries of Entergy Corporation and its operating companies.

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(1)	See Note 12 to the financial statements for additional discussion of the stock-based compensation plans.

(2)	Maximum amount of shares that may yet be repurchased relates only to the $500 million plan does not include an estimate of the amount of shares that may be purchased to fund the exercise of grants under the stock-based compensation plans.

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•	the number of shares of Entergy Corporation stock held by the shareholder;

•	the name and address of the candidate;

•	a brief biographical description of the candidate, including his or her occupation for at least the last five years, and a statement of the qualifications of the candidate, taking into account the qualification requirements discussed in the Proxy Statement under “Board of Directors - Identifying Director Candidates”; and

•	the candidate’s signed consent to be named in the Proxy Statement and a representation of such candidates’ intent to serve as a director for the entire term if elected.

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(1)	Messrs. Bakken, Brown, Denault, Marsh, and West hold the positions referenced above as executive officers of Entergy Corporation and are members of Entergy Corporation’s Office of the Chief Executive. No additional compensation was paid in 2019 to any of these officers for their service as Named Executive Officers of the Utility operating companies.

•	Motivate its management team to drive strong financial and operational results.

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•	Attract and retain a highly experienced and successful management team.

•	Incentivize and reward the achievement of financial and operational metrics that are deemed by the Personnel Committee to be consistent with the overall goals and strategic direction that the Board has approved for Entergy Corporation.

•	Align the interests of the executives and Entergy Corporation shareholders by directly tying the value of equity-based awards to Entergy Corporation’s stock price performance, relative total shareholder return and earnings growth.

•	Create sustainable value for the benefit of all of Entergy Corporation’s stakeholders, including its owners, customers, employees and communities.

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•

The earnings measure, ETR Tax Adjusted EPS, is based on the externally reported ETR Adjusted EPS, which is then adjusted to add back the effect of significant tax items, and to eliminate the effect of major storms, the resolution of certain unresolved regulatory litigation matters, changes in federal income tax law and unrealized gains or losses on equity securities (the “Pre-Determined Exclusions”).

•	The cash flow measure, ETR Adjusted Operating Cash Flow is calculated based on Entergy Corporation’s as-reported (GAAP) operating cash flow, adjusted to eliminate the effect of any Pre-Determined Exclusions.

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•	Published and private compensation survey data compiled by Pay Governance, LLC (“Pay Governance”), the Personnel Committee’s independent compensation consultant;

•	Both utility and general industry data to determine total cash compensation (base salary and annual incentive) for non-industry specific roles;

•	Data from utility companies to determine total cash compensation for management roles that are utility-specific, such as Group President, Utility Operations; and

•	Utility market data to determine long-term incentives for all positions.

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•

Establish Performance Measures to Determine EAM Pool. Annually, the Personnel Committee engages in a rigorous process to determine the performance measures used to determine the EAM. The Personnel Committee’s goal is to establish measures that are consistent with Entergy Corporation’s strategy and business objectives for the upcoming year, as reflected in its financial plan, and are designed to drive results that represent a high level of achievement. These measures are approved based on a comprehensive review by the full Board of Entergy Corporation’s financial plan, conducted in December of the preceding year and updated in January to reflect key drivers of anticipated changes in performance from the preceding year.

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•	Establish Target Achievement Levels. In January, after Entergy Corporation’s financial plan is updated to reflect any changes from that reviewed in December, the Personnel Committee establishes the specific targets that must be achieved for each performance measure. The Personnel Committee also seeks to assure that the targets:

◦	Take into account changes in the business environment and specific challenges facing Entergy Corporation;

◦	Reflect an appropriate balancing of the various risks and opportunities recognized at the time the targets are set; and

◦	Are aligned with external expectations communicated to Entergy Corporation’s shareholders.

•

Establish Named Officer Target Opportunities. In January of each year, the Personnel Committee establishes the target opportunities for the members of the Office of the Chief Executive based on its review of the competitive analysis of job-specific market data prepared by Pay Governance as well as the officer’s role, individual performance and internal equity considerations. For the Named Executive Officers who are members of the Office of the Chief Executive (Messrs. Bakken, Brown, Denault, Marsh and West), target award opportunities are established based on these factors. For the other Named Executive Officers, target award opportunities are determined based on their management level within the Entergy organization. Executive management levels at Entergy Corporation range from ML level 1 through ML level 4 (the “ML 1-4 Officers”). At December 31, 2019, Mr. May held a Level 3 position, and Mr. Ellis, Mr. Fisackerly, Ms. Landreaux and Ms. Rainer held Level 4 positions. Accordingly, their respective incentive award opportunities differ from one another based on either their management level or the external market data developed by the Committee’s independent compensation consultant. The 2019 target opportunities were increased for Mr. Denault, Mr. Marsh and Mr. Brown to align more closely with market data. The target levels for the other Named Executive Officers are comparable to the levels set for 2018.

•

Determine the EAM. After the end of the fiscal year, the Finance and Personnel Committees jointly review Entergy Corporation’s financial results and the Personnel Committee determines the EAM, which represents the level of success in achieving the performance objectives established by the committee and determines the maximum funding level of the annual incentive plan, as a percentage of the total target opportunity.

•	Determine Annual Incentive Awards. To determine individual executive officer awards under the annual incentive plan, the Personnel Committee considers not only each executive’s role in executing on Entergy Corporation’s strategies and delivering the financial performance achieved, but also the individual’s accountability for any challenges the Company experienced during the year.

•	They are based on objective financial measures that Entergy Corporation and its investors consider to be important in evaluating its financial performance;

•	They are based on the same metrics we use for internal and external financial reporting; and

•	They provide both discipline and transparency.

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(1)	Payouts for performance between minimum and target achievement levels and between target and maximum achievement levels are calculated using straight-line interpolation. There is no payout for performance below the minimum achievement level.

(2)	ETR Tax Adjusted Earnings Per Share is a different measure than the consolidated operational earnings per share, and ETR Adjusted Operating Cash Flow is a different measure than the consolidated operational operating cash flow used to determine the 2018 annual incentive awards. As a result, the goals and results are not comparable year over year.

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•	Each performance unit represents one share of Entergy Corporation’s common stock at the end of the three-year performance period, plus dividends accrued during the performance period.

•	The performance units and accrued dividends on any shares earned during the performance period are settled in shares of Entergy Corporation common stock.

•	The Personnel Committee sets payout opportunities for the program at the outset of each performance period, with payouts only occurring if the performance goals are met.

•	Payouts under this program will not be made for the 2019-2021 performance period if total shareholder return falls within the lowest quartile of the peer companies in the Philadelphia Utility Index and Cumulative Entergy Adjusted EPS is below the minimum performance goal.

•	All shares paid out under the Long-Term Performance Unit Program are required to be retained by Entergy Corporation’s officers until applicable executive stock ownership requirements are met.

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(1)	Payouts for performance between achievement levels are calculated using straight-line interpolation, with no payouts for performance below the minimum achievement level for both performance measures.

•

The Personnel Committee chose relative total shareholder return as a performance measure because it reflects Entergy Corporation’s creation of shareholder value relative to other electric utilities included in the Philadelphia Utility Index over the performance period. By measuring performance in relation to an industry benchmark, this measure is intended to isolate and reward management for the creation of shareholder value that is not driven by events that affect the industry as a whole.

•

Minimum, target and maximum performance levels are determined by reference to the ranking of Entergy Corporation’s total shareholder return in relation to the TSR of the companies in the Philadelphia Utility Index. The Personnel Committee identified the Philadelphia Utility Index as the appropriate industry peer group for determining relative total shareholder return because the companies included in this index, in the aggregate, are deemed to be comparable to the Company in terms of business and scale.

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Cumulative ETR Adjusted EPS, which adjusts Entergy Corporation’s as reported (GAAP) results to eliminate the impact of earnings or loss from Entergy Wholesale Commodities and other non-routine items, was selected in 2019 as a performance measure because the Personnel Committee wished to incentivize management to achieve steady, predictable earnings growth for the Company over the 3 year performance period, and because it aligns with the earnings measure used to communicate the Company’s earnings expectations externally to investors.

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In a manner similar to the way targets are established for the annual incentives, targets for the Cumulative ETR Adjusted EPS performance measure were established by the Personnel Committee after the Entergy Corporation Board’s review of Entergy’s financial plan for the three-year period beginning in 2019 and are consistent with the earnings expectations for the Company that are communicated to investors. These targets also incorporate the Pre-Determined Exclusions discussed previously with respect to the annual incentive measures.

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(1)	Payouts for performance between achievement levels are calculated using straight-line interpolation, with no payouts for performance below the minimum achievement level.

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(1)	Includes accrued dividends.

(2)	Value determined based on the closing price of Entergy Corporation common stock on January 17, 2020 ($126.31), the date the Personnel Committee certified the 2017-2019 performance period results.

(3)	Represents the aggregate grant date fair value calculated in accordance with applicable accounting rules as reflected in the 2017 Summary Compensation Table.

(4)	As a new hire in 2018, Mr. Ellis received a pro-rata target award opportunity for the 2017-2019 performance period.

(5)	As a new officer in 2018, Ms. Landreaux received a pro-rata target award opportunity for the 2017-2019 performance period.

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(i) the payment was predicated upon the achievement of certain financial results with respect to the applicable performance period that were subsequently determined to be the subject of a material restatement other than a restatement due to changes in accounting policy; or (ii) a material miscalculation of a performance award occurs, whether or not the financial statements were restated and, in either such case, a lower payment would have been made to the executive officer based upon the restated financial results or correct calculation; or

•	in the Board of Directors’ view, the executive officer engaged in fraud that caused or partially caused the need for a restatement or caused a material miscalculation of a performance award, in each case, whether or not the financial statements were restated.

•	all net after-tax shares paid out under the Long-Term Performance Unit Program;

•	all net after-tax shares of the restricted stock and restricted stock units received upon vesting; and

•	at least 75% of the after-tax net shares received upon the exercise of Entergy Corporation stock options.

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(1)	Mr. Ellis was named Chief Executive Officer, Entergy New Orleans in December 2018, and Ms. Landreaux was named Chief Executive Officer, Entergy Arkansas in July 2018.

(2)	The amounts in column (c) represent the actual base salary paid to the Named Executive Officers in the applicable year.  The 2019 changes in base salaries noted in the Compensation Discussion and Analysis were effective in April 2019.

(3)	The amount in column (d) in 2019, 2018 and 2017 for Mr. Bakken represents the cash bonus paid to him pursuant to the Nuclear Retention Plan. See “Nuclear Retention Plan” in Compensation Discussion and Analysis. The amount in column (d) in 2018 for Mr. Ellis represents a cash sign-on bonus paid in connection with his commencement of employment with Entergy New Orleans.

(4)

The amounts in column (e) represent the aggregate grant date fair value of restricted stock and performance units granted under the 2015 Equity Plan, each calculated in accordance with FASB ASC Topic 718, without taking into account estimated forfeitures.  The grant date fair value of the restricted stock is based on the closing price of Entergy Corporation common stock on the date of grant.  The grant date fair value of the portion of the performance units with vesting based on the total shareholder return was measured using a Monte Carlo simulation valuation model.  The simulation model applies a risk-free interest rate and an expected volatility assumption.  The risk-free interest rate is assumed to equal the yield on a three-year treasury bond on the grant date.  Volatility is based on historical volatility for the 36-month period preceding the grant date.  The performance units in the table are also valued based on the probable outcome of the applicable performance condition at the time of grant. The maximum value of shares that will be received if the highest achievement level is attained with respect to both the total shareholder return and Cumulative ETR Adjusted EPS, for performance units granted in 2019 are as follows:  Mr. Bakken, $1,953,212; Mr. Brown, $1,915,446; Mr. Denault, $8,269,303; Mr. Ellis, $296,003; Mr.

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(5)	The amounts in column (f) represent the aggregate grant date fair value of stock options granted under the 2015 Equity Plan calculated in accordance with FASB ASC Topic 718.  For a discussion of the relevant assumptions used in valuing these awards, see Note 12 to the financial statements.

(6)	The amounts in column (g) represent cash payments made under the Annual Incentive Plan.

(7)

For all Named Executive Officers, the amounts in column (h) include the annual actuarial increase in the present value of these Named Executive Officers’ benefits under all pension plans established by Entergy Corporation using interest rate and mortality rate assumptions consistent with those used in Entergy Corporation’s financial statements and include amounts which the Named Executive Officers may not currently be entitled to receive because such amounts are not vested (see “2019 Pension Benefits”). The increase in pension benefits for all of the Named Executive Officers in 2019 was driven by a decline in the discount rate that was a result of the decrease in prevailing interest rates. None of the increases for any of the Named Executive Officers is attributable to above-market or preferential earnings on non-qualified deferred compensation. For 2018, the aggregate change in the actuarial present value was a decrease of pension benefits of $52,000 for Mr. Fisackerly, $163,000 for Mr. Marsh, $700 for Mr. May, $110,700 for Ms. Rainer, and $149,300 for Mr. West.

(8)

The amounts in column (i) for 2019 include (a) matching contributions by Entergy Corporation under the Savings Plan to each of the Named Executive Officers; (b) dividends paid on restricted stock when vested; (c) life insurance premiums; (d) tax gross up payments on club dues and relocation expenses; and (e) perquisites and other compensation as described further below.  The amounts are listed in the following table:

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(1)	The amounts in columns (c), (d), and (e) represent minimum, target, and maximum payment levels under the Annual Incentive Plan.  The actual amounts awarded are reported in column (g) of the Summary Compensation Table.

(2)

The amounts in columns (f), (g), and (h) represent the minimum, target, and maximum payment levels under the Long-Term Performance Unit Program.  Performance under the program is measured by Entergy Corporation’s total shareholder return relative to the total shareholder returns of the companies included in the Philadelphia Utility Index and Cumulative Entergy Adjusted EPS with total shareholder return weighted eighty percent and Cumulative Entergy Adjusted EPS weighted twenty percent. There is no payout under the program if Entergy Corporation’s total shareholder return falls within the lowest quartile of the peer companies in the Philadelphia Utility Index and Cumulative Entergy Adjusted EPS is below the minimum performance goal. Subject to the achievement of performance targets, each unit will be converted into one share of Entergy Corporation’s common stock on the last day of the performance period (December 31, 2021.)  Accrued dividends on the shares earned will also be paid in Entergy Corporation common stock.

(3)	The amounts in column (i) represent shares of restricted stock granted under the 2015 Equity Plan.  Shares of restricted stock vest one-third on each of the first through third anniversaries of the grant date, have voting rights, and accrue dividends during the vesting period.

(4)	The amounts in column (j) represent options to purchase shares of Entergy Corporation’s common stock.  The options vest one-third on each of the first through third anniversaries of the grant date and have a ten-year term from the date of grant. The options were granted under the 2015 Equity Plan.

(5)

The amounts in column (l) are valued based on the aggregate grant date fair value of the award calculated in accordance with FASB ASC Topic 718 and, in the case of the performance units, are based on the probable outcome of the applicable performance conditions.  See Notes 4 and 5 to the 2019 Summary Compensation Table for a discussion of the relevant assumptions used in calculating the grant date fair value.

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(1)	Consists of options granted under the 2015 Equity Plan that vested or will vest as follows: 1/3 of the options granted vest on each of January 31, 2020, January 31, 2021 and January 31, 2022.

(2)	Consists of options granted under the 2015 Equity Plan that vested or will vest as follows: 1/2 of the remaining unexercisable options vest on each of January 25, 2020 and January 25, 2021.

(3)	Consists of options granted under the 2015 Equity Plan that vested on January 26, 2020.

(4)

Consists of performance units granted under the 2015 Equity Plan that will vest on December 31, 2021 based on two performance measures: 1) Entergy Corporation’s total shareholder return performance over the 2019-2021 performance period and 2) Cumulative Entergy Adjusted EPS with total shareholder return weighted eighty percent and Cumulative Entergy Adjusted EPS weighted twenty percent, as described under “What Entergy Corporation Pays and Why - Principal Executive Compensation Elements - Variable Compensation - Long-Term Incentive Compensation - Performance Unit Program” in the Compensation Discussion and Analysis.

(5)	Consists of performance units granted under the 2015 Equity Plan that will vest on December 31, 2020 based on two performance measures: 1) Entergy Corporation’s total shareholder return performance over the 2018-2020 performance period and 2) Cumulative Utility, Parent and Other Adjusted EPS with each performance measure weighted equally.

(6)	Consists of shares of restricted stock granted under the 2015 Equity Plan that vested or will vest as follows:  1/3 of the shares of restricted stock granted vest on each of January 31, 2020, January 31, 2021, and January 31, 2022.

(7)	Consists of shares of restricted stock granted under the 2015 Equity Plan that vested or will vest as follows:  1/2 of the shares of restricted stock granted vest on each of January 25, 2020 and January 25, 2021.

(8)	Consists of shares of restricted stock granted under the 2015 Equity Plan that vested on January 26, 2020.

(9)	Consists of restricted stock units granted under the 2015 Equity Plan which will vest on August 3, 2020.

(10)	Consists of restricted stock units granted under the 2015 Equity Plan which will vest 1/2 on each of April 6, 2022 and April 6, 2025.

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(1)	Represents the value of performance units for the 2017-2019 performance period (payable solely in shares based on the closing stock price of Entergy Corporation on the date of vesting) under the Performance Unit Program and the vesting of shares of restricted stock in 2019.

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(1)	As of December 31, 2019, Mr. Brown, Mr. Denault, Mr. May, and Ms. Rainer were retirement eligible.

(2)

In 2006, Mr. Denault entered into a retention agreement granting him an additional 15 years of service and permission to retire under the non-qualified System Executive Retirement Plan in the event his employment is terminated by his Entergy employer other than for cause (as defined in the retention agreement), by Mr. Denault for good reason (as defined in the retention agreement), or on account of his death or disability. His retention agreement also provides that if he terminates employment for any other reason, he shall be entitled to the additional 15 years of service under the non-qualified System Executive Retirement Plan only if his Entergy employer grants him permission to retire. The additional 15 years of service increases the present value of his benefit by $3,887,900.

(3)	Service under the non-qualified System Executive Retirement Plan is granted from the date of hire. Service under the qualified Entergy Retirement Plan is granted from the later of the date of hire or the plan participation date.

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(1)

Effective July 1, 2014, (a) no new grants of supplemental service may be provided to participants in the Pension Equalization Plan; (b) supplemental credited service granted prior to July 1, 2014 was grandfathered; and (c) participants in Entergy Corporation’s Cash Balance Plan are not eligible to participate in the Pension Equalization Plan and instead may be eligible to participate in the Cash Balance Equalization Plan.

(2)

Benefits accrued under the System Executive Retirement Plan, Pension Equalization Plan, and Cash Balance Equalization Plan, if any, will become fully vested if a participant is involuntarily terminated without cause or terminates his or her employment for good reason in connection with a change in control with payment generally made in a lump-sum payment as soon as reasonably practicable following the first day of the month after the termination of employment, unless delayed 6 months under Internal Revenue Code Section 409A.

(3)	The System Executive Retirement Plan was closed to new executive officers effective July 1, 2014.

(1)	Amounts in this column are not included in the Summary Compensation Table.

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*

Cash severance payments are capped at 2.99 times the sum of (a) an executive’s annual base salary plus (b) the higher of his or her actual annual incentive payment under the Annual Incentive Plan or his or her annual incentive, calculated using the average annual target opportunity derived under the Annual Incentive Plan for the two calendar years immediately preceding the calendar year in which termination occurs. Any cash severance payments to be paid under the Continuity Plan in excess of this cap will be forfeited by the participant.

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Change in Control: (a) the purchase of 30% or more of either Entergy Corporation’s common stock or the combined voting power of Entergy Corporation’s voting securities; (b) the merger or consolidation of Entergy Corporation (unless its Board members constitute at least a majority of the board members of the surviving entity); (c) the liquidation, dissolution or sale of all or substantially all of Entergy Corporation’s assets; or (d) a change in the composition of Entergy Corporation’s Board such that, during any two-year period, the individuals serving at the beginning of the period no longer constitute a majority of Entergy Corporation’s Board at the end of the period.

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Potential Change in Control: (a) Entergy Corporation or an affiliate enters into an agreement the consummation of which would constitute a Change in Control; (b) the Entergy Corporation Board adopts resolutions determining that, for purposes of the Continuity Plan, a potential Change in Control has occurred; (c) a System Company or other person or entity publicly announces an intention to take actions that would constitute a Change in Control; or (d) any person or entity becomes the beneficial owner (directly or indirectly) of Entergy Corporation’s outstanding shares of common stock constituting 20% or more of the voting power or value of the Entergy Corporation’s outstanding common stock.

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Cause: The participant’s (a) willful and continuous failure to perform substantially his or her duties after written demand for performance; (b) engagement in conduct that is materially injurious to Entergy Corporation or any of its subsidiaries; (c) conviction or guilty or nolo contendere plea to a felony or other crime that materially and adversely affects either his or her ability to perform his or her duties or Entergy Corporation’s reputation; (d) material violation of any agreement with Entergy Corporation or any of its subsidiaries; or (e) disclosure of any of Entergy Corporation’s confidential information without authorization.

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Good Reason: The participant’s (a) nature or status of duties and responsibilities is substantially altered or reduced; (b) salary is reduced by 5% or more; (c) primary work location is relocated outside the continental United States; (d) compensation plans are discontinued without an equitable replacement; (e) benefits or number of vacation days are substantially reduced; or (f) employment is terminated by an Entergy employer for reasons other than in accordance with the Continuity Plan.

*	If an officer resigns after the completion of an annual incentive plan, he or she may receive, at the Company’s discretion, an annual incentive payment.

**	If an officer resigns after the completion of a Long-Term Performance Unit Program performance period, he or she may receive a payout under the Long-Term Performance Unit Program based on the outcome of the performance period.

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1)	See “2019 Pension Benefits” for a description of the pension benefits Mr. Bakken, Mr. Ellis, Mr. Fisackerly, Ms. Landreaux, Mr. Marsh, and Mr. West may receive upon the occurrence of certain termination events.

2)

As of December 31, 2019, Mr. Brown, Mr. Denault, Mr. May, and Ms. Rainer are retirement eligible and would retire rather than voluntarily resign, and in addition to the payments and benefits in the table, Mr. Brown, Mr. Denault, Mr. May, and Ms. Rainer also would be entitled to receive their vested pension benefits under the Entergy Retirement Plan. For a description of these benefits, see “2019 Pension Benefits.”

3)

For purposes of the table, the value of Mr. Denault’s payments was calculated by multiplying the target performance units for the 2016-2018 Performance Unit Program (41,700) by the closing price of Entergy stock on December 31, 2019 ($119.80), which would equal a payment of $4,995,660 for the forfeited performance units for each performance period. The value of Mr. Bakken’s, Mr. Brown’s, Mr. Marsh’s, and Mr. West’s payments was calculated by multiplying the target performance units for the 2016-2018 Performance Unit Program (8,200) by the closing price of Entergy stock on December 31, 2019 ($119.80), which would equal a payment of $982,360 for the forfeited performance units for each performance period. The value of Mr. May’s payment was calculated by multiplying the target performance units for the 2016-2018 Performance Unit Program (2,700) by the closing price of Entergy stock on December 31, 2019 ($119.80), which would equal a payment of $323,460 for the forfeited performance units for each performance period. The value of the payments for the other Named Executives Officers was calculated by multiplying the target performance units for the 2016-2018 Performance Unit Program (1,800) by

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4)

For purposes of the table, the value of Mr. Denault’s retention payment was calculated by taking an average of the target performance units from the 2015-2017 Performance Unit Program (33,100) and from the 2016-2018 Performance Unit Program (41,700). This average number of units (37,400) multiplied by the closing price of Entergy stock on December 31, 2019 ($119.80) would equal a payment of $4,480,520.

5)	Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. Bakken, Mr. Marsh, and Mr. West would be eligible to receive Entergy-subsidized COBRA benefits for 18 months and Mr. Ellis, Mr. Fisackerly, and Ms. Landreaux would be eligible to receive Entergy-subsidized COBRA benefits for 12 months.

6)	Upon retirement, Mr. Brown, Mr. Denault, Mr. May, and Ms. Rainer would be eligible for retiree medical and dental benefits, the same as all other retirees.

7)

Mr. Bakken’s 20,000 restricted stock units vest in two equal installments on April 6, 2022 and April 6, 2025. In the event of a change in control, the unvested restricted stock units will fully vest upon Mr. Bakken’s Qualifying Termination during a change in control period. Pursuant to his restricted stock unit agreement, Mr. Bakken is subject to certain restrictions on his ability to compete with Entergy and its affiliates or solicit its employees or customers during and for 12 months after his employment with his Entergy employer. In addition, the restricted stock unit agreement limits Mr. Bakken’s ability to disparage Entergy and its affiliates. In the event of a breach of these restrictions, other than following certain constructive terminations of his employment, Mr. Bakken will forfeit any restricted stock units that are not yet vested and paid, and must repay to Entergy any shares of Entergy stock paid to him in respect of the restricted stock units and any amounts he received upon the sale or transfer of any such shares.

8)

Mr. Marsh’s 21,100 restricted stock units vest 100% in 2020. Pursuant to his restricted stock unit agreement, any unvested restricted stock units will vest immediately in the event of his termination of employment due to Mr. Marsh’s total disability or death or a Qualifying Termination during a change in control period. Pursuant to his restricted stock unit agreement, Mr. Marsh is subject to certain restrictions on his ability to compete with Entergy and its affiliates during and for 12 months after his employment with Entergy, or to solicit its employees or customers during and for 24 months after his employment with Entergy. In addition, the restricted stock unit agreement limits Mr. Marsh’s ability to disparage Entergy and its affiliates. In the event of a breach of these restrictions, Mr. Marsh will forfeit any restricted stock units that are not yet vested and paid, and must repay to Entergy any shares of Entergy stock paid to him in respect of the restricted stock units and any amounts he received upon the sale or transfer of any such shares.

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•	The median of the annual total compensation of all of Entergy Arkansas’s employees, other than Ms. Landreaux, was $230,966.

•	Ms. Landreaux’s annual total compensation, as reported in the Total column of the 2019 Summary Compensation Table was $1,064,459.

•	Based on this information, the ratio of the annual total compensation of Mrs. Landreaux to the median of the annual total compensation of all employees is estimated to be 5:1.

•	The median of the annual total compensation of all of Entergy Louisiana’s employees, other than Mr. May, was $173,745.

•	Mr. May’s annual total compensation, as reported in the Total column of the 2019 Summary Compensation Table, was $2,073,894.

•	Based on this information, the ratio of the annual total compensation of Mr. May to the median of the annual total compensation of all employees is estimated to be 12:1.

•	The median of the annual total compensation of all of Entergy Mississippi’s employees, other than Mr. Fisackerly, was $254,843.

•	Mr. Fisackerly’s annual total compensation, as reported in the Total column of the 2019 Summary Compensation Table, was $1,579,844.

•	Based on this information, the ratio of the annual total compensation of Mr. Fisackerly to the median of the annual total compensation of all employees is estimated to be 6:1.

•	The median of the annual total compensation of all of Entergy New Orleans’s employees, other than Mr. Ellis, was $145,217.

•	Mr. Ellis’s annual total compensation, as reported in the Total column of the 2019 Summary Compensation Table was $732,040.

•	Based on this information, the ratio of the annual total compensation of Mr. Ellis to the median of the annual total compensation of all employees is estimated to be 5:1.

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•	The median of the annual total compensation of all of Entergy Texas’s employees, other than Ms. Rainer, was $233,988.

•	Ms. Rainer’s annual total compensation, as reported in the Total column of the 2019 Summary Compensation Table, was $1,467,716.

•	Based on this information, the ratio of the annual total compensation of Ms. Rainer to the median of the annual total compensation of all employees is estimated to be 6:1.

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(1)	The number of shares of Entergy Corporation common stock owned by each individual and by all non-employee directors and executive officers as a group does not exceed one percent of the outstanding shares of Entergy Corporation common stock.

(2)

For the non-employee directors, the balances include phantom units that are issued under the Service Recognition Program. All non-employee directors are credited with phantom units for each year of service on the Entergy Corporation Board. These phantom units do not have voting rights or accrue dividends, and will be settled in shares of Entergy Corporation common stock following the non-employee director’s separation from the Board.

(3)

Represents the balances of phantom units each executive holds under the defined contribution restoration plan and the deferral provisions of Entergy Corporation’s equity ownership plans.  These units will be paid out in either Entergy Corporation Common Stock or cash equivalent to the value of one share of Entergy Corporation common stock per unit on the date of payout, including accrued dividends.  The deferral period is determined by the individual and is at least two years from the award of the bonus.  Messrs. Donald and Frederickson have deferred receipt of some of their quarterly stock grants.  The deferred shares will be settled in cash in an amount equal to the market value of Entergy Corporation common stock at the end of the deferral period.

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(1)

Includes the 2007 Equity Ownership Plan, the 2011 Equity Ownership Plan, the 2015 Equity Plan, and the 2019 Omnibus Incentive Plan.  The 2007 Equity Ownership Plan was approved by Entergy Corporation shareholders on May 12, 2006, and only applied to awards granted between January 1, 2007 and May 5, 2011. The 2011 Equity Ownership Plan was approved by Entergy Corporation shareholders on May 6, 2011, and only applied to awards granted between May 6, 2011 and May 7, 2015.  The 2015 Equity Plan was approved by Entergy Corporation shareholders on May 8, 2015, and only applied to awards granted between May 8, 2015 and May 3, 2019. The 2019 Omnibus Incentive Plan was approved by the Entergy Corporation shareholders on May 3, 2019, and 7,300,000 shares of Entergy Corporation common stock can be issued from the 2019 Omnibus Incentive Plan, with all shares available for equity-based incentive awards. The 2007 Equity Ownership Plan, the 2011 Equity Ownership Plan, the 2015 Equity Plan, and the 2019 Omnibus Incentive Plan (collectively, the “Plans”) are administered by the Personnel Committee of the Board of Directors (other than with respect to awards granted to non-employee directors, which awards are administered by the entire Board of Directors).  Eligibility under the Plans is limited to the non-employee directors and to the officers and employees of an Entergy employer or an affiliate of Entergy Corporation.  The Plans provide for the issuance of stock options, restricted stock, equity awards (units whose value is related to the value of shares of the common stock but do not represent actual shares of common stock), performance awards (performance shares or units valued by reference to shares of common stock or performance units valued by reference to financial measures or property other than common stock), restricted stock unit awards, and other stock-based awards.

(2)	The weighted average exercise price reported in this column does not include outstanding performance awards.

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•	To any transaction or series of transactions in which Entergy Corporation or a subsidiary is a participant;

•	When the amount involved exceeds $120,000; and

•	When a Related Party (an Entergy Corporation director or executive officer, any nominee for director, any shareholder owning an excess of 5% of the total equity of Entergy Corporation and any immediate family member of any such person) has a direct or indirect material interest (other than solely as a result of being a director or a less than 10% beneficial owner of another entity).

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(a)	Includes fees for employee benefit plan audits, consultation on financial accounting and reporting, and other attestation services.

(b)	100% of fees paid in 2019 and 2018 were pre-approved by the Entergy Corporation Audit Committee.

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1.	The independent auditor will provide the Audit Committee, for approval, an annual engagement letter outlining the scope of services proposed to be performed during the fiscal year, including audit services and other permissible non-audit services (e.g. audit-related services, tax services, and all other services).

2.

For other permissible services not included in the engagement letter, Entergy management will submit a description of the proposed service, including a budget estimate, to the Audit Committee for pre-approval.  Management and the independent auditor must agree that the requested service is consistent with the SEC’s rules on auditor independence prior to submission to the Audit Committee.  The Audit Committee, at its discretion, will pre-approve permissible services and has established the following additional guidelines for permissible non-audit services provided by the independent auditor:

•	Aggregate non-audit service fees are targeted at fifty percent or less of the approved audit service fee.

•	All other services should only be provided by the independent auditor if it is a highly qualified provider of that service or if the Audit Committee pre-approves the independent audit firm to provide the service.

3.	The Audit Committee will be informed quarterly as to the status of pre-approved services actually provided by the independent auditor.

4.	To ensure prompt handling of unexpected matters, the Audit Committee delegates to the Audit Committee Chair or its designee the authority to approve permissible services and fees.  The Audit Committee Chair or designee will report action taken to the Audit Committee at the next scheduled Audit Committee meeting.

5.	The Vice President and General Auditor will be responsible for tracking all independent auditor fees and will report quarterly to the Audit Committee.

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ENTERGY CORPORATION AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2019, 2018, and 2017
(In Thousands)
Column A		Column B				Column C				Column D				Column E
										Other
		Balance at				Additions				Changes				Balance
Description		Beginning of Period				Charged to Income				Deductions (1)				at End of Period
Allowance for doubtful accounts
2019			$7,322				$2,806				$2,724				$7,404
2018			$13,587				$3,936				$10,201				$7,322
2017			$11,924				$4,211				$2,548				$13,587
Notes:
(1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off.

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ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2019, 2018, and 2017
(In Thousands)
Column A		Column B				Column C				Column D				Column E
										Other
		Balance at				Additions				Changes				Balance
Description		Beginning of Period				Charged to Income				Deductions (1)				at End of Period
Allowance for doubtful accounts
2019			$1,264				$1,000				$1,095				$1,169
2018			$1,063				$810				$609				$1,264
2017			$1,211				$503				$651				$1,063
Notes:
(1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off.

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ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2019, 2018, and 2017
(In Thousands)
Column A		Column B				Column C				Column D				Column E
										Other
		Balance at				Additions				Changes				Balance
Description		Beginning of Period				Charged to Income				Deductions (1)				at End of Period
Allowance for doubtful accounts
2019			$1,813				$762				$673				$1,902
2018			$8,430				$2,395				$9,012				$1,813
2017			$6,277				$3,108				$955				$8,430
Notes:
(1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off.

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ENTERGY MISSISSIPPI, LLC
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2019, 2018, and 2017
(In Thousands)
Column A		Column B				Column C				Column D				Column E
										Other
		Balance at				Additions				Changes				Balance
Description		Beginning of Period				Charged to Income				Deductions (1)				at End of Period
Allowance for doubtful accounts
2019			$563				$406				$333				$636
2018			$574				$265				$276				$563
2017			$549				$255				$230				$574
Notes:
(1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off.

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ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2019, 2018, and 2017
(In Thousands)
Column A		Column B				Column C				Column D				Column E
										Other
		Balance at				Additions				Changes				Balance
Description		Beginning of Period				Charged to Income				Deductions (1)				at End of Period
Allowance for doubtful accounts
2019			$3,222				$316				$312				$3,226
2018			$3,057				$187				$22				$3,222
2017			$3,059				$152				$154				$3,057
Notes:
(1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off.

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ENTERGY TEXAS, INC. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2019, 2018, and 2017
(In Thousands)
Column A		Column B				Column C				Column D				Column E
										Other
		Balance at				Additions				Changes				Balance
Description		Beginning of Period				Charged to Income				Deductions (1)				at End of Period
Allowance for doubtful accounts
2019			$461				$321				$311				$471
2018			$463				$279				$281				$461
2017			$828				$192				$557				$463
Notes:
(1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off.