The Utility operating companies have long-term firm and short-term interruptible gas contracts for both supply and transportation. Over 50% of the Utility operating companies’ power plants maintain some level of long-term firm transportation. Short-term contracts and spot-market purchases satisfy additional gas requirements.
Many factors, including wellhead deliverability, storage, pipeline capacity, and demand requirements of end users, influence the availability and price of natural gas supplies for power plants. Demand is primarily tied to weather conditions as well as to the prices and availability of other energy sources. Pursuant to federal and state regulations, gas supplies to power plants may be interrupted during periods of shortage. To the extent natural gas supplies are disrupted or natural gas prices significantly increase, the Utility operating companies may in some instances use alternate fuels, such as oil when available, or rely to a larger extent on coal, nuclear generation, and purchased power.
The operator of Big Cajun 2 - Unit 3, Louisiana Generating, LLC, has advised Entergy Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2020.2023, but is also currently experiencing delivery constraints. Entergy Louisiana’s and Entergy Texas’s coal nomination requests to Big Cajun 2 - Unit 3 are made on an annual basis.
The Registrant Subsidiaries that own nuclear plants, Entergy Arkansas, Entergy Louisiana, and System Energy, are responsible through a shared regulated uranium pool for contracts to acquire nuclear material to be used in fueling Entergy’s Utility nuclear units. These companies own the materials and services in this shared regulated
uranium pool on a pro rata fractional basis determined by the nuclear generation capability of each company. Any liabilities for obligations of the pooled contracts are on a several but not joint basis. The shared regulated uranium pool maintains inventories of nuclear materials during the various stages of processing. The Registrant Subsidiaries purchase enriched uranium hexafluoride for their nuclear plant reload requirements at the average inventory cost from the shared regulated uranium pool. Entergy Operations, Inc. contracts separately for the fabrication of nuclear fuel as agent on behalf of each of the Registrant Subsidiaries that owns a nuclear plant. All contracts for the disposal of spent nuclear fuel are between the DOE and the owner of a nuclear power plant.
Based upon currently planned fuel cycles, the Utility nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable or fixed prices through most of 2023.2027. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners.miners, including their ability to work through supply disruptions caused by global events, such as the COVID-19 pandemic, or national events, such as political disruption. There are a number of possible supply alternatives that may be accessed to mitigate any supplier performance failure, including potentially drawing upon Entergy’s inventory intended for later generation periods depending upon its risk management strategy at that time, although the pricing of any alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. In addition, some nuclear fuel contracts are on a non-fixed price basis subject to prevailing prices at the time of delivery.
The effects of market price changes may be reduced and deferred by risk management strategies, such as negotiation of floor and ceiling amounts for long-term contracts, buying for inventory or entering into forward physical contracts at fixed prices when Entergy believes it is appropriate and useful. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S.
Entergy’s ability to assure nuclear fuel supply also depends upon the performance reliability of conversion, enrichment, and fabrication services providers. There are fewer of these providers than for uranium. For conversion and enrichment services, like uranium, Entergy diversifies its supply by supplier and country and may take special measures as needed to ensure supply of enriched uranium for the reliable fabrication of nuclear fuel. For fabrication services, each plant is dependent upon the effective performance of the fabricator of that plant’s nuclear fuel, therefore, Entergy provides additional monitoring, inspection, and oversight for the fabrication process to assure reliability and quality.
Entergy Arkansas, Entergy Louisiana, and System Energy each have made arrangements to lease nuclear fuel and related equipment and services. The lessors, which are consolidated in the financial statements of Entergy and the applicable Registrant Subsidiary, finance the acquisition and ownership of nuclear fuel through credit agreements and the issuance of notes. These credit facilities are subject to periodic renewal, and the notes are issued periodically, typically for terms between three and seven years.
Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with one interstate and three intrastate pipelines. Entergy New Orleans has a “no-notice” service gas purchase contract with CenterPointSymmetry Energy ServicesSolutions which guarantees Entergy New Orleans gas delivery at specific delivery points and at any volume within the minimum and maximum set forth in the contract amounts. The CenterPointSymmetry Energy ServiceSolutions gas supply is
transported to Entergy New Orleans pursuant to a transportation service agreement with Gulf South Pipeline Co. This service is subject to FERC-approved rates. Entergy New Orleans also makes interruptible spot market purchases.
As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy Louisiana’s or Entergy New Orleans’s suppliers failed to perform their obligations to deliver gas under their supply agreements. Gulf South Pipeline Co. could curtail transportation capacity only in the event of pipeline system constraints.
State or local regulatory authorities, as described above, regulate the retail rates of the Utility operating companies. The FERC regulates wholesale sales of electricity rates and interstate transmission of electricity, including System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. See Note 2 to the financial statements for further discussion of federal regulation proceedings.
In December 2013 the Utility operating companies integrated into the MISO RTO. Although becoming a member of MISO did not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities, MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. MISO also exercises functional control of transmission
planning and congestion management and provides schedules and pricing for the commitment and dispatch of generation that is offered into MISO’s markets, as well as pricing for load that bids into the markets. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their generating facilities into the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. Each Utility operating company has its own transmission pricing zone and a formula rate template (included as Attachment O to the MISO tariff) used to establish transmission rates within MISO. The terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets and the allocation of transmission upgrade costs, are subject to regulation by the FERC.
System Energy recovers costs related to its interest in Grand Gulf through rates charged to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans for capacity and energy under the Unit Power Sales Agreement (described below). In July 2001 a rate proceeding commenced by System Energy at the FERC in 1995 became final, with the FERC approving a prospective 10.94% return on equity. In 1998 the FERC approved requests by Entergy Arkansas and Entergy Mississippi to accelerate a portion of their Grand Gulf purchased power obligations. Entergy Arkansas’s and Entergy Mississippi’s acceleration of Grand Gulf purchased power obligations ceased effective July 2001 and July 2003, respectively, as approved by the FERC. See Note 2 to the financial statements for discussion of complaints filed withproceedings at the FERC regardingrelated to System Energy’s return on equity.Energy.
The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System Energy’s ownership and leasehold interests in Grand Gulf to Entergy Arkansas (36%), Entergy Louisiana (14%), Entergy Mississippi (33%), and Entergy New Orleans (17%). Each of these companies is obligated to make payments to System Energy for its entitlement of capacity and energy on a full cost-of-service basis regardless of the quantity of energy delivered. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenue. The financial condition of System Energy depends upon the continued commercial operation of Grand Gulf and the receipt of such payments. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans generally recover payments made under the Unit Power Sales Agreement through rates charged to their customers.
In the case of Entergy Arkansas and Entergy Louisiana, payments are also recovered through sales of electricity from their respective retained shares of Grand Gulf. Under a settlement agreement entered into with the APSC in 1985 and amended in 1988, Entergy Arkansas retains 22% of its 36% share of Grand Gulf-related costs and recovers the remaining 78% of its share in rates. In the event that Entergy Arkansas is not able to sell its retained share to third parties, it may sell such energy to its retail customers at a price equal to its avoided cost, which is currently less than Entergy Arkansas’s cost from its retained share. Entergy Arkansas has life-of-resources purchased power agreements with Entergy Louisiana and Entergy New Orleans that sell a portion of the output of Entergy Arkansas’s retained share of Grand Gulf to those companies, with the remainder of the retained share being sold to Entergy Mississippi through a separate life-of-resources purchased power agreement. In a series of LPSC orders, court decisions, and agreements from late 1985 to mid-1988, Entergy Louisiana was granted rate reliefcost recovery with respect to costs associated with Entergy Louisiana’s share of capacity and energy from Grand Gulf, subject to certain terms and conditions. Entergy Louisiana retains and does not recover from retail ratepayers 18% of its 14% share of the costs of Grand Gulf capacity and energy and recovers the remaining 82% of its share in rates. Entergy Louisiana is allowed to recover through the fuel adjustment clause at 4.6 cents per kWh for the energy related to its retained portion of these costs. Alternatively, Entergy Louisiana may sell such energy to non-affiliated parties at prices above the fuel adjustment clause recovery amount, subject to the LPSC’s approval. Entergy Arkansas also has a life-of-resources purchased power agreement with Entergy Mississippi to sell a portion of the output of Entergy Arkansas’s non-retained share of Grand Gulf. Entergy Mississippi was granted rate reliefcost recovery for those purchases by the MPSC through its annual unit power cost rate mechanism.
The Availability Agreement among System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans was entered into in 1974 in connection with the original financing by System Energy of Grand Gulf. The Availability Agreement provides that System Energy make available to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans all capacity and energy available from System Energy’s share of Grand Gulf.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans also agreed severally to pay System Energy monthly for the right to receive capacity and energy from Grand Gulf in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement) would at least equal System Energy’s total operating expenses for Grand Gulf (including depreciation at a specified rate and expenses incurred in a permanent shutdown of Grand Gulf) and interest charges.
The allocation percentages under the Availability Agreement are fixed as follows: Entergy Arkansas - 17.1%; Entergy Louisiana - 26.9%; Entergy Mississippi - 31.3%; and Entergy New Orleans - 24.7%. The allocation percentages under the Availability Agreement would remain in effect and would govern payments made under such agreement in the event of a shortfall of operating expense funds available to System Energy from other sources, including payments under the Unit Power Sales Agreement.
System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for all of its one outstanding series of first mortgage bonds.bonds, as well as for its outstanding term loan and the pollution control revenue refunding bonds issued on its behalf. In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they were prohibited by governmental action from making payments under the Availability Agreement (for example, if the FERC reduced or disallowed such payments as constituting excessive rates), they would then make subordinated advances to System Energy in the same amounts and at the same times as the prohibited payments. System Energy would not be allowed to repay these subordinated advances so long as it remained in default under the related indebtedness or in other similar circumstances.
Each of the assignment agreements relating to the Availability Agreement provides that Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans will make payments directly to System Energy. However, if there is an event of default, those payments must be made directly to the holders of indebtedness that are the beneficiaries of such assignment agreements. The payments must be made pro rata according to the amount of the respective obligations secured.
The obligations of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans to make payments under the Availability Agreement are subject to the receipt and continued effectiveness of all necessary regulatory approvals. Sales of capacity and energy under the Availability Agreement would require that the Availability Agreement be submitted to the FERC for approval with respect to the terms of such sale. No such filing with the FERC has been made because sales of capacity and energy from Grand Gulf are being made pursuant to the Unit Power Sales Agreement. If, for any reason, sales of capacity and energy are made in the future pursuant to the Availability Agreement, the jurisdictional portions of the Availability Agreement would be submitted to the FERC for approval.
Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement to System Energy have exceeded the amounts payable under the Availability Agreement and, therefore, 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 certain of 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 because their Availability Agreement obligations exceed their Unit Power Sales Agreement obligations.
The Availability Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, without further consent of any assignees or other creditors.
Entergy Services, a limited liability company wholly-owned by Entergy Corporation, provides management, administrative, accounting, legal, engineering, and other services primarily to the Utility operating companies, but also provides services to Entergy Wholesale Commodities. Entergy Operations is also wholly-owned by Entergy Corporation and provides nuclear management, operations and maintenance services under contract for ANO, River Bend, Waterford 3, and Grand Gulf, subject to the owner oversight of Entergy Arkansas, Entergy Louisiana, and System Energy, respectively. Entergy Services and Entergy Operations provide their services to the Utility operating companies and System Energy on an “at cost” basis, pursuant to cost allocation methodologies for these service agreements that were approved by the FERC.
Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas
Effective December 31, 2007, Entergy Gulf States, Inc. completed a jurisdictional separation into two vertically integrated utility companies, one operating under the sole retail jurisdiction of the PUCT, Entergy Texas, and the other operating under the sole retail jurisdiction of the LPSC, Entergy Gulf States Louisiana. Entergy Texas owns all Entergy Gulf States, Inc. distribution and transmission assets located in Texas, the gas-fired generating plants located in Texas, undivided 42.5% ownership shares of Entergy Gulf States, Inc.’s 70% ownership interest in Nelson Unit 6 and 42% ownership interest in Big Cajun 2, Unit 3, which are coal-fired generating plants located in Louisiana, and other assets and contract rights to the extent related to utility operations in Texas. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, owns all of the remaining assets that were owned by Entergy Gulf States, Inc. On a book value basis, approximately 58.1% of the Entergy Gulf States, Inc. assets were allocated to Entergy Gulf States Louisiana and approximately 41.9% were allocated to Entergy Texas.
Entergy Texas purchases from Entergy Louisiana pursuant to a life-of-unit purchased power agreement a 42.5% share of capacity and energy from the 70% of River Bend subject to retail regulation. Entergy Texas was allocated a share of River Bend’s nuclear and environmental liabilities that is identical to the share of the plant’s output purchased by Entergy Texas under the purchased power agreement. In connection with the termination of the System Agreement effective August 31, 2016, the purchased power agreements that were put in place for certain legacy units at the time of the jurisdictional separation were also terminated at that time. See Note 2 to the financial statements for additional discussion of the purchased power agreements.
In November 2017, pursuant to the agreement in principle, Entergy New Orleans, Inc. undertook a multi-step restructuring, including the following:
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.
In November 2018, Entergy Arkansas undertook a multi-step restructuring, including the following:
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.
In November 2018, Entergy Mississippi undertook a multi-step restructuring, including the following:
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.
Entergy Wholesale Commodities’ customers for the sale of both energy and capacity from its nuclear plantsowned generation and its contracted power purchases include retail power providers, utilities, electric power co-operatives, power trading organizations, and other power generation companies. These customers include Consumers Energy, the company from which Entergy purchased the Palisades plant, and NYISO and MISO. Substantially all of the credit exposure associated with the planned energy output under contract for Entergy Wholesale Commodities nuclear plants is with counterparties or their guarantors that have public investment grade credit ratings.
The Federal Power Act gives the FERC jurisdiction over the rates charged by System Energy for Grand Gulf capacity and energy provided to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans and over the rates charged by Entergy Arkansas and Entergy Louisiana to unaffiliated wholesale customers. The FERC also regulates wholesale power sales between the Utility operating companies. In addition, the FERC regulates the MISO RTO, an independent entity that maintains functional control over the combined transmission systems of its members and administers wholesale energy, capacity, and ancillary services markets for market participants in the MISO region, including the Utility operating companies. FERC regulation of the MISO RTO includes regulation of the design and implementation of the wholesale markets administered by the MISO RTO, as
well as the rates, terms, and conditions of open access transmission service over the member systems and the allocation of costs associated with transmission upgrades.
Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 7065 MW of capacity.
Additionally, Entergy Arkansas serves a limited number of retail customers in Tennessee. Pursuant to legislation enacted in Tennessee, Entergy Arkansas is subject to complaints before the Tennessee Regulatory Authority only if it fails to treat its retail customers in Tennessee in the same manner as its retail customers in Arkansas. Additionally, Entergy Arkansas maintains limited facilities in Missouri but does not provide retail electric service to customers in Missouri. Although Entergy Arkansas obtained a certificate with respect to its Missouri facilities, Entergy Arkansas is not subject to the retail rate or regulatory schemeratemaking jurisdiction in Missouri.
Entergy Louisiana’s electric and gas business is subject to regulation by the LPSC as to the following:
Entergy Mississippi is also subject to regulation by the APSC as to the certificate of environmental compatibility and public need for the Independence Station, which is located in Arkansas.
Entergy New Orleans is subject to regulation by the City Council as to the following:
To the extent authorized by governing legislation, Entergy Texas is subject to the original jurisdiction of the municipal authorities of a number of incorporated cities in Texas with appellate jurisdiction over such matters residing in the PUCT. Entergy Texas is also subject to regulation by the PUCT as to the following:
Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose civil penalties or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, Entergy Louisiana, and System Energy, as owners of all or portions of ANO, River Bend and Waterford 3, and Grand Gulf, respectively, and Entergy Operations, as the licensee and operator of these units, are subject to the jurisdiction of the NRC. Entergy subsidiaries in the Entergy Wholesale Commodities segment are subject to the NRC’s jurisdiction as the owners and operators of Indian Point Energy Center, Palisades, and Big Rock Point.
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 Arkansas is the only one of the Utility operating companies that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 20192022 of $191.1$195.0 million for the one-time fee. Entergy accepted assignment of the Pilgrim, FitzPatrick and Indian Point 3, Indian Point 1 and Indian Point 2, Vermont Yankee, Palisades, and Big Rock Point spent fuel disposal contracts with the DOE held by their previous owners. The FitzPatrick spent fuel disposal contract was assigned to Exelon as part of the sale of the plant, completed in March 2017. The Vermont Yankee spent fuel disposal contract was assigned to NorthStar as part of the sale of the plant which was completed in January 2019. The Pilgrim spent fuel disposal contract was transferred to Holtec as part of the sale of Entergy Nuclear Generation Company in August 2019. The owners of these plants previous to Entergy have paid or retained liability for the fees for all generation prior to the purchase dates of those plants. The fees payable to the DOE may be adjusted in the future to assure full recovery. 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. Entergy’s total spent fuel fees to date, including the one-time fee liability of Entergy Arkansas, have surpassed $1.6$1.7 billion (exclusive of amounts relating to Entergy plants that were paid or are owed by prior owners of those plants).
The permanent spent fuel repository in the U.S. has been legislated to be Yucca Mountain, Nevada. The DOE is required by law to proceed with the licensing (the DOE filed the license application in June 2008) and, after the license is granted by the NRC, proceed with the repository construction and commencement of receipt of spent fuel. 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. The DOE continues to delay meeting its obligation. Specific steps were taken to discontinue the Yucca Mountain project, including a motion to the NRC to withdraw the license application with prejudice and the establishment of a commission to develop recommendations for alternative spent fuel storage solutions. In August 2013 the U.S. Court of Appeals for the D.C. Circuit ordered the NRC to continue with the Yucca Mountain license review, but only to the extent of funds previously appropriated by Congress for that purpose and not yet used. Although the NRC completed the safety evaluation report for the license review in 2015, the previously appropriated funds are not sufficient to complete the review, including required hearings. The government has taken no effective action to date related to the recommendations of the appointed spent fuel study commission. Accordingly, large uncertainty remains regarding the time frame under which the DOE will begin to accept spent fuel from Entergy’s facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at Entergy’s nuclear sites.
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 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.
the damages caused by the DOE’s delay in performance. See Note 8 to the financial statements for discussion of final judgments recorded by Entergy in 2017, 2018,2020, 2021, and 20192022 related to Entergy’s nuclear owner licensee subsidiaries’ litigation with the DOE. Through 2019,2022, Entergy’s subsidiaries have won and collected on judgments against the government totaling over $600 million.approximately $1 billion.
Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are providing their own spent fuel storage. Storage capability additions using dry casks began operations at Palisades in 1993, at ANO in 1996, at River Bend in 2005, at Grand Gulf in 2006, at Indian Point in 2008, and at Waterford 3 in 2011. These facilities will be expanded as needed.
Entergy Arkansas, Entergy Louisiana, and System Energy are entitled to recover from customers through electric rates the estimated decommissioning costs for ANO, Waterford 3, and Grand Gulf, respectively. In addition, Entergy Louisiana and Entergy Texas are entitled to recover from customers through electric rates the estimated decommissioning costs for the portion of River Bend subject to retail rate regulation. The collections are deposited in trust funds that can only be used in accordance with NRC and other applicable regulatory requirements. Entergy periodically reviews and updates the estimated decommissioning costs to reflect inflation and changes in regulatory requirements and technology, and then makes applications to the regulatory authorities to reflect, in rates, the changes in projected decommissioning costs.
In July 2010 the LPSC approved increased decommissioning collections for Waterford 3 and the Louisiana regulated share of River Bend and in December 2010 the PUCT approved increased decommissioning collections for the Texas share of River Bend to address previously identified funding shortfalls. This LPSC decision contemplated that the level of decommissioning collections could be revisited should the NRC grant license extensions for both Waterford 3 and River Bend. In July 2019, following the NRC approval of license extensions for Waterford 3 and River Bend, Entergy Louisiana made a filing with the LPSC seeking to adjust decommissioning and depreciation rates for those plants, including one proposed scenario that would adjust Louisiana-jurisdictional decommissioning collections to zero for both plants (including an offsetting increase in depreciation rates). An evidentiary hearingBecause of the ongoing public health emergency arising from the COVID-19 pandemic and accompanying economic uncertainty, Entergy Louisiana determined that the relief sought in the filing was no longer appropriate, and in November 2020, filed an unopposed motion to dismiss the proceeding. Following that filing, in a December 2020 order, the LPSC dismissed the proceeding without prejudice. In July 2021, Entergy Louisiana made a filing with the LPSC to adjust Waterford 3 and River Bend decommissioning collections based on the latest site-specific decommissioning cost estimates for those plants. The filing seeks to increase Waterford 3 decommissioning collections and decrease River Bend decommissioning collections. The procedural schedule in the case has been scheduled for July 2020, and managementsuspended pending settlement negotiations. Management cannot predict the outcome of the case. this filing.
Entergy currently believes its decommissioning funding will be sufficient for its nuclear plants subject to retail rate regulation, although decommissioning cost inflation and trust fund performance will ultimately determine the adequacy of the funding amounts.
Additional information with respect to Entergy’s decommissioning costs and decommissioning trust funds is found in Note 9 and Note 16 to the financial statements.
The Price-Anderson Act requires that reactor licensees purchase and maintain the maximum amount of nuclear liability insurance available and participate in an industry assessment program called Secondary Financial Protection in order to protect 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 limits the contingent liability for a single nuclear incident to a maximum assessment of approximately $137.6 million per reactor (with 9896 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, Entergy Louisiana, or System Energy or an Entergy Wholesale Commodities company is liable, protection is afforded through a combination of private insurance and the Secondary Financial Protection program. In addition to this, insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units is also purchased. The Price-Anderson Act and insurance applicable to the nuclear programs of Entergy are discussed in more detail in Note 8 to the financial statements.
The NRC’s Reactor Oversight Process is a program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response. The NRC evaluates plant performance by analyzing two distinct inputs: inspection findings resulting from the NRC’s inspection program and performance indicators reported by the licensee. The evaluations result in the placement of
each plant in one of the NRC’s Reactor Oversight Process Action Matrix columns: “licensee response column,” or Column 1, “regulatory response column,” or Column 2, “degraded cornerstone column,” or Column 3, and “multiple/repetitive degraded cornerstone column,” or Column 4.4, and “unacceptable performance,” or Column 5. Plants in Column 1 are subject to normal NRC inspection activities. Plants in Column 2, Column 3, or Column 4 are subject to progressively increasing levels of inspection by the NRC with,NRC. Continued plant operation is not permitted for plants in general, progressively increasing levelsColumn 5. All of associated costs. Thethe nuclear generating plants owned and operated by Entergy’s Utility and Entergy Wholesale Commodities businessesbusiness are currently in Column 1.1, except Waterford 3, which is in Column 2.
Entergy’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy’s businesses are in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted below. Because environmental regulations are subject to change, future compliance requirements and costs cannot be precisely estimated. Except to the extent discussed below, at this time compliance with federal, state, and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of Entergy’s businesses and is not expected to have a material effect on their competitive position, results of operations, cash flows, or financial position.
The Clean Air Act and its amendments establish several programs that currently or in the future may affect Entergy’s fossil-fueled generation facilities and, to a lesser extent, certain operations at nuclear and other facilities. Individual states also operate similar independent state programs or delegated federal programs that may include requirements more stringent than federal regulatory requirements. These programs include:
The Clean Air Act requires the EPA to set National Ambient Air Quality Standards (NAAQS) for ozone, carbon monoxide, lead, nitrogen dioxide, particulate matter, and sulfur dioxide, and requires periodic review of those standards. When an area fails to meet an ambient standard, it is considered to be in nonattainment and is classified as “marginal,” “moderate,” “serious,” or “severe.” When an area fails to meet the ambient air standard, the EPA requires state regulatory authorities to prepare state implementation plans meant to cause progress toward bringing the area into attainment with applicable standards.
The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011, which had a compliance date, with a widely granted one-year extension, of April 2016. The required controls have been installed and are operational at all affected Entergy units. In February 2019May 2020 the EPA published its proposedfinalized a rule that finds that it is not “appropriate and necessary” to regulate hazardous air pollutants from electric steam generating units under the provisions of section 112(n) of the Clean Air Act. This is a reversal of the EPA’s previous finding requiring such regulation. However, the proposalThe final appropriate and necessary finding does not seek to revise the underlying MATS rule. Several lawsuits have been filed challenging the appropriate and necessary finding. In February 2021 the D.C. Circuit granted the EPA’s motion to hold the litigation in abeyance pending the agency’s review of the appropriate and necessary rule. In February 2022 the EPA issued a proposed rule at this time.revoking the 2020 rule and determining, again, that it is “appropriate and necessary” to regulate hazardous air pollutants. The EPA is seeking additional information, which it could use to further tighten the standard. Entergy will continue to monitor this situation.
In January and February 2018, Entergy Arkansas, Entergy Mississippi, Entergy Power, and other co-owners received 60-day notice of intent to sue letters from the Sierra Club and the National Parks Conservation Association concerning allegations of violations of new source review and permitting provisions of the Clean Air Act at the Independence and White Bluff coal-burning units, respectively. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims and reducing the risk that Entergy Arkansas, as operator of Independence and White Bluff, might be compelled under the Clean Air Act’s regional haze program to install costly emissions control technologies. Consistent with the terms of the settlement, and in many cases also the Part II SIP, Entergy Arkansas, along with co-owners, willagreed to begin using only low-sulfur coal at Independence and White Bluff by mid-2021; agreed to cease to useusing coal at White Bluff and Independence by the end of 2028 and 2030, respectively; agreed to cease operation of the remaining gas unit at Lake Catherine by the end of 2027; reservereserved the option to develop new generating sources at each plant site; and commitcommitted to installinstalling or proposeproposing to regulators at least 800 MWs of renewable generation by the end of 2027, with at least half installed or proposed by the end of 2022 (which includes two existing Entergy Arkansas projects) and with all qualifying co-owner projects counting toward satisfaction of the obligation. Under the settlement, the Sierra Club and the National Parks Conservation Association also waivewaived certain potential existing claims under federal and state environmental law with respect to specified generating plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the
In July 2019 the EPA released the Affordable Clean Energy Rule (ACE), which applies only to existing coal-fired electric generating units. The ACE determines that heat rate improvements are the best system of emission reductions and lists six candidate technologies for consideration by states at each coal unit. The rule and associated rulemakings by the EPA replace the Obama administration’s Clean Power Plan, rule.which established national emissions performance rates for existing fossil-fuel fired steam electric generating units and combustion turbines. The ACE rule provides states discretion in determining how the best system for emission reductions applies to individual units, including through the consideration of technical feasibility and the remaining useful life of the facility. The ADEQ and the LDEQ have issued information collection requests to Entergy is evaluatingfacilities to help the final Affordable Clean Energy Rule’s impacts on its coal units and will monitor litigation challengingstates collect the rule. The EPA also has proposed a revisioninformation needed to determine the best system of emission reductions for each facility. Entergy responded to the requests. In January 2021 the U.S. Court of Appeals for the D.C. Circuit vacated ACE. The court held that ACE relied on an incorrect interpretation of the Clean Air Act that the statute expressly forecloses emission reduction approaches, such as emissions trading and generating shifting, that cannot be applied at and to the individual source. The court remanded ACE to the EPA for further consideration and also vacated the repeal of the Clean Power Plan. In March 2021 the D.C. Circuit issued a partial mandate vacating the ACE rule, but withheld the mandate vacating the repeal of the Clean Power Plan pending the EPA’s new source performance standard onrulemaking to regulate greenhouse gas emissions. Thus, there currently is no regulation in place with respect to greenhouse gas emissions that primarily impacts new coalfrom existing electric generating units and therefore, shouldstates are not impact Entergy.
Entergy participates in the M.J. Bradley & Associates’ Annual Benchmarking Air Emissions Report, an annual analysis of the 100 largest U.S. electric power producers. The report is available on the M.J. Bradley website. Entergy’s annual greenhouse gas emissions inventory is also third-party verified, and that certification is made available on the American Carbon Registry website. Entergy participates annually in the Dow Jones Sustainability Index and in 20192022 was listed on the North American Index. Entergy has been listed on the World or North American Index, or both, for eighteen21 consecutive years. Entergy also participated in the 2022 CDP Climate Change and CDP Water Security evaluations, receiving a ‘B’ for both responses.
The 1972 amendments to the Federal Water Pollution Control Act (known as the Clean Water Act) provide the statutory basis for the National Pollutant Discharge Elimination System (NPDES) permit program, section 402, and the basic structure for regulating the discharge of pollutants from point sources to waters of the United States. The Clean Water Act requires virtually all discharges of pollutants to waters of the United States to be permitted. Section 316(b) of the Clean Water Act regulates cooling water intake structures, section 401 of the Clean Water Act requires a water quality certification from the state in support of certain federal actions and approvals, and section 404 regulates the dredge and fill of waters of the United States, including jurisdictional wetlands.
The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), authorizes the EPA to mandate clean-up by, or to collect reimbursement of clean-up costs from, owners or operators of sites at which hazardous substances may be or have been released. Certain private parties also may use CERCLA to recover response costs. Parties that transported hazardous substances to these sites or arranged for the disposal of the substances are also deemed liable by CERCLA. CERCLA has been interpreted to impose strict, joint, and several liability on responsible parties. Many states have adopted programs similar to CERCLA. Entergy subsidiaries in the Utility and Entergy Wholesale Commodities businesses have sent waste materials to various disposal
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 RCRAResource 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. As of December 31, 2019,2022, Entergy has recorded asset retirement obligations related to CCR management of $19.2$27 million.
Pursuant to the EPA Rule, Entergy operates groundwater monitoring systems surrounding its coal combustion residual landfills located at White Bluff, Independence, and Nelson. Monitoring to date has detected concentrations of certain listed constituents in the area, but has not indicated that these constituents originated at the active landfill cells. Reporting has occurred as required, and detection monitoring will continue as the rule requires. In late-2017, Entergy determined that certain in-ground wastewater treatment system recycle ponds at its White Bluff and Independence facilities require management under the new EPA regulations. InConsequently, in order to meet these regulations, onemove away from using the recycle ponds, White Bluff and Independence each have installed a new permanent bottom ash handling system that does not fall under the CCR rule. As of November 2020, both sites are operating the new system and no longer are sending waste to the recycle ponds. Each site has commenced closure of its two recycle ponds at White Bluff commenced closure in October 2018. Additionally,(four ponds total), prior to the secondApril 11, 2021 deadline under the finalized CCR rule for unlined recycle pond at White Bluff plans to initiate closure on or before October 31, 2020.ponds. Any potential requirements for corrective action or operational changes under the new EPACCR rule continue to be assessed. Notably, ongoing litigation has resulted in the EPA’s continuing review of the rule. Consequently, the nature and cost of additional corrective action requirements may depend, in part, on the outcome of the EPA’s review.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
EmployeesCustomers
Employees are an integral part of Entergy’s commitment to serving customers. As of December 31, 2019, Entergy subsidiaries employed 13,635 people.
|
| | |
Utility: | |
|
Entergy Arkansas | 1,251 |
|
Entergy Louisiana | 1,670 |
|
Entergy Mississippi | 745 |
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Entergy New Orleans | 308 |
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Entergy Texas | 643 |
|
System Energy | — |
|
Entergy Operations | 3,564 |
|
Entergy Services | 3,899 |
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Entergy Nuclear Operations | 1,505 |
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Other subsidiaries | 50 |
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Total Entergy | 13,635 |
|
Approximately 4,100 employees are represented by the International Brotherhood of Electrical Workers,2022, the Utility Workers Unionoperating companies provided retail electric and gas service to customers in Arkansas, Louisiana, Mississippi, and Texas, as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Electric Customers | | Gas Customers |
| | Area Served | | (In Thousands) | | (%) | | (In Thousands) | | (%) |
| Entergy Arkansas | Portions of Arkansas | | 730 | | | 24 | % | | | | |
| Entergy Louisiana | Portions of Louisiana | | 1,101 | | | 37 | % | | 95 | | | 47 | % |
| Entergy Mississippi | Portions of Mississippi | | 461 | | | 15 | % | | | | |
| Entergy New Orleans | City of New Orleans | | 211 | | | 7 | % | | 109 | | | 53 | % |
| Entergy Texas | Portions of Texas | | 499 | | | 17 | % | | | | |
| Total customers | | | 3,002 | | | 100 | % | | 204 | | | 100 | % |
Electric and Natural Gas Energy Sales
Electric Energy Sales
The total electric energy sales of America, the International Brotherhood of Teamsters, the United Government Security Officers of America, and the International Union, Security, Police, and Fire Professionals of America.
Availability of SEC filings and other information on Entergy’s website
Entergy electronically files reportsUtility operating companies are subject to seasonal fluctuations, with the SEC, including annual reportspeak sales period normally occurring during the third quarter of each year. On June 24, 2022, Entergy reached a 2022 peak demand of 22,301 MWh, compared to the 2021 peak of 22,051 MWh recorded on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxies, and amendments to such reports. August 23, 2021. Selected electric energy sales data for 2022 is shown in the table below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | | Entergy (a) |
| | (GWh) |
| Sales to retail customers | 22,473 | | | 57,532 | | | 13,038 | | | 5,706 | | | 21,380 | | | — | | | 120,129 | |
| Sales for resale: | | | | | | | | | | | | | |
| Affiliates | 1,906 | | | 5,416 | | | — | | | — | | | 279 | | | 7,739 | | | — | |
| Others | 6,520 | | | 3,423 | | | 2,914 | | | 2,298 | | | 813 | | | — | | | 15,968 | |
| Total | 30,899 | | | 66,371 | | | 15,952 | | | 8,004 | | | 22,472 | | | 7,739 | | | 136,097 | |
| Average use per residential customer (kWh) | 13,478 | | | 14,874 | | | 14,791 | | | 12,818 | | | 15,444 | | | — | | | 14,479 | |
(a)Includes the effect of intercompany eliminations.
The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding registrants that file electronically withfollowing table illustrates the SEC at http://www.sec.gov. Copies of the reports that Entergy files with the SEC can be obtained at the SEC’s website.
Entergy uses its website, http://www.entergy.com,Utility operating companies’ 2022 combined electric sales volume as a routine channel for distributionpercentage of important information, including news releases, analyst presentationstotal electric sales volume, and financial information. Filings made with2022 combined electric revenues as a percentage of total 2022 electric revenue, each by customer class.
| | | | | | | | | | | | | | |
| Customer Class | | % of Sales Volume | | % of Revenue |
| Residential | | 27.3 | | 35.2 |
| Commercial | | 20.6 | | 23.4 |
| Industrial (a) | | 38.6 | | 28.2 |
| Governmental | | 1.8 | | 2.2 |
| Wholesale/Other | | 11.7 | | 11.0 |
(a)Major industrial customers are primarily in the SEC are postedpetroleum refining and available without charge on Entergy’s website as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. These filings include annual and quarterly reports on Forms 10-K and 10-Q (including related filings in Inline XBRL format) and current reports on Form 8-K; proxy statements; and any amendments to those reports or statements. All such postings and filings are available on Entergy’s Investor Relations website free of charge. Entergy is providing the address to its internet site solely for the information of investors and does not intend the address to be an active link. The contents of the website are not incorporated into this report.chemical industries.
Part I Item 1A & 1B1
Entergy Corporation, Utility operating companies, and System Energy
RISK FACTORS
Investors should
Entergy New Orleans and Entergy Louisiana provide both electric power and natural gas to retail customers. Entergy New Orleans and Entergy Louisiana sold 10,514,012 and 6,786,779 Mcf, respectively, of natural gas to retail customers in 2022. In 2022, 99% of Entergy Louisiana’s operating revenue was derived from the electric utility business and only 1% from the natural gas distribution business. For Entergy New Orleans, 86% of operating revenue was derived from the electric utility business and 14% from the natural gas distribution business in 2022.
Following is data concerning Entergy New Orleans’s 2022 retail operating revenue sources:
| | | | | | | | | | | | | | |
| Customer Class | | % of Electric Operating Revenue | | % of Natural Gas Operating Revenue |
| Residential | | 47 | | 47 |
| Commercial | | 36 | | 26 |
| Industrial | | 5 | | 19 |
| Governmental/Municipal | | 12 | | 8 |
Retail Rate Regulation
General (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, System Energy)
Each Utility operating company regularly participates in retail rate proceedings. The status of material retail rate proceedings is described in Note 2 to the financial statements. Certain aspects of the Utility operating companies’ retail rate mechanisms are discussed below.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Rate base (in billions) | | Current authorized return on common equity | | Weighted average cost of capital (after-tax) | | Equity ratio | | Regulatory construct | |
| | | | | | | | | | | |
| Entergy Arkansas | | $9.2 (a) | | 9.15% - 10.15% | | 5.25% | | 37.8% (b) | | - forward test year formula rate
plan
- riders: MISO, capacity, Grand Gulf,
energy efficiency, fuel and
purchased power | |
| | | | | | | | | | | |
| Entergy Louisiana (electric) | | $14.4 (c) | | 9.0% - 10.0% | | 6.62% | | 49.41% | | - formula rate plan through 2022
test year
- riders/specific recovery: MISO,
capacity, transmission, fuel,
distribution | |
| | | | | | | | | | | |
| Entergy Louisiana (gas) | | $0.13 (d) | | 9.3% - 10.3% | | 6.76% | | 49.03% | | - gas rate stabilization plan
- rider: gas infrastructure | |
| | | | | | | | | | | |
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Mississippi | | $4.0 (e) | | 9.19% - 11.37% | | 6.71% | | 45.9% | | - formula rate plan with forward-looking features
- riders: power management, Grand Gulf, fuel, MISO, unit power cost, storm damage, ad valorem tax adjustment, vegetation, grid modernization, restructuring credit | |
| | | | | | | | | | | |
| Entergy New Orleans (electric) | | $1.2 (f) | | 8.85% -
9.85% | | 6.88% | | 51% | | - formula rate plan with forward-looking features
- riders/specific recovery: fuel and purchased power, MISO, energy efficiency, environmental, capacity | |
| | | | | | | | | | | |
| Entergy New Orleans (gas) | | $0.2 (f) | | 8.85% -
9.85% | | 6.88% | | 51% | | - formula rate plan with forward-looking features
- rider: purchased gas | |
| | | | | | | | | | | |
| Entergy Texas | | $2.4 (g) | | 9.65% | | 7.73% | | 50.90% | | - rate case
- riders: fuel, capacity, cost recovery
(distribution, transmission, and
generation), rate case expenses,
AMI surcharge, tax reform, among
others | |
| | | | | | | | | | | |
| System Energy | | $1.67 (h) | | 10.94% (i) | | 8.04 % | | 61% (i) | | - monthly cost of service | |
(a)Based on 2023 test year.
(b)Based on $1.9 billion in accumulated deferred income taxes at a 0% cost rate included in the weighted average cost of capital calculation.
(c)Based on December 31, 2021 test year and includes approximately $800 million for the Lake Charles Power Station and excludes $250 million for the Washington Parish Energy Center included in the capacity rider, $400 million of transmission plant investment included in the transmission rider, and $200 million of distribution investment included in the distribution rider.
(d)Based on September 30, 2021 test year.
(e)Based on 2022 forward test year.
(f)Based on December 31, 2021 test year and known and measurables through December 31, 2022.
(g)Based on December 31, 2017 test year and excludes $1.7 billion in cost recovery riders.
(h)Based on calculation as of December 31, 2022.
(i)Effective July 2022, Entergy Mississippi’s bills from System Energy reflect an authorized return on equity of 9.65%, a capital structure not to exceed 52% equity, a rate base reduction for the advance collection of sale-leaseback rental costs, and the exclusion of certain long-term incentive plan performance unit costs from rates. 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.
Entergy Arkansas
Formula Rate Plan
Between base rate cases, Entergy Arkansas is able to adjust base rates annually, subject to certain caps, through formula rate plans that utilize a forward test year. Entergy Arkansas is subject to a maximum rate change
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
of 4% of the filing year total retail revenue. In addition, Entergy Arkansas is subject to a true-up of projection to actuals netted with future projection. In response to Entergy Arkansas’s application for a general change in rates in 2015, the APSC approved the formula rate plan tariff proposed by Entergy Arkansas including its use of a projected year test period and an initial five-year term. The initial five-year term expired in 2021. As granted by Arkansas law, Entergy Arkansas obtained APSC approval of the extension of the formula rate plan tariff for an additional five-year term, through 2026. If Entergy Arkansas’s formula rate plan were terminated, Entergy Arkansas could file an application for a general change in rates that may include a request for continued regulation under a formula rate review carefullymechanism.
Fuel and Purchased Power Cost Recovery
Entergy Arkansas’s rate schedules include an energy cost recovery rider to recover fuel and purchased power costs in monthly bills. The rider utilizes 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-recovery or under-recovery, including carrying charges, of the energy cost 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 December 2007 the APSC issued an order stating that Entergy Arkansas’s energy cost recovery rider will remain in effect, and any future termination of the rider would be subject to eighteen months advance notice by the APSC, which would occur following notice and hearing.
Production Cost Allocation Rider
Entergy Arkansas has in place an APSC-approved production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of System Agreement proceedings.
Entergy Louisiana
Formula Rate Plan
Entergy Louisiana historically sets electric base rates annually through a formula rate plan using a historic test year. The form of the formula rate plan, on a combined basis, was approved in connection with the business combination of Entergy Louisiana and Entergy Gulf States Louisiana and largely followed the formula rate plans that were approved by the LPSC in connection with the full electric base rate cases filed by those companies in February 2013. The formula rate plan was most recently extended through the test year 2022; certain modifications were made in that extension, including a decrease to the allowed return on equity, narrowing of the earnings “dead band” around the mid-point allowed return on equity, elimination of sharing above and below the earnings “dead band,” and the addition of a distribution cost recovery mechanism. The formula rate plan continues to include exceptions from the rate cap and sharing requirements for certain large capital investment projects, including acquisition or construction of generating facilities and purchase power agreements approved by the LPSC, certain transmission investments, and most recently, certain distribution investments, among other items. In the event that the electric formula rate plan is not renewed or extended or otherwise replaced, Entergy Louisiana would revert to the more traditional rate case environment with a rate case filing occurring as soon as mid-2023.
Fuel Recovery
Entergy Louisiana’s rate schedules include a fuel adjustment clause designed to recover the cost of fuel and purchased power costs. The fuel adjustment clause contains a surcharge or credit for deferred fuel expense and related carrying charges arising from the monthly reconciliation of actual fuel costs incurred with fuel cost revenues billed to customers, including carrying charges. See Note 2 to the financial statements for a discussion of proceedings related to audits of Entergy Louisiana’s fuel adjustment clause filings.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
To help stabilize electricity costs, Entergy Louisiana received approval from the LPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Louisiana historically hedged approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity was reviewed on an annual basis. In January 2018, Entergy Louisiana filed an application with the LPSC to suspend these seasonal hedging programs and implement financial hedges with terms up to five years for a portion of its natural gas exposure, which was approved in November 2018.
Entergy Louisiana’s gas rates include a purchased gas adjustment clause based on estimated gas costs 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.
Retail Rates - Gas
In accordance with the settlement of Entergy Gulf States Louisiana’s gas rate stabilization plan for the test year ended September 30, 2012, in August 2014, Entergy Gulf States Louisiana submitted for consideration a proposal for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment and relocation projects mandated by local governments. After review by the LPSC staff and inclusion of certain customer safeguards required by the LPSC staff, in December 2014, Entergy Gulf States Louisiana and the LPSC staff submitted a joint settlement for implementation of an accelerated gas pipe replacement program providing for the replacement of approximately 100 miles of pipe over the next ten years, as well as relocation of certain existing pipe resulting from local government-related infrastructure projects, and for a rider to recover the investment associated with these projects. The rider allows for recovery of approximately $65 million over ten years. The rider recovery will be adjusted on a quarterly basis to include actual investment incurred for the prior quarter and is subject to the following conditions, among others: a ten-year term; application of any earnings in excess of the upper end of the earnings band as an offset to the revenue requirement of the infrastructure rider; adherence to a specified spending plan, within plus or minus 20% annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding 10%; and an annual true-up. The joint settlement was approved by the LPSC in January 2015. Implementation of the infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2015. In April 2022 Entergy Louisiana submitted for consideration a proposal to extend the infrastructure rider to address replacement of an additional 187 miles of pipe. In December 2022 Entergy Louisiana and the LPSC staff submitted an uncontested settlement that extends the rider for an additional ten years beginning after the end of the current term of the rider in 2025. The extension is subject to the same customer safeguards and conditions as the original term of the rider. The extension allows for recovery of approximately $95 million over ten years. In February 2023, the uncontested settlement was approved by the LPSC.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Louisiana’s filings to recover storm-related costs.
Other
In March 2016 the LPSC opened two dockets to examine, on a generic basis, issues that it identified in connection with its review of Cleco Corporation’s acquisition by third party investors. The first docket is captioned “In re: Investigation of double leveraging issues for all LPSC-jurisdictional utilities,” and the second is captioned “In re: Investigation of tax structure issues for all LPSC-jurisdictional utilities.” In April 2016 the LPSC clarified that the concerns giving rise to the two dockets arose as a result of its review of the structure of the Cleco-Macquarie transaction and that the specific intent of the directives is to seek more information regarding intra-corporate debt financing of a utility’s capital structure as well as the use of investment tax credits to mitigate the tax
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
obligation at the parent level of a consolidated entity. No schedule has been set for either docket, and limited discovery has occurred.
In December 2019 an LPSC commissioner issued an unopposed directive to staff to research customer-centered options for all customer classes, as well as other regulatory environments, and recommend a plan for how to ensure customers are the focus. There was no opposition to the directive from other commissioners but several remarked that the intent of the directive was not initiated to pursue retail open access. In furtherance of the directive, the LPSC issued a notice of the opening of a docket to conduct a rulemaking to research and evaluate customer-centered options for all electric customer classes as well as other regulatory environments in January 2020. To date, the LPSC staff has requested multiple rounds of comments from stakeholders and conducted one technical conference. Topics on which comments have been filed include full and limited retail access, demand response, sleeved power purchase agreements, and energy efficiency. Neither the LPSC or the LPSC staff have made recommendations or adopted any rules.
Entergy Mississippi
Formula Rate Plan
Since the conclusion in 2015 of Entergy Mississippi’s most recent base rate case, Entergy Mississippi has set electric base rates annually through a formula rate plan. Between base rate cases, Entergy Mississippi is able to adjust base rates annually, subject to certain caps, through formula rate plans that utilize forward-looking features. In addition, Entergy Mississippi is subject to an annual “look-back” evaluation. Entergy Mississippi is allowed a maximum rate increase of 4% of each test year’s retail revenue. Any increase above 4% requires a base rate case. If Entergy Mississippi’s formula rate plan were terminated without replacement, it would revert to the more traditional rate case environment or seek approval of a new formula rate plan.
In August 2012 the MPSC opened inquiries to review whether the then current formulaic methodology used to calculate the return on common equity in both Entergy Mississippi’s formula rate plan and Mississippi Power Company’s annual formula rate plan was still appropriate or could be improved to better serve the public interest. The intent of this inquiry and review was for informational purposes only; the evaluation of any recommendations for changes to the existing methodology would take place in a general rate case or in the existing formula rate plan proceeding. In March 2013 the Mississippi Public Utilities Staff filed its consultant’s report which noted the return on common equity estimation methods used by Entergy Mississippi and Mississippi Power Company are commonly used throughout the electric utility industry. The report suggested ways in which the methods used by Entergy Mississippi and Mississippi Power Company might be improved, but did not recommend specific changes in the return on common equity formulas or calculations at that time. In June 2014 the MPSC expanded the scope of the August 2012 inquiry to study the merits of adopting a uniform formula rate plan that could be applied, where possible in whole or in part, to both Entergy Mississippi and Mississippi Power Company in order to achieve greater consistency in the plans. The MPSC directed the Mississippi Public Utilities Staff to investigate and review Entergy Mississippi’s formula rate plan rider schedule and Mississippi Power Company’s Performance Evaluation Plan by considering the merits and deficiencies and possibilities for improvement of each and then to propose a uniform formula rate plan that, where possible, could be applicable to both companies. No procedural schedule has been set. In October 2014 the Mississippi Public Utilities Staff conducted a public technical conference to discuss performance benchmarking and its potential application to the electric utilities’ formula rate plans. The docket remains open.
In December 2019 the MPSC approved Entergy Mississippi’s proposed revisions to its formula rate plan to 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 as well as to allow similar cost recovery treatment for other capacity acquisitions that are approved by the MPSC. 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
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
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.
Fuel Recovery
Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased power costs. The energy cost rate for each calendar year is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy costs as of the 12-month period ended September 30. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC. The energy cost recovery riders allow interim rate adjustments depending on the level of over- or under-recovery of fuel and purchased energy costs.
To help stabilize electricity costs, Entergy Mississippi received approval from the MPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Mississippi hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of recovery of Entergy Mississippi’s storm-related costs.
Entergy New Orleans
Formula Rate Plan
As part of its determination of rates in the base rate case filed by Entergy New Orleans in 2018, in November 2019, the City Council issued a resolution resolving the rate case, with rates to become effective retroactive to August 2019. The resolution allows Entergy New Orleans to implement a three-year formula rate plan, beginning with the 2019 test year as adjusted for forward-looking known and measurable changes, with the filing for the first test year to be made in 2020. As part of a settlement of Entergy New Orleans’ appeal of the Council’s decision in its 2018 base rate case, Entergy New Orleans agreed to postpone the filing of its first test year formula rate plan to 2021 and, in return, to be provided an additional test year for the three-year cycle. Accordingly, Entergy New Orleans will submit its final formula rate plan filing of the three-year cycle in April 2023 unless the formula rate plan is extended or renewed. See Note 2 to the financial statements for further discussion.
Fuel Recovery
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.
To help stabilize gas costs, Entergy New Orleans seeks approval annually from the City Council to continue implementation of its natural gas hedging program consistent with the City Council’s stated policy objectives. The program uses financial instruments to hedge exposure to volatility in the wholesale price of natural gas purchased to
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serve Entergy New Orleans gas customers. Entergy New Orleans hedges up to 25% of actual gas sales made during the winter months.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy New Orleans’s filings to recover storm-related costs.
Entergy Texas
Base Rates
The base rates of Entergy Texas are established largely in traditional base rate case proceedings. Between base rate proceedings, Entergy Texas has available rate riders to recover the revenue requirements associated with certain incremental costs. Entergy Texas is required to file full base rate case proceedings every four years and within eighteen months of utilizing its generation cost recovery rider for investments above $200 million.
Fuel Recovery
Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, that are not included 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 every three years, at a minimum. In the course of this reconciliation, the PUCT determines whether eligible fuel and fuel-related expenses and revenues are necessary and reasonable and makes a prudence finding for each of the fuel-related contracts entered into during the reconciliation period. The PUCT fuel cost proceedings are discussed in Note 2 to the financial statements.
At the PUCT’s April 2013 open meeting, the PUCT Commissioners discussed their view that a purchased power capacity rider was good public policy. The PUCT issued an order in May 2013 adopting the rule allowing for a purchased power capacity rider, subject to an offsetting adjustment for load growth. The rule, as adopted, also includes a process for obtaining pre-approval by the PUCT of purchased power agreements. No Texas utility, including Entergy Texas, has exercised the option to recover capacity costs under the new rider mechanism, but Entergy Texas will continue to evaluate the benefits of utilizing the rider to recover future capacity costs.
Other Cost Recovery
As discussed above, Entergy Texas has available rate riders to recover the revenue requirements associated with certain incremental costs. These riders include a transmission cost recovery factor rider mechanism for the recovery of transmission-related capital investments, a distribution cost recovery factor rider mechanism for the recovery of distribution-related capital investment, and a generation cost recovery rider mechanism for the recovery of generation-related capital investments.
In June 2009 a law was enacted in Texas containing provisions that allow Entergy Texas to take advantage of a cost recovery mechanism that permits annual filings for the recovery of reasonable and necessary expenditures for transmission infrastructure improvement and changes in wholesale transmission charges. This mechanism was previously available to other non-ERCOT Texas utility companies, but not to Entergy Texas.
In September 2011 the PUCT adopted a proposed rule implementing a distribution cost recovery factor to recover capital and capital-related costs related to distribution infrastructure. The distribution cost recovery factor permits utilities once per year to implement an increase or decrease in rates above or below amounts reflected in base rates to reflect distribution-related depreciation expense, federal income tax and other taxes, and return on
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investment. The distribution cost recovery factor rider may be changed a maximum of four times between base rate cases.
In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery rider rule, implementing legislation passed in the 2019 Texas legislative session intended to allow electric utilities to recover generation investments between base rate proceedings. The PUCT approved the final rule in July 2020.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Texas’s filings to recover storm-related costs.
Electric Industry Restructuring
In June 2009 a law was enacted in Texas that required Entergy Texas to cease all activities relating to Entergy Texas’s transition to competition. The law allows Entergy Texas to remain a part of the SERC Reliability Corporation (SERC) Region, although it does not prevent Entergy Texas from joining another power region. The law provides that proceedings to certify a power region that Entergy Texas belongs to as a qualified power region can be initiated by the PUCT, or on motion by another party, when the conditions supporting such a proceeding exist. Under the law, the PUCT may not approve a transition to competition plan for Entergy Texas until the expiration of four years from the PUCT’s certification of a qualified power region for Entergy Texas.
The law further amended already existing law that had required Entergy Texas to propose for PUCT approval a tariff to allow eligible customers the ability to contract for competitive generation. The amending language in the law provides, among other things, that: 1) the tariff shall not be implemented in a manner that harms the sustainability or competitiveness of manufacturers who choose not to participate in the tariff; 2) Entergy Texas shall “purchase competitive generation service, selected by the customer, and provide the generation at retail to the customer;” and 3) Entergy Texas shall provide and price transmission service and ancillary services under that tariff at a rate that is unbundled from its cost of service. The law directs that the PUCT may not issue an order on the tariff that is contrary to an applicable decision, rule, or policy statement of a federal regulatory agency having jurisdiction. The PUCT determined that unrecovered costs that may be recovered through the rider consist only of those costs necessary to implement and administer the competitive generation program and do not include lost revenues or embedded generation costs. The amount of customer load that may be included in the competitive generation service program is limited to 115 MW.
System Energy
Cost of Service
The rates of System Energy are established by the FERC, and the costs allowed to be charged pursuant to these rates are, in turn, passed through to the participating Utility operating companies through the Unit Power Sales Agreement, which has monthly billings that reflect the current operating costs of, and investment in, Grand Gulf. Retail regulators and other parties may seek to initiate proceedings at FERC to investigate the prudence of costs included in the rates charged under the Unit Power Sales Agreement and examine, among other things, the reasonableness or prudence of the operation and maintenance practices, level of expenditures, allowed rates of return and rate base, and previously incurred capital expenditures. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC, including a challenge with respect to System Energy’s uncertain tax positions, sale leaseback arrangement, authorized return on equity and capital structure, and a separate proceeding for a broader investigation of rates under the Unit Power Sales Agreement. In addition, certain of the Utility operating companies’ retail regulators have filed a complaint at FERC challenging the 2012 extended power uprate of Grand Gulf and the operation and management of the plant, particularly during the time period 2016 - 2020. Beginning in 2021, System Energy implemented billing protocols to provide retail regulators with
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information regarding rates billed under the Unit Power Sales Agreement. Entergy cannot predict the outcome of any of these proceedings, and an adverse outcome in any of them could have a material adverse effect on Entergy’s or System Energy’s results of operations, financial condition, or liquidity. See Note 2 to the financial statements for further discussion of the proceedings.
Franchises
Entergy Arkansas holds exclusive franchises to provide electric service in approximately 308 incorporated cities and towns in Arkansas. These franchises generally are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas, franchises are considered to be contracts and, therefore, are governed pursuant to the terms of the franchise agreement and applicable statutes.
Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 175 incorporated municipalities and in the unincorporated areas of approximately 59 parishes of Louisiana. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and in East Baton Rouge Parish. Municipal franchise agreement terms range from 25 to 60 years while parish franchise terms range from 25 to 99 years.
Entergy Mississippi has received from the MPSC certificates of public convenience and necessity to provide electric service to areas within 45 counties, including a number of municipalities, in western Mississippi. Under Mississippi statutory law, such certificates are exclusive. Entergy Mississippi may continue to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence.
Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city ordinances. These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans’s electric and gas utility properties.
Entergy Texas holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 27 counties in eastern Texas and holds non-exclusive franchises to provide electric service in approximately 70 incorporated municipalities. Entergy Texas typically obtains 25-year franchise agreements as existing agreements expire. Entergy Texas’s electric franchises expire over the period 2023-2058.
The business of System Energy is limited to wholesale power sales. It has no distribution franchises.
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Property and Other Generation Resources
Owned Generating Stations
The total capability of the generating stations owned and leased by the Utility operating companies and System Energy as of December 31, 2022 is indicated below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Owned and Leased Capability MW(a) |
| Company | | Total | | CT / CCGT (b) | | Legacy Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
| Entergy Arkansas | | 5,276 | | | 1,567 | | | 522 | | | 1,822 | | | 1,192 | | | 73 | | | 100 | |
| Entergy Louisiana | | 10,829 | | | 5,595 | | | 2,766 | | | 2,129 | | | 339 | | | — | | | — | |
| Entergy Mississippi | | 2,857 | | | 1,738 | | | 707 | | | — | | | 310 | | | — | | | 102 | |
| Entergy New Orleans | | 663 | | | 636 | | | — | | | — | | | — | | | — | | | 27 | |
| Entergy Texas | | 3,190 | | | 980 | | | 1,960 | | | — | | | 250 | | | — | | | — | |
| System Energy | | 1,260 | | | — | | | — | | | 1,260 | | | — | | | — | | | — | |
| Total | | 24,075 | | | 10,516 | | | 5,955 | | | 5,211 | | | 2,091 | | | 73 | | | 229 | |
(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.
(b)Represents Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.
Summer peak load for the Utility has averaged 21,602 MW over the previous decade.
The Utility operating companies’ load and capacity projections are reviewed periodically to assess the need and timing for additional generating capacity and interconnections. These reviews consider existing and projected demand, the availability and price of power, the location of new load, the economy, Entergy’s clean energy and other public policy goals, environmental regulations, and the age and condition of Entergy’s existing infrastructure.
The Utility operating companies’ long-term resource strategy (Portfolio Transformation Strategy) calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Over the past decade, the Portfolio Transformation Strategy has resulted in the addition of about 8,975 MW of new long-term resources and the deactivation of about 4,881 MW of legacy generation. As MISO market participants, the Utility operating companies also participate in MISO’s Day Ahead and Real Time Energy and Ancillary Services markets to economically dispatch generation and purchase energy to serve customers reliably and at the lowest reasonable cost.
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Other Generation Resources
RFP Procurements
The Utility operating companies from time to time issue requests for proposals (RFP) to procure supply-side resources from sources other than the spot market to meet the unique regional needs of the Utility operating companies. The RFPs issued by the Utility operating companies have sought resources needed to meet near-term MISO reliability requirements as well as long-term requirements through a broad range of wholesale power products, including long-term contractual products and asset acquisitions. The RFP process has resulted in selections or acquisitions, including, among other things:
•Entergy Louisiana’s construction of the 980 MW, combined-cycle, gas turbine J. Wayne Leonard Power Station (previously referred to as the St. Charles generating facility) at its existing Little Gypsy electric generating station. The facility began commercial operation in May 2019;
•Entergy Louisiana’s construction of the 994 MW, combined-cycle, gas turbine Lake Charles generating facility at its existing Nelson electric generating station site. The facility began commercial operation in March 2020;
•Entergy Texas’s construction of the 993 MW, combined-cycle, gas turbine Montgomery County Power Station at its existing Lewis Creek electric generating station. The facility began commercial operation in January 2021;
•Entergy New Orleans’s construction of the 20 MW solar photovoltaic facility, New Orleans Solar Station, located at the NASA Michoud Facility. The facility began commercial operation in December 2020;
•In December 2020, Entergy Texas selected the self-build alternative, Orange County Advanced Power Station, out of the 2020 Entergy Texas combined-cycle, gas turbine RFP. Regulatory approval was received in November 2022 and construction has commenced. The facility is expected to be in service by mid-2026;
•In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Searcy Solar facility, sited on approximately 800 acres in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the APSC in April 2020, and closed on the acquisition, through use of a tax equity partnership, in December 2021. The Searcy Solar facility was placed in service in January 2022;
•In November 2018, Entergy Mississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Sunflower Solar facility, sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and the Sunflower Solar facility began commercial operation in September 2022;
•In June 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Walnut Bend Solar facility, that will be sited on approximately 1,000 acres in Lee County, Arkansas. In July 2021 the APSC issued an order approving the acquisition of the Walnut Bend Solar facility. The counter-party notified Entergy Arkansas that it was terminating the project, though it was willing to consider an alternative for the site. Entergy Arkansas disputed the right of termination. Negotiations are ongoing, including with respect to cost and schedule and to updates arising as a result of the Inflation Reduction Act of 2022, and the updates would require additional APSC approval. At this time the project, if approved, is expected to achieve commercial operation in 2024;
•In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility, West Memphis Solar facility, that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In October 2021 the APSC issued an order approving the acquisition of the West Memphis Solar facility. The counter-party notified Entergy Arkansas that it was seeking changes to certain terms of the build-own-transfer agreement, including both cost and schedule. In January 2023, Entergy Arkansas made a supplemental filing with the APSC. Following APSC supplemental approval, full notice to proceed will be issued with closing expected to occur in 2024;
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•In November 2021, Entergy Louisiana signed an agreement for the purchase of an approximately 150 MW to-be-constructed solar photovoltaic energy facility, St. Jacques facility, that will be sited in St. James Parish near Vacherie, Louisiana. In September 2022 the LPSC voted to approve the order including the St. Jacques facility; however, project details could be adjusted pending a final St. James Parish ruling on land use permit requirements. Closing is expected to occur in 2025 dependent upon the final St. James Parish ruling; and
•In August 2022, Entergy Arkansas signed an agreement for the purchase of an approximately 250 MW to-be-constructed solar photovoltaic energy facility, Driver Solar facility, that will be sited near Osceola, Arkansas. Also in August 2022, Entergy Arkansas received necessary approvals for the Driver Solar facility, and Entergy Arkansas has issued the counter-party full notice to proceed to begin construction. The parties are evaluating the effects of certain matters related to the Inflation Reduction Act of 2022, including the viability of a tax equity partnership. Closing is expected to occur by the end of 2024.
The RFP process has also resulted in the selection, or confirmation of the economic merits of, long-term purchased power agreements (PPAs), including, among others:
•River Bend’s 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’s 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 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. In November 2019, LS Power sold and transferred the Carville Energy Center and facility to Argo Infrastructure Partners, which included the power purchase agreement;
•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 to-be-constructed solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and the PPA began in November 2020;
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•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 to-be-constructed solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the PPA began in October 2020;
•In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in the first half of 2023;
•In August 2018, Entergy Louisiana and South Alexander Development I, LLC executed a 5-year agreement for 5 MW from a solar photovoltaic electric generating facility located in Livingston Parish, Louisiana. The PPA began in December 2020 and received regulatory approval in January 2021;
•In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and achieved commercial operation in November 2022;
•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in Polk County, Texas. The PPA is expected to start when the facility reaches commercial operation in December 2023;
•In June 2021, Entergy Louisiana and Sunlight Road Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. In September 2022 the LPSC voted to approve the order including this project. The facility is expected to reach commercial operation in December 2024;
•In June 2021, Entergy Louisiana and Vacherie Solar Energy Center, LLC executed a 20-year PPA for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. In September 2022 the LPSC voted to approve the order including this project; however, project details could be adjusted pending a final St. James Parish ruling on land use permit requirements. The facility is expected to reach commercial operation in 2025;
•In November 2021, Entergy Louisiana signed a PPA for approximately 125 MW from a to-be-constructed solar photovoltaic energy facility located in Allen, Louisiana. In September 2022 the LPSC voted to approve the order including this project. The facility is expected to reach commercial operation in February 2024;
•In December 2022, Entergy Mississippi signed a PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Hinds County, Mississippi. Following execution of the agreement, Entergy Mississippi filed a petition with the MPSC requesting all necessary approvals. The facility is expected to reach commercial operation in June 2026;
•In October 2022, Entergy Mississippi signed a PPA for approximately 100 MW from a to-be-constructed solar photovoltaic energy facility located in Tallahatchie County, Mississippi. Following execution of the agreement, Entergy Mississippi filed a petition with the MPSC requesting all necessary approvals. The facility is expected to reach commercial operation as early as May 2026;
•In October 2022, Entergy Mississippi signed a PPA for approximately 170 MW from a to-be-constructed solar photovoltaic energy facility located in Washington County, Mississippi. Following execution of the agreement, Entergy Mississippi filed a petition with the MPSC requesting all necessary approvals. The facility is expected to reach commercial operation as early as May 2026;
•In October 2022, Entergy Arkansas signed a PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in St. Francis County, Arkansas. Following execution of the agreement, Entergy Arkansas filed a petition with the APSC requesting all necessary approvals. The facility is expected to reach commercial operation as early as May 2025;
•In October 2022, Entergy Arkansas signed a PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in Mississippi County, Arkansas. Following execution of the agreement, Entergy Arkansas filed a petition with the APSC requesting all necessary approvals. The facility is expected to reach commercial operation as early as May 2025; and
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•In January 2023, Entergy Texas signed a PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Walker County, Texas. The facility is expected to reach commercial operation as early as June 2026.
In March 2021, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic resources. Entergy Louisiana selected a combination of PPA and build-own-transfer resources by March 2022, some of which have been executed and are noted above and the remainder are in progress working through definitive agreements.
In July 2021, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar generation resources. Entergy Texas selected a combination of PPA and build-own-transfer resources in March 2022. One PPA was executed in January 2023 as noted above, and definitive agreements for the remaining resources are in progress.
In August 2021, Entergy Services, on behalf of Entergy Arkansas, issued an RFP for solar photovoltaic and wind resources. Entergy Arkansas selected a combination of PPA and build-own-transfer resources in February 2022, some of which have been executed and are noted above and the remainder are in progress working through definitive agreements.
In January 2022, Entergy Services, on behalf of Entergy Mississippi, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 500 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Mississippi customers.
In June 2022, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 1500 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Louisiana customers.
In April 2022, Entergy Services, on behalf of Entergy Arkansas, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 1000 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Arkansas customers.
In October 2022, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 2000 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Texas customers.
In November 2022, Entergy Services, on behalf of Entergy Mississippi, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 500 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Mississippi customers.
Other Procurements From Third Parties
The Utility operating companies have also made resource acquisitions outside of the RFP process, including Entergy Arkansas’s (Power Block 2), Entergy Louisiana’s (Power Blocks 3 and 4), and Entergy New Orleans’s (Power Block 1) March 2016 acquisitions of the 1,980 MW (summer rating), natural gas-fired, combined-cycle gas turbine Union Power Station power blocks, each rated at 495 MW (summer rating); and Entergy Mississippi’s October 2019 acquisition of the 810 MW, combined-cycle, natural gas-fired Choctaw Generating Station. The
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Utility operating companies have also entered into various limited- and long-term contracts in recent years as a result of bilateral negotiations.
The Washington Parish Energy Center is a 361 MW natural gas-fired peaking power plant approximately 60 miles north of New Orleans on a site Entergy Louisiana purchased from Calpine in 2019. In May 2018, Entergy Louisiana received LPSC approval of its certification application for this simple-cycle power plant to be developed pursuant to an agreement between Calpine and Entergy Louisiana. Calpine began construction on the plant in early 2019 and Entergy Louisiana purchased the plant upon completion in November 2020.
The Hardin County Peaking Facility, an existing 147 MW simple-cycle gas-fired peaking power plant in Kountze, Texas, previously owned by East Texas Electric Cooperative, was acquired by Entergy Texas in June 2021. The facility has been in operation since January 2010.
Power Through Programs
In December 2020, Entergy Texas filed an application with the PUCT to amend its certificate of convenience and necessity to own and operate up to 75 MW of natural gas-fired distributed generation to be installed at commercial and industrial customer premises. Under this proposal, Entergy Texas would own and operate a fleet of generators ranging from 100 kW to 10 MW that would supply a portion of Entergy Texas’s long-term resource needs and enhance the resiliency of Entergy Texas’s electric grid. This fleet of generators would also be available to customers during outages to supply backup electric service as part of a program known as “Power Through.” In its 2021 session, the Texas legislature modified the Texas Utilities Code to exempt generators under 10 megawatts from the requirement to obtain a certificate of convenience and necessity. In addition, the PUCT announced an intent to conduct a broad rulemaking related to distributed generation and recommended that utilities with pending applications addressing distributed generation withdraw them. Accordingly, Entergy Texas withdrew its application for a certificate of convenience and necessity and associated tariff from the PUCT without prejudice to refiling. Entergy Texas continues to deploy certain customer-sited distributed generators under an existing PUCT-approved tariff. In August 2022, Entergy Texas filed an application for PUCT approval of voluntary Rate Schedule Utility Owned Distributed Generation (UODG) through which it would charge host customers for back-up service from customer-sited Power Through generators. Based on the exemption enacted by the Texas legislature in 2021, Entergy Texas’s application was not required to, and did not, seek an amendment to its certificate of convenience and necessity in order to continue deploying Power Through generators. In October 2022 two intervenors filed requests for a hearing on Entergy Texas’s application. In October 2022 the PUCT staff filed a request that the proceeding be referred to the State Office of Administrative Hearings. In January 2023 the PUCT announced an intent to develop certain broadly applicable reliability metrics against which to measure distributed generation resources and directed Entergy Texas to withdraw its application. However, the PUCT did allow Entergy Texas to continue its pilot program for Power Through generators. Entergy Texas has withdrawn its application and is considering next steps.
In August 2021, Entergy Arkansas filed with the APSC an application for authority to deploy natural gas-fired distributed generation. The application was supported by a number of letters of interest from Entergy Arkansas customers. In December 2021 the APSC general staff requested briefing, which Entergy Arkansas opposed. In January 2022, Entergy Arkansas filed to support the establishment of a procedural schedule with a hearing in April 2022. Also in January 2022, the APSC granted the general staff’s request for briefing but on an expedited schedule; briefing concluded in February 2022. Based on testimony filed to date the APSC general staff, Arkansas Electric Energy Consumers, Sierra Club, and Audubon oppose Entergy Arkansas’s proposed “Power Through” offering, which has been demonstrated to be in high demand by interested customers, some of which directly have filed public comments encouraging the APSC to approve the application. A paper hearing was held in August and September 2022 with Entergy Arkansas responding to several written commissioner questions. The parties are awaiting a decision from the APSC.
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In July 2021, Entergy Louisiana filed with the LPSC an application for authority to deploy natural gas-fired distributed generation. The application was supported by a number of letters of interest from Entergy Louisiana customers. In October 2021, a procedural schedule was established with a hearing in April 2022. Staff and certain intervenors filed direct testimony in December 2021, and cross-answering testimony was filed in January 2022. Entergy Louisiana filed rebuttal testimony in February 2022. The parties reached an uncontested settlement which, among other things, recommended approval of 120 MW of natural gas fired distributed generation and an additional 30 MW of solar and battery distributed generation, for a total distributed generation program of 150 MW. Pursuant to the terms of the settlement agreement, Entergy Louisiana may seek to expand the distributed generation program following the earlier of two years after issuance of an order approving the settlement or the installation of 60 MW of distributed generation pursuant to this program. The settlement was approved by the LPSC in November 2022.
Interconnections
The Utility operating companies’ generating units are interconnected to a transmission system operating at various voltages up to 500 kV. These generating units consist of steam-turbine generators fueled by natural gas and coal, combustion-turbine generators, and reciprocating internal combustion engine generators that are fueled by natural gas, generators powered by pressurized and boiling water nuclear reactors and inverter-based resources interconnecting both solar photovoltaic systems and energy storage devices that operate in the MISO wholesale electric market. Additionally, some of the Utility operating companies also offer customer services and products that include resources interconnected to both the distribution and transmission systems that also participate in the wholesale market. Entergy’s Utility operating companies are MISO market participants and the companies’ transmission systems are interconnected with those of many neighboring utilities. MISO is an essential link in the safe, cost-effective delivery of electric power across all or parts of 15 U.S. states and the Canadian province of Manitoba. In addition, the Utility operating companies are members of SERC Reliability Corporation (SERC), the Regional Entity with delegated authority from the North American Electric Reliability Corporation (NERC) for the purpose of proposing and enforcing Bulk Electric System reliability standards within 16 central and southeastern states.
Gas Property
As of December 31, 2022, Entergy New Orleans distributed and transported natural gas for distribution within New Orleans, Louisiana, through approximately 2,600 miles of gas pipeline. As of December 31, 2022, the gas properties of Entergy Louisiana, which are located in and around Baton Rouge, Louisiana, were not material to Entergy Louisiana’s financial position.
Title
The Utility operating companies’ generating stations are generally located on properties owned in fee simple. Most of the substations and transmission and distribution lines are constructed on private property or public rights-of-way pursuant to easements, servitudes, or appropriate franchises. Some substation properties are owned in fee simple. The Utility operating companies generally have the right of eminent domain, whereby they may perfect title to, or secure easements or servitudes on, private property for their utility operations.
Substantially all of the physical properties and assets owned by Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are subject to the liens of mortgages securing bonds issued by those companies. The Lewis Creek generating station of Entergy Texas was acquired by merger with a subsidiary of Entergy Texas and is currently not subject to the lien of the Entergy Texas indenture.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Fuel Supply
The average fuel cost per kWh for the Utility operating companies and System Energy for the years 2020-2022 were:
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| Year | | Natural Gas | | Nuclear | | Coal | | Renewables (a) | | Purchased Power | | MISO Purchases (b) |
| 2022 | | (Cents Per kWh) |
| Entergy Arkansas | | 4.98 | | | 0.52 | | | 2.93 | | | 2.11 | | | 10.90 | | | (2.65) | |
| Entergy Louisiana | | 5.50 | | | 0.57 | | | 2.84 | | | 10.70 | | | 6.95 | | | 6.45 | |
| Entergy Mississippi | | 4.38 | | | — | | | 2.85 | | | 0.04 | | | 6.53 | | | 6.68 | |
| Entergy New Orleans (c) | | 5.10 | | | — | | | — | | | (5.16) | | | — | | | 7.21 | |
| Entergy Texas | | 5.77 | | | — | | | 2.83 | | | 6.26 | | | 5.61 | | | 6.68 | |
| System Energy | | — | | | 0.65 | | | — | | | — | | | — | | | — | |
| Utility | | 5.27 | | | 0.57 | | | 2.89 | | | 7.00 | | | 6.54 | | | 5.95 | |
| | | | | | | | | | | | |
| 2021 | | | | | | | | | | | | |
| Entergy Arkansas | | 4.11 | | | 0.56 | | | 2.43 | | | 2.85 | | | 2.53 | | | 3.87 | |
| Entergy Louisiana | | 3.77 | | | 0.56 | | | 2.62 | | | 10.87 | | | 5.52 | | | 4.04 | |
| Entergy Mississippi | | 2.71 | | | — | | | 2.53 | | | 1.22 | | | 2.70 | | | 4.16 | |
| Entergy New Orleans (c) | | 3.47 | | | — | | | — | | | (2.82) | | | — | | | 4.50 | |
| Entergy Texas | | 4.65 | | | — | | | 2.60 | | | 3.97 | | | 4.53 | | | 4.10 | |
| System Energy | | — | | | 0.55 | | | — | | | — | | | — | | | — | |
| Utility | | 3.75 | | | 0.56 | | | 2.48 | | | 9.07 | | | 4.76 | | | 4.08 | |
| | | | | | | | | | | | |
| 2020 | | | | | | | | | | | | |
| Entergy Arkansas | | 1.78 | | | 0.62 | | | 2.35 | | | 2.28 | | | 7.39 | | | 0.63 | |
| Entergy Louisiana | | 1.98 | | | 0.58 | | | 3.27 | | | 9.99 | | | 3.48 | | | 2.65 | |
| Entergy Mississippi | | 1.73 | | | — | | | 2.52 | | | 0.25 | | | 3.23 | | | 2.26 | |
| Entergy New Orleans | | 1.56 | | | — | | | — | | | 0.02 | | | — | | | 2.99 | |
| Entergy Texas | | 2.23 | | | — | | | 3.17 | | | 3.61 | | | 3.29 | | | 2.71 | |
| System Energy | | — | | | 0.39 | | | — | | | — | | | — | | | — | |
| Utility | | 1.92 | | | 0.57 | | | 2.54 | | | 8.28 | | | 3.35 | | | 2.48 | |
(a)Includes average fuel costs from both owned and purchased power resources.
(b)Includes activity from financial transmission rights. See Note 15 to the financial statements for discussion of financial transmission rights.
(c)Entergy New Orleans’s renewables include liquidated damage payments of $2.9 million in 2022 and $1 million in 2021 due to the delay of in-service dates related to purchased power agreements.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Actual 2022 and projected 2023 sources of generation for the Utility operating companies and System Energy, including certain power purchases from affiliates under life of unit power purchase agreements, including the Unit Power Sales Agreement, are:
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| 2022 |
| | CT / CCGT (b) | | Legacy Gas | | Nuclear | | Coal | | Renewables (c) | | Purchased Power (d) | | MISO Purchases (e) |
| Entergy Arkansas | 30 | % | | 1 | % | | 50 | % | | 12 | % | | 3 | % | | — | % | | 4 | % |
| Entergy Louisiana | 44 | % | | 9 | % | | 23 | % | | 3 | % | | 2 | % | | 8 | % | | 11 | % |
| Entergy Mississippi | 59 | % | | 6 | % | | 18 | % | | 7 | % | | 1 | % | | — | % | | 9 | % |
| Entergy New Orleans | 54 | % | | 1 | % | | 35 | % | | 1 | % | | 1 | % | | 1 | % | | 7 | % |
| Entergy Texas | 31 | % | | 20 | % | | 11 | % | | 5 | % | | — | % | | 9 | % | | 24 | % |
| System Energy (a) | — | % | | — | % | | 100 | % | | — | % | | — | % | | — | % | | — | % |
| Utility | 42 | % | | 8 | % | | 27 | % | | 5 | % | | 2 | % | | 5 | % | | 11 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2023 |
| | CT / CCGT (b) | | Legacy Gas | | Nuclear | | Coal | | Renewables (c) | | Purchased Power (d) | | MISO Purchases (e) |
| Entergy Arkansas | 26 | % | | — | % | | 58 | % | | 13 | % | | 3 | % | | — | % | | — | % |
| Entergy Louisiana | 47 | % | | 5 | % | | 30 | % | | 3 | % | | 3 | % | | 12 | % | | — | % |
| Entergy Mississippi | 63 | % | | — | % | | 26 | % | | 10 | % | | 1 | % | | — | % | | — | % |
| Entergy New Orleans | 48 | % | | 1 | % | | 45 | % | | 2 | % | | 3 | % | | 1 | % | | — | % |
| Entergy Texas | 44 | % | | 31 | % | | 15 | % | | 9 | % | | — | % | | 1 | % | | — | % |
| System Energy (a) | — | % | | — | % | | 100 | % | | — | % | | — | % | | — | % | | — | % |
| Utility | 44 | % | | 6 | % | | 36 | % | | 7 | % | | 2 | % | | 5 | % | | — | % |
(a)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.
(b)Represents natural gas sourced for Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.
(c)Includes generation from both owned and purchased power resources.
(d)Excludes MISO purchases and renewables purchased through purchased power agreements.
(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 2022 is not projected for 2023.
Some of the Utility’s gas-fired plants are also capable of using fuel oil, if necessary. Although based on current economics the Utility does not expect fuel oil use in 2023, it is possible that various operational events including weather or pipeline maintenance may require the use of fuel oil.
Natural Gas
The Utility operating companies have long-term firm and short-term interruptible gas contracts for both supply and transportation. Over 50% of the Utility operating companies’ power plants maintain some level of long-term firm transportation. Short-term contracts and spot-market purchases satisfy additional gas requirements.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Entergy Texas owns a gas storage facility and Entergy Louisiana has a firm storage service agreement that provide reliable and flexible natural gas service to certain generating stations.
Many factors, including wellhead deliverability, storage, pipeline capacity, and demand requirements of end users, influence the availability and price of natural gas supplies for power plants. Demand is primarily tied to weather conditions as well as to the prices and availability of other energy sources. Pursuant to federal and state regulations, gas supplies to power plants may be interrupted during periods of shortage. To the extent natural gas supplies are disrupted or natural gas prices significantly increase, the Utility operating companies may in some instances use alternate fuels, such as oil when available, or rely to a larger extent on coal, nuclear generation, and purchased power.
Coal
Entergy Arkansas has committed to six two- to three-year contracts that will supply approximately 85% of the total coal supply needs in 2023. These contracts are staggered in term so that not all contracts have to be renewed the same year. If needed, additional Powder River Basin (PRB) coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. Based on the high cost of alternate sources, modes of transportation, and infrastructure improvements necessary for its delivery, no alternative coal consumption is expected at Entergy Arkansas during 2023. Coal will be transported to Arkansas via an existing Union Pacific transportation agreement that is expected to provide all of Entergy Arkansas’s rail transportation requirements for 2023.
Entergy Louisiana has committed to four two- to three-year contracts that will supply approximately 90% of Nelson Unit 6 coal needs in 2023. If needed, additional PRB coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. For the same reasons as the Entergy Arkansas plants, no alternative coal consumption is expected at Nelson Unit 6 during 2023. Coal will be transported to Nelson via an existing transportation agreement that is expected to provide all of Entergy Louisiana’s rail transportation requirements for 2023.
Coal transportation delivery rates to Entergy Arkansas- and Entergy Louisiana-operated coal-fired units became constrained and were unable to fully meet supply needs and obligations beginning in August 2021. Deliveries remained constrained through 2022 with modest improvement expected later in 2023. Both Entergy Arkansas and Entergy Louisiana control enough railcars to satisfy the rail transportation requirement.
The operator of Big Cajun 2 - Unit 3, Louisiana Generating, LLC, has advised Entergy Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2023, but is also currently experiencing delivery constraints. Entergy Louisiana’s and Entergy Texas’s coal nomination requests to Big Cajun 2 - Unit 3 are made on an annual basis.
Nuclear Fuel
The nuclear fuel cycle consists of the following:
•mining and milling of uranium ore to produce a concentrate;
•conversion of the concentrate to uranium hexafluoride gas;
•enrichment of the uranium hexafluoride gas;
•fabrication of nuclear fuel assemblies for use in fueling nuclear reactors; and
•disposal of spent fuel.
The Registrant Subsidiaries that own nuclear plants, Entergy Arkansas, Entergy Louisiana, and System Energy, are responsible through a shared regulated uranium pool for contracts to acquire nuclear material to be used in fueling Entergy’s Utility nuclear units. These companies own the materials and services in this shared regulated
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
uranium pool on a pro rata fractional basis determined by the nuclear generation capability of each company. Any liabilities for obligations of the pooled contracts are on a several but not joint basis. The shared regulated uranium pool maintains inventories of nuclear materials during the various stages of processing. The Registrant Subsidiaries purchase enriched uranium hexafluoride for their nuclear plant reload requirements at the average inventory cost from the shared regulated uranium pool. Entergy Operations, Inc. contracts separately for the fabrication of nuclear fuel as agent on behalf of each of the Registrant Subsidiaries that owns a nuclear plant. All contracts for the disposal of spent nuclear fuel are between the DOE and the owner of a nuclear power plant.
Based upon currently planned fuel cycles, the Utility nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable or fixed prices through most of 2027. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners, including their ability to work through supply disruptions caused by global events, such as the COVID-19 pandemic, or national events, such as political disruption. There are a number of possible supply alternatives that may be accessed to mitigate any supplier performance failure, including potentially drawing upon Entergy’s inventory intended for later generation periods depending upon its risk factorsmanagement strategy at that time, although the pricing of any alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. In addition, some nuclear fuel contracts are on a non-fixed price basis subject to prevailing prices at the time of delivery.
The effects of market price changes may be reduced and deferred by risk management strategies, such as negotiation of floor and ceiling amounts for long-term contracts, buying for inventory or entering into forward physical contracts at fixed prices when Entergy believes it is appropriate and useful. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S.
Entergy’s ability to assure nuclear fuel supply also depends upon the performance reliability of conversion, enrichment, and fabrication services providers. There are fewer of these providers than for uranium. For conversion and enrichment services, like uranium, Entergy diversifies its supply by supplier and country and may take special measures as needed to ensure supply of enriched uranium for the reliable fabrication of nuclear fuel. For fabrication services, each plant is dependent upon the effective performance of the fabricator of that plant’s nuclear fuel, therefore, Entergy provides additional monitoring, inspection, and oversight for the fabrication process to assure reliability and quality.
Entergy Arkansas, Entergy Louisiana, and System Energy each have made arrangements to lease nuclear fuel and related equipment and services. The lessors, which are consolidated in the financial statements of Entergy and the applicable Registrant Subsidiary, finance the acquisition and ownership of nuclear fuel through credit agreements and the issuance of notes. These credit facilities are subject to periodic renewal, and the notes are issued periodically, typically for terms between three and seven years.
Natural Gas Purchased for Resale
Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with one interstate and three intrastate pipelines. Entergy New Orleans has a “no-notice” service gas purchase contract with Symmetry Energy Solutions which guarantees Entergy New Orleans gas delivery at specific delivery points and at any volume within the minimum and maximum set forth in the contract amounts. The Symmetry Energy Solutions gas supply is transported to Entergy New Orleans pursuant to a transportation service agreement with Gulf South Pipeline Co. This service is subject to FERC-approved rates. Entergy New Orleans also makes interruptible spot market purchases.
Entergy Louisiana purchased natural gas for resale in 2022 under a firm contract from Sequent Energy Management L.P. The gas is delivered through a combination of intrastate and interstate pipelines.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy Louisiana’s or Entergy New Orleans’s suppliers failed to perform their obligations to deliver gas under their supply agreements. Gulf South Pipeline Co. could curtail transportation capacity only in the event of pipeline system constraints.
Federal Regulation of the Utility
State or local regulatory authorities, as described above, regulate the retail rates of the Utility operating companies. The FERC regulates wholesale sales of electricity rates and interstate transmission of electricity, including System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. See Note 2 to the financial statements for further discussion of federal regulation proceedings.
Transmission and MISO Markets
In December 2013 the Utility operating companies integrated into the MISO RTO. Although becoming a member of MISO did not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities, MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. MISO also exercises functional control of transmission planning and congestion management and provides schedules and pricing for the commitment and dispatch of generation that is offered into MISO’s markets, as well as pricing for load that bids into the markets. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their generating facilities into the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. Each Utility operating company has its own transmission pricing zone and a formula rate template (included as Attachment O to the MISO tariff) used to establish transmission rates within MISO. The terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets and the allocation of transmission upgrade costs, are subject to regulation by the FERC.
System Energy and Related Agreements
System Energy recovers costs related to its interest in Grand Gulf through rates charged to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans for capacity and energy under the Unit Power Sales Agreement (described below). In 1998 the FERC approved requests by Entergy Arkansas and Entergy Mississippi to accelerate a portion of their Grand Gulf purchased power obligations. Entergy Arkansas’s and Entergy Mississippi’s acceleration of Grand Gulf purchased power obligations ceased effective July 2001 and July 2003, respectively, as approved by the FERC. See Note 2 to the financial statements for discussion of proceedings at the FERC related to System Energy.
Unit Power Sales Agreement
The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System Energy’s ownership and leasehold interests in Grand Gulf to Entergy Arkansas (36%), Entergy Louisiana (14%), Entergy Mississippi (33%), and Entergy New Orleans (17%). Each of these companies is obligated to make payments to System Energy for its entitlement of capacity and energy on a full cost-of-service basis regardless of the quantity of energy delivered. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenue. The financial condition of System Energy depends upon the continued commercial operation of Grand Gulf and the receipt of such payments. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans generally recover payments made under the Unit Power Sales Agreement through rates charged to their customers.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
In the case of Entergy Arkansas and Entergy Louisiana, payments are also recovered through sales of electricity from their respective retained shares of Grand Gulf. Under a settlement agreement entered into with the APSC in 1985 and amended in 1988, Entergy Arkansas retains 22% of its 36% share of Grand Gulf-related costs and recovers the remaining 78% of its share in rates. In the event that Entergy Arkansas is not able to sell its retained share to third parties, it may sell such energy to its retail customers at a price equal to its avoided cost, which is currently less than Entergy Arkansas’s cost from its retained share. Entergy Arkansas has life-of-resources purchased power agreements with Entergy Louisiana and Entergy New Orleans that sell a portion of the output of Entergy Arkansas’s retained share of Grand Gulf to those companies, with the remainder of the retained share being sold to Entergy Mississippi through a separate life-of-resources purchased power agreement. In a series of LPSC orders, court decisions, and agreements from late 1985 to mid-1988, Entergy Louisiana was granted cost recovery with respect to costs associated with Entergy Louisiana’s share of capacity and energy from Grand Gulf, subject to certain terms and conditions. Entergy Louisiana retains and does not recover from retail ratepayers 18% of its 14% share of the costs of Grand Gulf capacity and energy and recovers the remaining 82% of its share in rates. Entergy Louisiana is allowed to recover through the fuel adjustment clause at 4.6 cents per kWh for the energy related to its retained portion of these costs. Alternatively, Entergy Louisiana may sell such energy to non-affiliated parties at prices above the fuel adjustment clause recovery amount, subject to the LPSC’s approval. Entergy Arkansas also has a life-of-resources purchased power agreement with Entergy Mississippi to sell a portion of the output of Entergy Arkansas’s non-retained share of Grand Gulf. Entergy Mississippi was granted cost recovery for those purchases by the MPSC through its annual unit power cost rate mechanism.
Availability Agreement
The Availability Agreement among System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans was entered into in 1974 in connection with the original financing by System Energy of Grand Gulf. The Availability Agreement provides that System Energy make available to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans all capacity and energy available from System Energy’s share of Grand Gulf.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans also agreed severally to pay System Energy monthly for the right to receive capacity and energy from Grand Gulf in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement) would at least equal System Energy’s total operating expenses for Grand Gulf (including depreciation at a specified rate and expenses incurred in a permanent shutdown of Grand Gulf) and interest charges.
The allocation percentages under the Availability Agreement are fixed as follows: Entergy Arkansas - 17.1%; Entergy Louisiana - 26.9%; Entergy Mississippi - 31.3%; and Entergy New Orleans - 24.7%. The allocation percentages under the Availability Agreement would remain in effect and would govern payments made under such agreement in the event of a shortfall of operating expense funds available to System Energy from other sources, including payments under the Unit Power Sales Agreement.
System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for all of its outstanding series of first mortgage bonds, as well as for its outstanding term loan and the pollution control revenue refunding bonds issued on its behalf. In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they were prohibited by governmental action from making payments under the Availability Agreement (for example, if the FERC reduced or disallowed such payments as constituting excessive rates), they would then make subordinated advances to System Energy in the same amounts and at the same times as the prohibited payments. System Energy would not be allowed to repay these subordinated advances so long as it remained in default under the related indebtedness or in other similar circumstances.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Each of the assignment agreements relating to the Availability Agreement provides that Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans will make payments directly to System Energy. However, if there is an event of default, those payments must be made directly to the holders of indebtedness that are the beneficiaries of such assignment agreements. The payments must be made pro rata according to the amount of the respective obligations secured.
The obligations of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans to make payments under the Availability Agreement are subject to the receipt and continued effectiveness of all necessary regulatory approvals. Sales of capacity and energy under the Availability Agreement would require that the Availability Agreement be submitted to the FERC for approval with respect to the terms of such sale. No such filing with the FERC has been made because sales of capacity and energy from Grand Gulf are being made pursuant to the Unit Power Sales Agreement. If, for any reason, sales of capacity and energy are made in the future pursuant to the Availability Agreement, the jurisdictional portions of the Availability Agreement would be submitted to the FERC for approval.
Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement to System Energy have exceeded the amounts payable under the Availability Agreement and, therefore, 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 certain of 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 because their Availability Agreement obligations exceed their Unit Power Sales Agreement obligations.
The Availability Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, without further consent of any assignees or other creditors.
Service Companies
Entergy Services, a limited liability company wholly-owned by Entergy Corporation, provides management, administrative, accounting, legal, engineering, and other services primarily to the Utility operating companies, but also provides services to Entergy Wholesale Commodities. Entergy Operations is also wholly-owned by Entergy Corporation and provides nuclear management, operations and maintenance services under contract for ANO, River Bend, Waterford 3, and Grand Gulf, subject to the owner oversight of Entergy Arkansas, Entergy Louisiana, and System Energy, respectively. Entergy Services and Entergy Operations provide their services to the Utility operating companies and System Energy on an “at cost” basis, pursuant to cost allocation methodologies for these service agreements that were approved by the FERC.
Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas
Effective December 31, 2007, Entergy Gulf States, Inc. completed a jurisdictional separation into two vertically integrated utility companies, one operating under the sole retail jurisdiction of the PUCT, Entergy Texas, and the other informationoperating under the sole retail jurisdiction of the LPSC, Entergy Gulf States Louisiana. Entergy Texas owns all Entergy Gulf States, Inc. distribution and transmission assets located in this Form 10-K.Texas, the gas-fired generating plants located in Texas, undivided 42.5% ownership shares of Entergy Gulf States, Inc.’s 70% ownership interest in Nelson Unit 6 and 42% ownership interest in Big Cajun 2, Unit 3, which are coal-fired generating plants located in Louisiana, and other assets and contract rights to the extent related to utility operations in Texas. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, owns all of the remaining assets that were owned by Entergy Gulf States, Inc. On a book value basis, approximately 58.1% of the Entergy Gulf States, Inc. assets were allocated to Entergy Gulf States Louisiana and approximately 41.9% were allocated to Entergy Texas.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Entergy Texas purchases from Entergy Louisiana pursuant to a life-of-unit purchased power agreement a 42.5% share of capacity and energy from the 70% of River Bend subject to retail regulation. Entergy Texas was allocated a share of River Bend’s nuclear and environmental liabilities that is identical to the share of the plant’s output purchased by Entergy Texas under the purchased power agreement. In connection with the termination of the System Agreement effective August 31, 2016, the purchased power agreements that were put in place for certain legacy units at the time of the jurisdictional separation were also terminated at that time. See Note 2 to the financial statements for additional discussion of the purchased power agreements.
Entergy Louisiana and Entergy Gulf States Louisiana Business Combination
On October 1, 2015, the businesses formerly conducted by Entergy Louisiana (Old Entergy Louisiana) and Entergy Gulf States Louisiana (Old Entergy Gulf States Louisiana) were combined into a single public utility. In order to effect the business combination, under the Texas Business Organizations Code (TXBOC), Old Entergy Louisiana allocated substantially all of its assets to a new subsidiary, Entergy Louisiana Power, LLC, a Texas limited liability company (New Entergy Louisiana), and New Entergy Louisiana assumed the liabilities of Old Entergy Louisiana, in a transaction regarded as a merger under the TXBOC. Under the TXBOC, Old Entergy Gulf States Louisiana allocated substantially all of its assets to a new subsidiary (New Entergy Gulf States Louisiana) and New Entergy Gulf States Louisiana assumed the liabilities of Old Entergy Gulf States Louisiana, in a transaction regarded as a merger under the TXBOC. New Entergy Gulf States Louisiana then merged into New Entergy Louisiana with New Entergy Louisiana surviving the merger. Thereupon, Old Entergy Louisiana changed its name from “Entergy Louisiana, LLC” to “EL Investment Company, LLC” and New Entergy Louisiana changed its name from “Entergy Louisiana Power, LLC” to “Entergy Louisiana, LLC” (Entergy Louisiana). With the completion of the business combination, Entergy Louisiana holds substantially all of the assets, and has assumed the liabilities, of Old Entergy Louisiana and Old Entergy Gulf States Louisiana.
Entergy New Orleans Internal Restructuring
In November 2017, pursuant to the agreement in principle, Entergy New Orleans, Inc. undertook a multi-step restructuring, including the following:
•Entergy New Orleans, Inc. redeemed its outstanding preferred stock at a price of approximately $21 million, which included a call premium of approximately $819,000, plus any accumulated and unpaid dividends.
•Entergy New Orleans, Inc. converted from a Louisiana corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy New Orleans, Inc. allocated substantially all of its assets to a new subsidiary, Entergy New Orleans Power, LLC, a Texas limited liability company (Entergy New Orleans Power), and Entergy New Orleans Power assumed substantially all of the liabilities of Entergy New Orleans, Inc. in a transaction regarded as a merger under the TXBOC. Entergy New Orleans, Inc. remained in existence and held the membership interests in Entergy New Orleans Power.
•Entergy New Orleans, Inc. contributed the membership interests in Entergy New Orleans Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy New Orleans Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2017, Entergy New Orleans, Inc. changed its name to Entergy Utility Group, Inc., and Entergy New Orleans Power then changed its name to Entergy New Orleans, LLC. Entergy New Orleans, LLC holds substantially all of the assets, and has assumed substantially all of the liabilities, of Entergy New Orleans, Inc. The risksrestructuring was accounted for as a transaction between entities under common control.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Entergy Arkansas Internal Restructuring
In November 2018, Entergy Arkansas undertook a multi-step restructuring, including the following:
•Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.
•Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Arkansas Power, LLC, a Texas limited liability company (Entergy Arkansas Power), and Entergy Arkansas Power assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.
•Entergy Arkansas, Inc. contributed the membership interests in Entergy Arkansas Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Arkansas Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Arkansas, Inc. changed its name to Entergy Utility Property, Inc., and Entergy Arkansas Power then changed its name to Entergy Arkansas, LLC. Entergy Arkansas, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Arkansas, Inc. The transaction was accounted for as a transaction between entities under common control.
Entergy Mississippi Internal Restructuring
In November 2018, Entergy Mississippi undertook a multi-step restructuring, including the following:
•Entergy Mississippi, Inc. redeemed its outstanding preferred stock, at the aggregate redemption price of approximately $21.2 million.
•Entergy Mississippi, Inc. converted from a Mississippi corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Mississippi, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Mississippi Power and Light, LLC, a Texas limited liability company (Entergy Mississippi Power and Light), and Entergy Mississippi Power and Light assumed substantially all of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Mississippi, Inc. remained in existence and held the membership interests in Entergy Mississippi Power and Light.
•Entergy Mississippi, Inc. contributed the membership interests in Entergy Mississippi Power and Light to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Mississippi Power and Light is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Mississippi, Inc. changed its name to Entergy Utility Enterprises, Inc., and Entergy Mississippi Power and Light then changed its name to Entergy Mississippi, LLC. Entergy Mississippi, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Mississippi, Inc. The restructuring was accounted for as a transaction between entities under common control.
Entergy Wholesale Commodities
See “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the shutdown and sale of each of the Entergy Wholesale Commodities nuclear power plants. With the sale of Palisades in June 2022, Entergy completed its multi-year strategy to exit the merchant power business.
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Entergy Wholesale Commodities includes the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. Entergy facesWholesale Commodities also provides decommissioning-related services to nuclear power plants owned by non-affiliated entities in the United States.
Property
Entergy Wholesale Commodities includes ownership in the following non-nuclear power plants:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Plant | | Location | | Ownership | | Net Owned Capacity (a) | | Type |
| Independence Unit 2; 842 MW | | Newark, AR | | 14% | | 121 MW(b) | | Coal |
| Nelson Unit 6; 550 MW | | Westlake, LA | | 11% | | 60 MW(b) | | Coal |
(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.
All of Entergy Wholesale Commodities’ owned generation falls under the authority of MISO. Entergy Wholesale Commodities’ customers for the sale of both energy and capacity from its owned generation and its contracted power purchases include retail power providers, utilities, electric power co-operatives, power trading organizations, and other power generation companies. The majority of Entergy Wholesale Commodities’ owned generation and contracted power purchases are sold under cost-based contract.
Other Business Activities
TLG Services, a subsidiary in the Entergy Wholesale Commodities segment, offers decommissioning, engineering, and related services to nuclear power plant owners.
Regulation of Entergy’s Business
Federal Power Act
The Federal Power Act provides the FERC the authority to regulate:
•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.
The Federal Power Act gives the FERC jurisdiction over the rates charged by System Energy for Grand Gulf capacity and energy provided to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans and over the rates charged by Entergy Arkansas and Entergy Louisiana to unaffiliated wholesale customers. The FERC also regulates wholesale power sales between the Utility operating companies. In addition, the FERC regulates the MISO RTO, an independent entity that maintains functional control over the combined transmission systems of its members and administers wholesale energy, capacity, and ancillary services markets for market participants in the MISO region, including the Utility operating companies. FERC regulation of the MISO RTO includes regulation of the design and implementation of the wholesale markets administered by the MISO RTO, as
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well as the rates, terms, and conditions of open access transmission service over the member systems and the allocation of costs associated with transmission upgrades.
Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 65 MW of capacity.
State Regulation
Utility
Entergy Arkansas is subject to regulation by the APSC as to the following:
•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 non-exempt 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.
Additionally, Entergy Arkansas serves a limited number of retail customers in Tennessee. Pursuant to legislation enacted in Tennessee, Entergy Arkansas is subject to complaints before the Tennessee Regulatory Authority only if it fails to treat its retail customers in Tennessee in the same manner as its retail customers in Arkansas. Additionally, Entergy Arkansas maintains limited facilities in Missouri but does not provide retail electric service to customers in Missouri. Although Entergy Arkansas obtained a certificate with respect to its Missouri facilities, Entergy Arkansas is not subject to retail ratemaking jurisdiction in Missouri.
Entergy Louisiana’s electric and gas business is subject to regulation by the LPSC as to the following:
•utility service;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment clause, environmental adjustment charge, 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 for purchase power contracts that exceed either 5 MW or one year in term;
•procurement process to acquire capacity over 50 MW;
•audits of the energy efficiency rider;
•avoided cost payment to non-exempt Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers and acquisitions and other changes of control.
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Entergy Mississippi is subject to regulation by the MPSC as to the following:
•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;
•certification of generating facilities and certain transmission projects;
•avoided cost payments to non-exempt Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers, acquisitions, and other changes of control.
Entergy Mississippi is also subject to regulation by the APSC as to the certificate of environmental compatibility and public need for the Independence Station, which is located in Arkansas.
Entergy New Orleans is subject to regulation by the City Council as to the following:
•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;
•avoided cost payments to non-exempt Qualifying Facilities;
•issuance and sale of certain securities; and
•utility mergers and acquisitions and other changes of control.
To the extent authorized by governing legislation, Entergy Texas is subject to the original jurisdiction of the municipal authorities of a number of incorporated cities in Texas with appellate jurisdiction over such matters residing in the PUCT. Entergy Texas is also subject to regulation by the PUCT as to the following:
•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 non-exempt Qualifying Facilities;
•net energy metering; 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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Regulation of the Nuclear Power Industry
Atomic Energy Act of 1954 and Energy Reorganization Act of 1974
Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose civil penalties or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, Entergy Louisiana, and System Energy, as owners of all or portions of ANO, River Bend and Waterford 3, and Grand Gulf, respectively, and Entergy Operations, as the licensee and operator of these units, are subject to the jurisdiction of the NRC.
Nuclear Waste Policy Act of 1982
Spent Nuclear Fuel
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 Arkansas is the only one of the Utility operating companies that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 2022 of $195.0 million for the one-time fee. The fees payable to the DOE may be adjusted in the future to assure full recovery. 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. Entergy’s total spent fuel fees to date, including the one-time fee liability of Entergy Arkansas, have surpassed $1.7 billion (exclusive of amounts relating to Entergy plants that were paid or are owed by prior owners of those plants).
The permanent spent fuel repository in the U.S. has been legislated to be Yucca Mountain, Nevada. The DOE is required by law to proceed with the licensing (the DOE filed the license application in June 2008) and, after the license is granted by the NRC, proceed with the repository construction and commencement of receipt of spent fuel. 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. The DOE continues to delay meeting its obligation. Specific steps were taken to discontinue the Yucca Mountain project, including a motion to the NRC to withdraw the license application with prejudice and the establishment of a commission to develop recommendations for alternative spent fuel storage solutions. In August 2013 the U.S. Court of Appeals for the D.C. Circuit ordered the NRC to continue with the Yucca Mountain license review, but only to the extent of funds previously appropriated by Congress for that purpose and not yet used. Although the NRC completed the safety evaluation report for the license review in 2015, the previously appropriated funds are not limitedsufficient to complete the review, including required hearings. The government has taken no effective action to date related to the recommendations of the appointed spent fuel study commission. Accordingly, large uncertainty remains regarding the time frame under which the DOE will begin to accept spent fuel from Entergy’s facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at Entergy’s nuclear sites.
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 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
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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.
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. These subsidiaries have been, and continue to be, involved in litigation to recover the damages caused by the DOE’s delay in performance. See Note 8 to the financial statements for discussion of final judgments recorded by Entergy in 2020, 2021, and 2022 related to Entergy’s nuclear owner licensee subsidiaries’ litigation with the DOE. Through 2022, Entergy’s subsidiaries have won and collected on judgments against the government totaling approximately $1 billion.
Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are providing their own spent fuel storage. Storage capability additions using dry casks began operations at ANO in 1996, at River Bend in 2005, at Grand Gulf in 2006, and at Waterford 3 in 2011. These facilities will be expanded as needed.
Nuclear Plant Decommissioning
Entergy Arkansas, Entergy Louisiana, and System Energy are entitled to recover from customers through electric rates the estimated decommissioning costs for ANO, Waterford 3, and Grand Gulf, respectively. In addition, Entergy Louisiana and Entergy Texas are entitled to recover from customers through electric rates the estimated decommissioning costs for the portion of River Bend subject to retail rate regulation. The collections are deposited in trust funds that can only be used in accordance with NRC and other applicable regulatory requirements. Entergy periodically reviews and updates the estimated decommissioning costs to reflect inflation and changes in regulatory requirements and technology, and then makes applications to the regulatory authorities to reflect, in rates, the changes in projected decommissioning costs.
In December 2018 the APSC ordered collections in rates for decommissioning ANO 2 and found that ANO 1’s decommissioning was adequately funded without additional collections. In November 2021, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that both ANO 1 and 2 decommissioning trusts were adequately funded without further collections, and in December 2021 the APSC ordered zero collections for ANO 1 and 2 decommissioning. In November 2022, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that ANO 1’s decommissioning trust was adequately funded, but that ANO 2’s fund had a projected shortage as a result of a decline in decommissioning trust fund investment values over the past year. The filing proposes a reinstatement of decommissioning cost recovery for ANO 2. Management cannot predict the outcome of this filing.
In July 2010 the LPSC approved increased decommissioning collections for Waterford 3 and the Louisiana regulated share of River Bend to address previously identified funding shortfalls. This LPSC decision contemplated that the level of decommissioning collections could be revisited should the NRC grant license extensions for both Waterford 3 and River Bend. In July 2019, following the NRC approval of license extensions for Waterford 3 and River Bend, Entergy Louisiana made a filing with the LPSC seeking to adjust decommissioning and depreciation rates for those plants, including one proposed scenario that would adjust Louisiana-jurisdictional decommissioning collections to zero for both plants (including an offsetting increase in depreciation rates). Because of the ongoing public health emergency arising from the COVID-19 pandemic and accompanying economic uncertainty, Entergy Louisiana determined that the relief sought in the filing was no longer appropriate, and in November 2020, filed an unopposed motion to dismiss the proceeding. Following that filing, in a December 2020 order, the LPSC dismissed the proceeding without prejudice. In July 2021, Entergy Louisiana made a filing with the LPSC to adjust Waterford 3 and River Bend decommissioning collections based on the latest site-specific decommissioning cost estimates for those plants. The filing seeks to increase Waterford 3 decommissioning collections and decrease River Bend decommissioning collections. The procedural schedule in the case has been suspended pending settlement negotiations. Management cannot predict the outcome of this section. Therefiling.
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In December 2010 the PUCT approved increased decommissioning collections for the Texas share of River Bend to address previously identified funding shortfalls. In December 2018 the PUCT approved a settlement that eliminated River Bend decommissioning collections for the Texas jurisdictional share of the plant based on a determination by Entergy Texas that the existing decommissioning fund was adequate following license renewal. In July 2022, Entergy Texas filed a rate case that proposed continuation of the cessation of River Bend decommissioning collections. In December 2022, Entergy Texas filed on behalf of the parties a motion to abate the hearing on the merits to give parties additional time to finalize a settlement, which was approved by the presiding ALJ along with an order for the parties to file monthly settlement status reports. Management cannot predict the outcome of this filing.
In December 2016 the NRC issued a 20-year operating license renewal for Grand Gulf. In a 2017 filing at the FERC, System Energy stated that with the renewed operating license, Grand Gulf’s decommissioning trust was sufficiently funded, and proposed, among other things, to cease decommissioning collections for Grand Gulf effective October 1, 2017. The FERC accepted a settlement including the proposed decommissioning revenue requirement by letter order in August 2018.
Entergy currently believes its decommissioning funding will be sufficient for its nuclear plants subject to retail rate regulation, although decommissioning cost inflation and trust fund performance will ultimately determine the adequacy of the funding amounts.
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. In March 2021 filings with the NRC were made reporting on decommissioning funding for all of Entergy’s subsidiaries’ nuclear plants. Those reports showed that decommissioning funding for each of the nuclear plants met the NRC’s financial assurance requirements.
Additional information with respect to Entergy’s decommissioning costs and decommissioning trust funds is found in Note 9 and Note 16 to the financial statements.
Price-Anderson Act
The Price-Anderson Act requires that reactor licensees purchase and maintain the maximum amount of nuclear liability insurance available and participate in an industry assessment program called Secondary Financial Protection in order to protect 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 limits the contingent liability for a single nuclear incident to a maximum assessment of approximately $137.6 million per reactor (with 96 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, Entergy Louisiana, or System Energy is liable, protection is afforded through a combination of private insurance and the Secondary Financial Protection program. In addition to this, insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units is also purchased. The Price-Anderson Act and uncertainties (eitherinsurance applicable to the nuclear programs of Entergy are discussed in more detail in Note 8 to the financial statements.
NRC Reactor Oversight Process
The NRC’s Reactor Oversight Process is a program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response. The NRC evaluates plant performance by analyzing two distinct inputs: inspection findings resulting from the NRC’s inspection program and performance indicators reported by the licensee. The evaluations result in the placement of
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each plant in one of the NRC’s Reactor Oversight Process Action Matrix columns: “licensee response column,” or Column 1, “regulatory response column,” or Column 2, “degraded cornerstone column,” or Column 3, and “multiple/repetitive degraded cornerstone column,” or Column 4, and “unacceptable performance,” or Column 5. Plants in Column 1 are subject to normal NRC inspection activities. Plants in Column 2, Column 3, or Column 4 are subject to progressively increasing levels of inspection by the NRC. Continued plant operation is not permitted for plants in Column 5. All of the nuclear generating plants owned and operated by Entergy’s Utility business are currently unknownin Column 1, except Waterford 3, which is in Column 2.
In September 2022 the NRC placed Waterford 3 in Column 2 based on an error associated with a radiation monitor calibration. Entergy corrected the issue with the radiation monitor in February 2022; however, Waterford 3 is expected to remain in Column 2 until third quarter 2023 based on a subsequent radiation monitor calibration issue.
Environmental Regulation
Entergy’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy’s businesses are in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted below. Because environmental regulations are subject to change, future compliance requirements and costs cannot be precisely estimated. Except to the extent discussed below, at this time compliance with federal, state, and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of Entergy’s businesses and is not currently believedexpected to be material) that could adversely affect Entergy’s financial condition,have a material effect on their competitive position, results of operations, cash flows, or financial position.
Clean Air Act and liquidity.Subsequent Amendments
The Clean Air Act and its amendments establish several programs that currently or in the future may affect Entergy’s fossil-fueled generation facilities and, to a lesser extent, certain operations at nuclear and other facilities. Individual states also operate similar independent state programs or delegated federal programs that may include requirements more stringent than federal regulatory requirements. These programs include:
•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.
National Ambient Air Quality Standards
The Clean Air Act requires the EPA to set National Ambient Air Quality Standards (NAAQS) for ozone, carbon monoxide, lead, nitrogen dioxide, particulate matter, and sulfur dioxide, and requires periodic review of those standards. When an area fails to meet an ambient standard, it is considered to be in nonattainment and is classified as “marginal,” “moderate,” “serious,” or “severe.” When an area fails to meet the ambient air standard, the EPA requires state regulatory authorities to prepare state implementation plans meant to cause progress toward bringing the area into attainment with applicable standards.
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Ozone Nonattainment
Entergy Texas operates two fossil-fueled generating facilities (Lewis Creek and Montgomery County Power Station) in a geographic area that is not in attainment with the applicable NAAQS for ozone. The ozone nonattainment area that affects Entergy Texas is the Houston-Galveston-Brazoria area. Both Lewis Creek and the Montgomery County Power Station hold all necessary permits for operation and comply with applicable air quality program regulations. Measures enacted to return the area to ozone attainment could make these program regulations more stringent. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and nonattainment with the ozone NAAQS.
Potential SO2Nonattainment
The EPA issued a final rule in June 2010 adopting an SO2 1-hour national ambient air quality standard of 75 parts per billion. In Entergy’s utility service territory, only St. Bernard Parish and Evangeline Parish in Louisiana are designated as nonattainment. In August 2017 the EPA issued a letter indicating that East Baton Rouge and St. Charles parishes would be designated by December 31, 2020, as monitors were installed to determine compliance. In March 2021 the EPA published a final rule designating East Baton Rouge, St. Charles, St. James, and West Baton Rouge parishes in Louisiana as attainment/unclassifiable, and, in Texas, Jefferson County as attainment/unclassifiable and Orange County as unclassifiable. No challenges to these final designations were filed within the 60 day deadline. Entergy continues to monitor this situation.
Hazardous Air Pollutants
The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011, which had a compliance date, with a widely granted one-year extension, of April 2016. The required controls have been installed and are operational at all affected Entergy units. In May 2020 the EPA finalized a rule that finds that it is not “appropriate and necessary” to regulate hazardous air pollutants from electric steam generating units under the provisions of section 112(n) of the Clean Air Act. This is a reversal of the EPA’s previous finding requiring such regulation. The final appropriate and necessary finding does not revise the underlying MATS rule. Several lawsuits have been filed challenging the appropriate and necessary finding. In February 2021 the D.C. Circuit granted the EPA’s motion to hold the litigation in abeyance pending the agency’s review of the appropriate and necessary rule. In February 2022 the EPA issued a proposed rule revoking the 2020 rule and determining, again, that it is “appropriate and necessary” to regulate hazardous air pollutants. The EPA is seeking additional information, which it could use to further tighten the standard. Entergy will continue to monitor this situation.
Cross-State Air Pollution
In March 2005 the EPA finalized the Clean Air Interstate Rule (CAIR), which was intended to reduce SO2 and NOx emissions from electric generation plants in order to improve air quality in twenty-nine eastern states. The rule required a combination of capital investment to install pollution control equipment and increased operating costs through the purchase of emission allowances. Entergy began implementation in 2007, including installation of controls at several facilities and the development of an emission allowance procurement strategy. Based on several court challenges, CAIR and its subsequent versions, now known as the Cross-State Air Pollution Rule (CSAPR), have been remanded to and modified by the EPA on multiple occasions.
In April 2022 the EPA published a rule to address interstate transport for the 2015 ozone NAAQS which will increase the stringency of the CSAPR program in all four of the states where the Utility operating companies operate. If finalized as proposed, the rule will significantly reduce emission allowances and would likely require the installation of post-combustion nitrogen oxides (NOx) emissions controls on any coal or large legacy gas units that will operate beyond 2026 and are not currently equipped with such controls. Fifteen Entergy-owned units, totaling approximately 9,370 MW of total unit capacity, are identified by the EPA for selective catalytic reduction retrofits.
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Based on the EPA estimates, Entergy’s share of the capital costs would be approximately $1.6 billion if all the identified units were in fact retrofitted. Additionally, the EPA is proposing controls on certain non-electric generating NOx sources. Since releasing the proposed rule, the price for Group 3 NOx sources allowances has increased significantly, peaking at over $45,000 per allowance in late August 2022 before stabilizing in the range of $15,000 to $18,000 per allowance since September 2022. Comments on the proposed rule were due in June 2022. MISO, other impacted regional transmission organizations, and various state public service commissions all filed comments expressing reliability concerns if the rule is finalized as proposed. Entergy filed individual comments which assert, in addition to other issues, that the EPA’s proposal represents over-control of the Entergy units in Arkansas and Mississippi; the EPA should consider an alternative approach or provide flexibility for units with a limited remaining useful life; the EPA should consult with regional transmission organizations to determine the reliability impacts of the proposed rule; and the EPA should consider and incorporate current economic trends, including inflation, into any benefit-costs analysis supporting the rule.
Regional Haze
In June 2005 the EPA issued its final Clean Air Visibility Rule (CAVR) regulations that potentially could result in a requirement to install SO2 and NOx pollution control technology as Best Available Retrofit Control Technology to continue operating certain of Entergy’s fossil generation units. The rule leaves certain CAVR determinations to the states. This rule establishes a series of 10-year planning periods, with states required to develop State Implementation Plans (SIPs) for each planning period, with each SIP including such air pollution control measures as may be necessary to achieve the ultimate goal of the CAVR by the year 2064. The various states are currently in the process of developing SIPs to implement the second planning period of the CAVR, which addresses the 2018-2028 planning period.
In January and February 2018, Entergy Arkansas, Entergy Mississippi, Entergy Power, and other co-owners received 60-day notice of intent to sue letters from the Sierra Club and the National Parks Conservation Association concerning allegations of violations of new source review and permitting provisions of the Clean Air Act at the Independence and White Bluff coal-burning units, respectively. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims and reducing the risk that Entergy Arkansas, as operator of Independence and White Bluff, might be compelled under the Clean Air Act’s regional haze program to install costly emissions control technologies. Consistent with the terms of the settlement, Entergy Arkansas, along with co-owners, agreed to begin using only low-sulfur coal at Independence and White Bluff by mid-2021; agreed to cease using coal at White Bluff and Independence by the end of 2028 and 2030, respectively; agreed to cease operation of the remaining gas unit at Lake Catherine by the end of 2027; reserved the option to develop new generating sources at each plant site; and committed to installing or proposing to regulators at least 800 MWs of renewable generation by the end of 2027, with at least half installed or proposed by the end of 2022 (which includes two existing Entergy Arkansas projects) and with all qualifying co-owner projects counting toward satisfaction of the obligation. Under the settlement, the Sierra Club and the National Parks Conservation Association also waived certain potential existing claims under federal and state environmental law with respect to specified generating plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the National Parks Conservation Association, was subject to approval by the U.S. District Court for the Eastern District of Arkansas. In November 2020 the court denied motions by the Arkansas Attorney General and the Arkansas Affordable Energy Coalition to intervene and to stay the proceedings. The proposed intervenors did not appeal the ruling. The District Court approved and entered the proposed settlement in March 2021. Entergy met the settlement deadline to use low-sulfur coal and is on target to meet the other requirements of the settlement. See “FORWARD-LOOKING INFORMATIONRemaining Useful Lives Review.” in the “State and Local Rate Regulation and Fuel-Cost Recovery” section of Entergy Arkansas, LLC and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the APSC’s proceeding related to Entergy Arkansas’s utility generation units.
The second planning period (2018-2028) for the regional haze program requires states to examine sources for impacts on visibility and to prepare SIPs by July 31, 2021 to ensure reasonable progress is being made to attain
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visibility improvements. Entergy received information collection requests from the Arkansas and Louisiana Departments of Environmental Quality requesting an evaluation of technical and economic feasibility of various NOx and SO2 control technologies for Independence, Nelson 6, Nelson Industrial Steam Company (NISCO), and Ninemile. Responses to the information collection requests have been submitted to the respective state agencies. Louisiana has issued its draft SIP which, at this time, does not propose any additional air emissions controls for the affected Entergy units in Louisiana. Some public commenters, however, believe additional air controls are cost-effective. It is not yet clear how the Louisiana Department of Environmental Quality (LDEQ) will respond in its final SIP, and the agency, like many other state agencies, did not meet the July 31, 2021 deadline to submit a SIP to the EPA for review.
Similar to the LDEQ, the Arkansas Department of Energy and Environment, Division of Environmental Quality (ADEQ) did not meet the July 31, 2021 SIP submission deadline, but subsequently submitted it to the EPA for review. The ADEQ reviewed Entergy’s Independence plant, but determined that additional air emission controls would not be cost-effective considering the facility’s commitment to cease coal-fired combustion by December 31, 2030.
The Texas Commission on Environmental Quality has completed its second-planning period SIP and submitted it to the EPA for review. There were no Entergy sources selected for additional emission controls. The Mississippi Department of Environmental Quality continues to develop its SIP, but there are no Entergy sources that are expected to be impacted.
In August 2022 the EPA issued findings of failure to submit regional haze SIPs to 15 states, including Louisiana and Mississippi. These findings were effective September 2022 and start the two-year period for the EPA to either approve a SIP submitted by the state or issue a final federal plan.
Greenhouse Gas Emissions
In July 2019 the EPA released the Affordable Clean Energy Rule (ACE), which applies only to existing coal-fired electric generating units. The ACE determines that heat rate improvements are the best system of emission reductions and lists six candidate technologies for consideration by states at each coal unit. The rule and associated rulemakings by the EPA replace the Obama administration’s Clean Power Plan, which established national emissions performance rates for existing fossil-fuel fired steam electric generating units and combustion turbines. The ACE rule provides states discretion in determining how the best system for emission reductions applies to individual units, including through the consideration of technical feasibility and the remaining useful life of the facility. The ADEQ and the LDEQ have issued information collection requests to Entergy facilities to help the states collect the information needed to determine the best system of emission reductions for each facility. Entergy responded to the requests. In January 2021 the U.S. Court of Appeals for the D.C. Circuit vacated ACE. The court held that ACE relied on an incorrect interpretation of the Clean Air Act that the statute expressly forecloses emission reduction approaches, such as emissions trading and generating shifting, that cannot be applied at and to the individual source. The court remanded ACE to the EPA for further consideration and also vacated the repeal of the Clean Power Plan. In March 2021 the D.C. Circuit issued a partial mandate vacating the ACE rule, but withheld the mandate vacating the repeal of the Clean Power Plan pending the EPA’s new rulemaking to regulate greenhouse gas emissions. Thus, there currently is no regulation in place with respect to greenhouse gas emissions from existing electric generating units and states are not expected to take further action to develop and submit plans at this time. In October 2021 the United States Supreme Court agreed to hear a challenge to the already vacated ACE rule. In June 2022 the United States Supreme Court held that the EPA could not use generation shifting as the best system of emission reduction under Section 111(d) of the Clean Air Act. The EPA does still have the authority to regulate greenhouse gas emissions, but those emissions reductions must be technology based. The EPA has announced its intent to propose a rule for existing power plants pursuant to the Clean Air Act by March 2023. The ultimate impact of the United States Supreme Court's decision cannot be determined at this time.
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Entergy Corporation, Utility operating companies, and System Energy
In April 2021, President Biden announced a target for the United States in connection with the United Nations’ “Paris Agreement” on climate change. The target consists of a 50-52 percent reduction in economy-wide net greenhouse gas emissions from 2005 levels by 2030. President Biden has also stated that a goal of his administration is for the electric power industry to decarbonize fully by 2035. The details surrounding implementation of these targets are not finalized, and the impacts to Entergy of any potential related legislation cannot be predicted.
Entergy continues to support national legislation that would most efficiently reduce economy-wide greenhouse gas emissions and increase planning certainty for electric utilities. By virtue of its proportionally large investment in low-emitting generation technologies, Entergy has a low overall carbon dioxide emission “intensity,” or rate of carbon dioxide emitted per megawatt-hour of electricity generated. In anticipation of the imposition of carbon dioxide emission limits on the electric industry, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included a formal program to stabilize owned power plant carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in reducing emissions below 2000 levels. In 2006, Entergy started including emissions from controllable power purchases in addition to its ownership share of generation and established a second formal voluntary program to stabilize power plant carbon dioxide emissions and emissions from controllable power purchases, cumulatively over the period, at 20% below 2000 levels through 2010. In 2011, Entergy extended this commitment through 2020, which it ultimately outperformed by approximately 8% both cumulatively and on an annual basis. In 2019, in connection with a climate scenario analysis following the recommendations of the Task Force on Climate-related Financial Disclosures describing climate-related governance, strategy, risk management, and metrics and targets, Entergy announced a 2030 carbon dioxide emission rate goal focused on a 50% reduction from Entergy’s base year - 2000. Entergy now anticipates achieving this reduction several years early. In September 2020, Entergy announced a commitment to achieve net-zero greenhouse gas emissions by 2050 inclusive of all businesses, all applicable gases, and all emission scopes. In 2022, Entergy enhanced its commitment to include an interim goal of 50% carbon-free energy generating capacity by 2030 and expanded its interim emission rate goal to include all purchased power. See “Risk Factors” in Part I Item 1A for discussion of the risks associated with achieving these climate goals. Entergy’s comprehensive, third-party verified greenhouse gas inventory and progress against its voluntary goals are published on its website.
Entergy participates in the M.J. Bradley & Associates’ Annual Benchmarking Air Emissions Report, an annual analysis of the 100 largest U.S. electric power producers. The report is available on the M.J. Bradley website. Entergy participates annually in the Dow Jones Sustainability Index and in 2022 was listed on the North American Index. Entergy has been listed on the World or North American Index, or both, for 21 consecutive years. Entergy also participated in the 2022 CDP Climate Change and CDP Water Security evaluations, receiving a ‘B’ for both responses.
Potential Legislative, Regulatory, and Judicial Developments
In addition to the specific instances described above, there are a number of legislative and regulatory initiatives that are under consideration at the federal, state, and local level. Because of the nature of Entergy’s business, the imposition of any of these initiatives could affect Entergy’s operations. Entergy continues to monitor these initiatives and activities in order to analyze their potential operational and cost implications. These initiatives include:
•reconsideration and revision of ambient air quality standards downward which could lead to additional areas of nonattainment;
•designation by the EPA and state environmental agencies of areas that are not in attainment with national ambient air quality standards;
•introduction of bills in Congress and development of regulations by the EPA proposing further limits on SO2, mercury, carbon dioxide, and other air emissions. New legislation or regulations applicable to
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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 cap and trade programs to limit carbon dioxide and other greenhouse gases;
•efforts on the local, 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 polychlorinated biphenyls (PCBs);
•efforts by certain external groups to encourage reporting and disclosure of environmental, social, and governance 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;
•the regulation of the management, disposal, and beneficial reuse of coal combustion residuals; and
•the regulation of the management and disposal and recycling of equipment associated with renewable and clean energy sources such as used solar panels, wind turbine blades, hydrogen usage, or battery storage.
Clean Water Act
The 1972 amendments to the Federal Water Pollution Control Act (known as the Clean Water Act) provide the statutory basis for the National Pollutant Discharge Elimination System permit program, section 402, and the basic structure for regulating the discharge of pollutants from point sources to waters of the United States. The Clean Water Act requires virtually all discharges of pollutants to waters of the United States to be permitted. Section 316(b) of the Clean Water Act regulates cooling water intake structures, section 401 of the Clean Water Act requires a water quality certification from the state in support of certain federal actions and approvals, and section 404 regulates the dredge and fill of waters of the United States, including jurisdictional wetlands.
Federal Jurisdiction of Waters of the United States
In June 2020 the EPA’s revised definition of waters of the United States in the Navigable Waters Protection Rule (NWPR) became effective, narrowing the scope of Clean Water Act jurisdiction, as compared to a 2015 definition which had been stayed by several federal courts. In August 2021 a federal district court vacated and remanded the NWPR for further consideration. The EPA and the U.S. Army Corps of Engineers (Corps) subsequently issued a statement that the agencies would revert to pre-2015 regulations pending a new rulemaking. In December 2022 the EPA and the Corps released a final definition of waters of the United States that replaces the NWPR with a definition that is consistent with the pre-2015 regulatory regime as interpreted by several United States Supreme Court decisions. Most notably, the exclusion for waste treatment systems is retained.
Comprehensive Environmental Response, Compensation, and Liability Act of 1980
The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), authorizes the EPA to mandate clean-up by, or to collect reimbursement of clean-up costs from, owners or operators of sites at which hazardous substances may be or have been released. Certain private parties also may use CERCLA to recover response costs. Parties that transported hazardous substances to these sites or arranged for the disposal of the substances are also deemed liable by CERCLA. CERCLA has been interpreted to impose strict, joint, and several liability on responsible parties. Many states have adopted programs similar to CERCLA. Entergy subsidiaries in the Utility and Entergy Wholesale Commodities businesses have sent waste materials to various
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disposal sites over the years, and releases have occurred at Entergy facilities including nuclear facilities that have been or will be sold to decommissioning companies. In addition, environmental laws now regulate certain of Entergy’s operating procedures and maintenance practices that historically were not subject to regulation. Some disposal sites used by Entergy subsidiaries have been the subject of governmental action under CERCLA or similar state programs, resulting in site clean-up activities. Entergy subsidiaries have participated to various degrees in accordance with their respective potential liabilities in such site clean-ups and have developed experience with clean-up costs. The affected Entergy subsidiaries have established provisions for the liabilities for such environmental clean-up and restoration activities. Details of potentially material CERCLA and similar state program liabilities are discussed in the “Other Environmental Matters” section below.
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. As of December 31, 2022, Entergy has recorded asset retirement obligations related to CCR management of $27 million.
Pursuant to the EPA Rule, Entergy operates groundwater monitoring systems surrounding its coal combustion residual landfills located at White Bluff, Independence, and Nelson. Monitoring to date has detected concentrations of certain listed constituents in the area, but has not indicated that these constituents originated at the active landfill cells. Reporting has occurred as required, and detection monitoring will continue as the rule requires. In late-2017, Entergy determined that certain in-ground wastewater treatment system recycle ponds at its White Bluff and Independence facilities require management under the new EPA regulations. Consequently, in order to move away from using the recycle ponds, White Bluff and Independence each have installed a new permanent bottom ash handling system that does not fall under the CCR rule. As of November 2020, both sites are operating the new system and no longer are sending waste to the recycle ponds. Each site has commenced closure of its two recycle ponds (four ponds total), prior to the April 11, 2021 deadline under the finalized CCR rule for unlined recycle ponds. Any potential requirements for corrective action or operational changes under the new CCR rule continue to be assessed. Notably, ongoing litigation has resulted in the EPA’s continuing review of the rule. Consequently, the nature and cost of additional corrective action requirements may depend, in part, on the outcome of the EPA’s review.
Utility Regulatory Risks
•The terms and conditions of service, including electric and gas rates, of the Utility operating companies and System Energy are determined through regulatory approval proceedings that can be lengthy and subject to appeal, potentially resulting in lengthy litigation, and uncertainty as to ultimate results.
•Entergy’s business could experience adverse effects related to changes to state or federal legislation or regulation.
•The Utility operating companies recover fuel, purchased power, and associated costs through rate mechanisms that are subject to risks of delay or disallowance in regulatory proceedings.
•The Utility operating companies are subject to risks associated with participation in the MISO markets and the allocation of transmission upgrade costs.
•The continued impacts of the COVID-19 pandemic and responsive measures taken are highly uncertain and cannot be predicted.
•A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather could have material effects on Entergy and its Utility operating companies affected by severe weather.
•Weather, economic conditions, technological developments, and other factors may have a material impact on electricity and gas usage and otherwise materially affect the Utility operating companies’ results of operations.
Nuclear Operating, Shutdown, and Regulatory Risks
•The results of operations, financial condition, and liquidity of Entergy Arkansas, Entergy Louisiana, and System Energy could be materially affected by the following:
◦inability to consistently operate their nuclear power plants at high capacity factors;
◦refueling outages that last materially longer than anticipated or unplanned outages;
◦risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication);
◦the risk that the NRC will change or modify its regulations, suspend or revoke their licenses, or increase oversight of their nuclear plants;
◦risks and costs related to operating and maintaining their nuclear power plants;
◦the costs associated with the storage of the spent nuclear fuel, as well as the costs of and their ability to fully decommission their nuclear power plants;
◦the potential requirement to pay substantial retrospective premiums imposed under the Price-Anderson Act and/or by Nuclear Electric Insurance Limited (NEIL) in the event of a nuclear incident, and losses not covered by insurance;
◦the risk that the decommissioning trust fund assets for the nuclear power plants may not be adequate to meet decommissioning obligations if market performance and other changes decrease the value of assets in the decommissioning trusts; and
◦new or existing safety concerns regarding operating nuclear power plants and nuclear fuel.
General Business Risks
•Entergy and the Registrant Subsidiaries depend on access to the capital markets and, at times, may face potential liquidity constraints, which could make it more difficult to handle future contingencies. Disruptions in the capital and credit markets may adversely affect Entergy’s and its subsidiaries’ ability to meet liquidity needs, access capital and operate and grow their businesses, and the cost of capital.
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•A downgrade in Entergy’s or its Registrant Subsidiaries’ credit ratings could, among other things, negatively affect Entergy’s and its Registrant Subsidiaries’ ability to access capital and the cost of such capital.
•Entergy or its Registrant Subsidiaries may be materially adversely affected by negative publicity or the inability to meet their stated goals or commitments, among other potential causes.
•Changes in tax legislation and taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy’s and the Registrant Subsidiaries’ results of operations, financial condition, and liquidity.
•Entergy and its subsidiaries’ ability to successfully execute on their business strategies, including their ability to complete capital projects, other capital improvements, and strategic transactions, is subject to significant risks, and, as a result, they may be unable to achieve some or all of the anticipated results of such strategies.
•Failure to attract, retain, and manage an appropriately qualified workforce could negatively affect Entergy or its subsidiaries’ results of operations.
•Entergy and Entergy’s subsidiaries, including the Utility operating companies and System Energy, may incur substantial costs (i) to fulfill their obligations related to environmental and other matters or (ii) related to reliability standards.
•Entergy could be negatively affected by the effects of climate change, including physical risks, such as increased frequency and intensity of hurricanes and other severe weather, and transition risks, such as environmental and regulatory obligations intended to combat the effects of climate change, including by compelling greenhouse gas emission reductions or reporting, or increasing clean or renewable energy requirements, or placing a price on greenhouse gas emissions.
•Entergy and its subsidiaries are dependent on the continued and future availability and quality of water for cooling, process, and sanitary uses.
•Entergy and its subsidiaries may not be adequately hedged against changes in commodity prices.
•The Utility operating companies and Entergy’s non-regulated operations are exposed to the risk that counterparties may not meet their obligations.
•Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding and result in increased benefit plan costs.
•The litigation environment in the states in which the Registrant Subsidiaries operate poses a significant risk to those businesses.
•Terrorist attacks, physical attacks, cyber attacks, system failures, or data breaches of Entergy’s and its subsidiaries’ or their suppliers’ physical infrastructure or technology systems may adversely affect Entergy’s results of operations.
•Entergy and the Registrant Subsidiaries are subject to risks associated with their ability to obtain adequate insurance at acceptable costs.
•Significant increases in commodity prices, other materials and supplies, and operation and maintenance expenses may adversely affect Entergy’s results of operations, financial condition, and liquidity.
•The effect of higher purchased gas cost charges to customers taking gas service may adversely affect Entergy New Orleans’s results of operations and liquidity.
•System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on sales to affiliated companies for all of its revenues. Certain contractual arrangements relating to System Energy, the affiliated companies, and these revenues are the subject of ongoing litigation and regulatory proceedings. The aggregate amount of refunds claimed in these proceedings substantially exceeds the current net book value of System Energy. In the event of an adverse decision in one or more of these proceedings requiring the payment of substantial additional refunds, System Energy would be required to seek financing to pay such refunds, which financing may not be available on terms acceptable to System Energy, or may not be available at all, when required. If one or more of the foregoing events occurs, System Energy may be required to explore other options or protections available to it to extend, restructure, or retire its indebtedness and to prioritize its obligations.
•Entergy’s non-regulated operations are subject to substantial governmental regulation and may be adversely affected by legislative, regulatory, or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
•As a holding company, Entergy Corporation depends on cash distributions from its subsidiaries to meet its debt service and other financial obligations and to pay dividends on its common stock, and has provided, and may continue to provide, capital contributions or debt financing to its subsidiaries, which would reduce the funds available to meet its other financial obligations.
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Entergy Corporation, Utility operating companies, and System Energy
ENTERGY’S BUSINESS
Entergy is an integrated energy company engaged primarily in electric power production and retail distribution operations. Entergy owns and operates power plants with approximately 24,000 MW of electric generating capacity, including approximately 5,000 MW of nuclear power. Entergy delivers electricity to 3 million utility customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy had annual revenues of $13.8 billion in 2022 and had approximately 12,000 employees as of December 31, 2022.
Entergy operates primarily through two business segments: Utility and Entergy Wholesale Commodities.
•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 shutdown and sale of each of the Entergy Wholesale Commodities nuclear power plants. With the sale of Palisades in June 2022, Entergy completed its multi-year strategy to exit the merchant nuclear power business. Upon completion of all transition activities, effective January 1, 2023, Entergy Wholesale Commodities is no longer a reportable business segment.
See Note 13 to the financial statements for financial information regarding Entergy’s business segments.
Strategy
Entergy’s strategy is to operate and grow its utility business, creating sustainable value for its customers, employees, communities, and owners. Entergy’s strategy to achieve its stakeholder objectives has a few key aspects. First, Entergy invests in the Utility for the benefit of its customers, which supports steady, predictable growth in earnings and dividends. Second, Entergy manages risks by ensuring its Utility investments are customer-centric, supported by progressive regulatory constructs, and executed with disciplined project management. Third, Entergy is committed to delivering sustainable outcomes for all of its stakeholders by focusing on continually improving key elements of Environmental, Social, and Governance (ESG), including reducing carbon emissions and improving resilience for Entergy and its customers. Entergy also executed the wind down of the Entergy Wholesale Commodities merchant nuclear generation business, which was effectively complete by the end of 2022.
Utility
The Utility business segment includes five retail electric utility subsidiaries: Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas. These companies generate, transmit, distribute, and sell electric power to retail and wholesale customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy Louisiana and Entergy New Orleans also provide natural gas utility services to customers in and around Baton Rouge, Louisiana, and New Orleans, Louisiana, respectively. Also included in the Utility is System Energy, a wholly-owned subsidiary of Entergy Corporation that owns or leases 90 percent of Grand Gulf. System Energy sells its power and capacity from Grand Gulf at wholesale to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. The five retail utility subsidiaries are each regulated by the FERC and by state utility commissions, or, in the case of Entergy New Orleans, the City Council. System Energy is regulated by the FERC because all of its transactions are at wholesale. The Utility has a diverse power generation portfolio, including increasingly carbon-free energy sources, which is consistent with Entergy’s strong support for the environment.
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Customers
As of December 31, 2022, the Utility operating companies provided retail electric and gas service to customers in Arkansas, Louisiana, Mississippi, and Texas, as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Electric Customers | | Gas Customers |
| | Area Served | | (In Thousands) | | (%) | | (In Thousands) | | (%) |
| Entergy Arkansas | Portions of Arkansas | | 730 | | | 24 | % | | | | |
| Entergy Louisiana | Portions of Louisiana | | 1,101 | | | 37 | % | | 95 | | | 47 | % |
| Entergy Mississippi | Portions of Mississippi | | 461 | | | 15 | % | | | | |
| Entergy New Orleans | City of New Orleans | | 211 | | | 7 | % | | 109 | | | 53 | % |
| Entergy Texas | Portions of Texas | | 499 | | | 17 | % | | | | |
| Total customers | | | 3,002 | | | 100 | % | | 204 | | | 100 | % |
Electric and Natural Gas Energy Sales
Electric Energy Sales
The total electric energy sales of the Utility operating companies are subject to seasonal fluctuations, with the peak sales period normally occurring during the third quarter of each year. On June 24, 2022, Entergy reached a 2022 peak demand of 22,301 MWh, compared to the 2021 peak of 22,051 MWh recorded on August 23, 2021. Selected electric energy sales data for 2022 is shown in the table below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | | Entergy (a) |
| | (GWh) |
| Sales to retail customers | 22,473 | | | 57,532 | | | 13,038 | | | 5,706 | | | 21,380 | | | — | | | 120,129 | |
| Sales for resale: | | | | | | | | | | | | | |
| Affiliates | 1,906 | | | 5,416 | | | — | | | — | | | 279 | | | 7,739 | | | — | |
| Others | 6,520 | | | 3,423 | | | 2,914 | | | 2,298 | | | 813 | | | — | | | 15,968 | |
| Total | 30,899 | | | 66,371 | | | 15,952 | | | 8,004 | | | 22,472 | | | 7,739 | | | 136,097 | |
| Average use per residential customer (kWh) | 13,478 | | | 14,874 | | | 14,791 | | | 12,818 | | | 15,444 | | | — | | | 14,479 | |
(a)Includes the effect of intercompany eliminations.
The following table illustrates the Utility operating companies’ 2022 combined electric sales volume as a percentage of total electric sales volume, and 2022 combined electric revenues as a percentage of total 2022 electric revenue, each by customer class.
| | | | | | | | | | | | | | |
| Customer Class | | % of Sales Volume | | % of Revenue |
| Residential | | 27.3 | | 35.2 |
| Commercial | | 20.6 | | 23.4 |
| Industrial (a) | | 38.6 | | 28.2 |
| Governmental | | 1.8 | | 2.2 |
| Wholesale/Other | | 11.7 | | 11.0 |
(a)Major industrial customers are primarily in the petroleum refining and chemical industries.
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Entergy Corporation, Utility operating companies, and System Energy
Natural Gas Energy Sales
Entergy New Orleans and Entergy Louisiana provide both electric power and natural gas to retail customers. Entergy New Orleans and Entergy Louisiana sold 10,514,012 and 6,786,779 Mcf, respectively, of natural gas to retail customers in 2022. In 2022, 99% of Entergy Louisiana’s operating revenue was derived from the electric utility business and only 1% from the natural gas distribution business. For Entergy New Orleans, 86% of operating revenue was derived from the electric utility business and 14% from the natural gas distribution business in 2022.
Following is data concerning Entergy New Orleans’s 2022 retail operating revenue sources:
| | | | | | | | | | | | | | |
| Customer Class | | % of Electric Operating Revenue | | % of Natural Gas Operating Revenue |
| Residential | | 47 | | 47 |
| Commercial | | 36 | | 26 |
| Industrial | | 5 | | 19 |
| Governmental/Municipal | | 12 | | 8 |
Retail Rate Regulation
General (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, System Energy)
Each Utility operating company regularly participates in retail rate proceedings. The status of material retail rate proceedings is described in Note 2 to the financial statements. Certain aspects of the Utility operating companies’ retail rate mechanisms are discussed below.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Rate base (in billions) | | Current authorized return on common equity | | Weighted average cost of capital (after-tax) | | Equity ratio | | Regulatory construct | |
| | | | | | | | | | | |
| Entergy Arkansas | | $9.2 (a) | | 9.15% - 10.15% | | 5.25% | | 37.8% (b) | | - forward test year formula rate
plan
- riders: MISO, capacity, Grand Gulf,
energy efficiency, fuel and
purchased power | |
| | | | | | | | | | | |
| Entergy Louisiana (electric) | | $14.4 (c) | | 9.0% - 10.0% | | 6.62% | | 49.41% | | - formula rate plan through 2022
test year
- riders/specific recovery: MISO,
capacity, transmission, fuel,
distribution | |
| | | | | | | | | | | |
| Entergy Louisiana (gas) | | $0.13 (d) | | 9.3% - 10.3% | | 6.76% | | 49.03% | | - gas rate stabilization plan
- rider: gas infrastructure | |
| | | | | | | | | | | |
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Mississippi | | $4.0 (e) | | 9.19% - 11.37% | | 6.71% | | 45.9% | | - formula rate plan with forward-looking features
- riders: power management, Grand Gulf, fuel, MISO, unit power cost, storm damage, ad valorem tax adjustment, vegetation, grid modernization, restructuring credit | |
| | | | | | | | | | | |
| Entergy New Orleans (electric) | | $1.2 (f) | | 8.85% -
9.85% | | 6.88% | | 51% | | - formula rate plan with forward-looking features
- riders/specific recovery: fuel and purchased power, MISO, energy efficiency, environmental, capacity | |
| | | | | | | | | | | |
| Entergy New Orleans (gas) | | $0.2 (f) | | 8.85% -
9.85% | | 6.88% | | 51% | | - formula rate plan with forward-looking features
- rider: purchased gas | |
| | | | | | | | | | | |
| Entergy Texas | | $2.4 (g) | | 9.65% | | 7.73% | | 50.90% | | - rate case
- riders: fuel, capacity, cost recovery
(distribution, transmission, and
generation), rate case expenses,
AMI surcharge, tax reform, among
others | |
| | | | | | | | | | | |
| System Energy | | $1.67 (h) | | 10.94% (i) | | 8.04 % | | 61% (i) | | - monthly cost of service | |
(a)Based on 2023 test year.
(b)Based on $1.9 billion in accumulated deferred income taxes at a 0% cost rate included in the weighted average cost of capital calculation.
(c)Based on December 31, 2021 test year and includes approximately $800 million for the Lake Charles Power Station and excludes $250 million for the Washington Parish Energy Center included in the capacity rider, $400 million of transmission plant investment included in the transmission rider, and $200 million of distribution investment included in the distribution rider.
(d)Based on September 30, 2021 test year.
(e)Based on 2022 forward test year.
(f)Based on December 31, 2021 test year and known and measurables through December 31, 2022.
(g)Based on December 31, 2017 test year and excludes $1.7 billion in cost recovery riders.
(h)Based on calculation as of December 31, 2022.
(i)Effective July 2022, Entergy Mississippi’s bills from System Energy reflect an authorized return on equity of 9.65%, a capital structure not to exceed 52% equity, a rate base reduction for the advance collection of sale-leaseback rental costs, and the exclusion of certain long-term incentive plan performance unit costs from rates. 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.
Entergy Arkansas
Formula Rate Plan
Between base rate cases, Entergy Arkansas is able to adjust base rates annually, subject to certain caps, through formula rate plans that utilize a forward test year. Entergy Arkansas is subject to a maximum rate change
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of 4% of the filing year total retail revenue. In addition, Entergy Arkansas is subject to a true-up of projection to actuals netted with future projection. In response to Entergy Arkansas’s application for a general change in rates in 2015, the APSC approved the formula rate plan tariff proposed by Entergy Arkansas including its use of a projected year test period and an initial five-year term. The initial five-year term expired in 2021. As granted by Arkansas law, Entergy Arkansas obtained APSC approval of the extension of the formula rate plan tariff for an additional five-year term, through 2026. If Entergy Arkansas’s formula rate plan were terminated, Entergy Arkansas could file an application for a general change in rates that may include a request for continued regulation under a formula rate review mechanism.
Fuel and Purchased Power Cost Recovery
Entergy Arkansas’s rate schedules include an energy cost recovery rider to recover fuel and purchased power costs in monthly bills. The rider utilizes 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-recovery or under-recovery, including carrying charges, of the energy cost 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 December 2007 the APSC issued an order stating that Entergy Arkansas’s energy cost recovery rider will remain in effect, and any future termination of the rider would be subject to eighteen months advance notice by the APSC, which would occur following notice and hearing.
Production Cost Allocation Rider
Entergy Arkansas has in place an APSC-approved production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of System Agreement proceedings.
Entergy Louisiana
Formula Rate Plan
Entergy Louisiana historically sets electric base rates annually through a formula rate plan using a historic test year. The form of the formula rate plan, on a combined basis, was approved in connection with the business combination of Entergy Louisiana and Entergy Gulf States Louisiana and largely followed the formula rate plans that were approved by the LPSC in connection with the full electric base rate cases filed by those companies in February 2013. The formula rate plan was most recently extended through the test year 2022; certain modifications were made in that extension, including a decrease to the allowed return on equity, narrowing of the earnings “dead band” around the mid-point allowed return on equity, elimination of sharing above and below the earnings “dead band,” and the addition of a distribution cost recovery mechanism. The formula rate plan continues to include exceptions from the rate cap and sharing requirements for certain large capital investment projects, including acquisition or construction of generating facilities and purchase power agreements approved by the LPSC, certain transmission investments, and most recently, certain distribution investments, among other items. In the event that the electric formula rate plan is not renewed or extended or otherwise replaced, Entergy Louisiana would revert to the more traditional rate case environment with a rate case filing occurring as soon as mid-2023.
Fuel Recovery
Entergy Louisiana’s rate schedules include a fuel adjustment clause designed to recover the cost of fuel and purchased power costs. The fuel adjustment clause contains a surcharge or credit for deferred fuel expense and related carrying charges arising from the monthly reconciliation of actual fuel costs incurred with fuel cost revenues billed to customers, including carrying charges. See Note 2 to the financial statements for a discussion of proceedings related to audits of Entergy Louisiana’s fuel adjustment clause filings.
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To help stabilize electricity costs, Entergy Louisiana received approval from the LPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Louisiana historically hedged approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity was reviewed on an annual basis. In January 2018, Entergy Louisiana filed an application with the LPSC to suspend these seasonal hedging programs and implement financial hedges with terms up to five years for a portion of its natural gas exposure, which was approved in November 2018.
Entergy Louisiana’s gas rates include a purchased gas adjustment clause based on estimated gas costs 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.
Retail Rates - Gas
In accordance with the settlement of Entergy Gulf States Louisiana’s gas rate stabilization plan for the test year ended September 30, 2012, in August 2014, Entergy Gulf States Louisiana submitted for consideration a proposal for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment and relocation projects mandated by local governments. After review by the LPSC staff and inclusion of certain customer safeguards required by the LPSC staff, in December 2014, Entergy Gulf States Louisiana and the LPSC staff submitted a joint settlement for implementation of an accelerated gas pipe replacement program providing for the replacement of approximately 100 miles of pipe over the next ten years, as well as relocation of certain existing pipe resulting from local government-related infrastructure projects, and for a rider to recover the investment associated with these projects. The rider allows for recovery of approximately $65 million over ten years. The rider recovery will be adjusted on a quarterly basis to include actual investment incurred for the prior quarter and is subject to the following conditions, among others: a ten-year term; application of any earnings in excess of the upper end of the earnings band as an offset to the revenue requirement of the infrastructure rider; adherence to a specified spending plan, within plus or minus 20% annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding 10%; and an annual true-up. The joint settlement was approved by the LPSC in January 2015. Implementation of the infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2015. In April 2022 Entergy Louisiana submitted for consideration a proposal to extend the infrastructure rider to address replacement of an additional 187 miles of pipe. In December 2022 Entergy Louisiana and the LPSC staff submitted an uncontested settlement that extends the rider for an additional ten years beginning after the end of the current term of the rider in 2025. The extension is subject to the same customer safeguards and conditions as the original term of the rider. The extension allows for recovery of approximately $95 million over ten years. In February 2023, the uncontested settlement was approved by the LPSC.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Louisiana’s filings to recover storm-related costs.
Other
In March 2016 the LPSC opened two dockets to examine, on a generic basis, issues that it identified in connection with its review of Cleco Corporation’s acquisition by third party investors. The first docket is captioned “In re: Investigation of double leveraging issues for all LPSC-jurisdictional utilities,” and the second is captioned “In re: Investigation of tax structure issues for all LPSC-jurisdictional utilities.” In April 2016 the LPSC clarified that the concerns giving rise to the two dockets arose as a result of its review of the structure of the Cleco-Macquarie transaction and that the specific intent of the directives is to seek more information regarding intra-corporate debt financing of a utility’s capital structure as well as the use of investment tax credits to mitigate the tax
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obligation at the parent level of a consolidated entity. No schedule has been set for either docket, and limited discovery has occurred.
In December 2019 an LPSC commissioner issued an unopposed directive to staff to research customer-centered options for all customer classes, as well as other regulatory environments, and recommend a plan for how to ensure customers are the focus. There was no opposition to the directive from other commissioners but several remarked that the intent of the directive was not initiated to pursue retail open access. In furtherance of the directive, the LPSC issued a notice of the opening of a docket to conduct a rulemaking to research and evaluate customer-centered options for all electric customer classes as well as other regulatory environments in January 2020. To date, the LPSC staff has requested multiple rounds of comments from stakeholders and conducted one technical conference. Topics on which comments have been filed include full and limited retail access, demand response, sleeved power purchase agreements, and energy efficiency. Neither the LPSC or the LPSC staff have made recommendations or adopted any rules.
Entergy Mississippi
Formula Rate Plan
Since the conclusion in 2015 of Entergy Mississippi’s most recent base rate case, Entergy Mississippi has set electric base rates annually through a formula rate plan. Between base rate cases, Entergy Mississippi is able to adjust base rates annually, subject to certain caps, through formula rate plans that utilize forward-looking features. In addition, Entergy Mississippi is subject to an annual “look-back” evaluation. Entergy Mississippi is allowed a maximum rate increase of 4% of each test year’s retail revenue. Any increase above 4% requires a base rate case. If Entergy Mississippi’s formula rate plan were terminated without replacement, it would revert to the more traditional rate case environment or seek approval of a new formula rate plan.
In August 2012 the MPSC opened inquiries to review whether the then current formulaic methodology used to calculate the return on common equity in both Entergy Mississippi’s formula rate plan and Mississippi Power Company’s annual formula rate plan was still appropriate or could be improved to better serve the public interest. The intent of this inquiry and review was for informational purposes only; the evaluation of any recommendations for changes to the existing methodology would take place in a general rate case or in the existing formula rate plan proceeding. In March 2013 the Mississippi Public Utilities Staff filed its consultant’s report which noted the return on common equity estimation methods used by Entergy Mississippi and Mississippi Power Company are commonly used throughout the electric utility industry. The report suggested ways in which the methods used by Entergy Mississippi and Mississippi Power Company might be improved, but did not recommend specific changes in the return on common equity formulas or calculations at that time. In June 2014 the MPSC expanded the scope of the August 2012 inquiry to study the merits of adopting a uniform formula rate plan that could be applied, where possible in whole or in part, to both Entergy Mississippi and Mississippi Power Company in order to achieve greater consistency in the plans. The MPSC directed the Mississippi Public Utilities Staff to investigate and review Entergy Mississippi’s formula rate plan rider schedule and Mississippi Power Company’s Performance Evaluation Plan by considering the merits and deficiencies and possibilities for improvement of each and then to propose a uniform formula rate plan that, where possible, could be applicable to both companies. No procedural schedule has been set. In October 2014 the Mississippi Public Utilities Staff conducted a public technical conference to discuss performance benchmarking and its potential application to the electric utilities’ formula rate plans. The docket remains open.
In December 2019 the MPSC approved Entergy Mississippi’s proposed revisions to its formula rate plan to 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 as well as to allow similar cost recovery treatment for other capacity acquisitions that are approved by the MPSC. 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
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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.
Fuel Recovery
Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased power costs. The energy cost rate for each calendar year is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy costs as of the 12-month period ended September 30. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC. The energy cost recovery riders allow interim rate adjustments depending on the level of over- or under-recovery of fuel and purchased energy costs.
To help stabilize electricity costs, Entergy Mississippi received approval from the MPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Mississippi hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of recovery of Entergy Mississippi’s storm-related costs.
Entergy New Orleans
Formula Rate Plan
As part of its determination of rates in the base rate case filed by Entergy New Orleans in 2018, in November 2019, the City Council issued a resolution resolving the rate case, with rates to become effective retroactive to August 2019. The resolution allows Entergy New Orleans to implement a three-year formula rate plan, beginning with the 2019 test year as adjusted for forward-looking known and measurable changes, with the filing for the first test year to be made in 2020. As part of a settlement of Entergy New Orleans’ appeal of the Council’s decision in its 2018 base rate case, Entergy New Orleans agreed to postpone the filing of its first test year formula rate plan to 2021 and, in return, to be provided an additional test year for the three-year cycle. Accordingly, Entergy New Orleans will submit its final formula rate plan filing of the three-year cycle in April 2023 unless the formula rate plan is extended or renewed. See Note 2 to the financial statements for further discussion.
Fuel Recovery
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.
To help stabilize gas costs, Entergy New Orleans seeks approval annually from the City Council to continue implementation of its natural gas hedging program consistent with the City Council’s stated policy objectives. The program uses financial instruments to hedge exposure to volatility in the wholesale price of natural gas purchased to
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serve Entergy New Orleans gas customers. Entergy New Orleans hedges up to 25% of actual gas sales made during the winter months.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy New Orleans’s filings to recover storm-related costs.
Entergy Texas
Base Rates
The base rates of Entergy Texas are established largely in traditional base rate case proceedings. Between base rate proceedings, Entergy Texas has available rate riders to recover the revenue requirements associated with certain incremental costs. Entergy Texas is required to file full base rate case proceedings every four years and within eighteen months of utilizing its generation cost recovery rider for investments above $200 million.
Fuel Recovery
Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, that are not included 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 every three years, at a minimum. In the course of this reconciliation, the PUCT determines whether eligible fuel and fuel-related expenses and revenues are necessary and reasonable and makes a prudence finding for each of the fuel-related contracts entered into during the reconciliation period. The PUCT fuel cost proceedings are discussed in Note 2 to the financial statements.
At the PUCT’s April 2013 open meeting, the PUCT Commissioners discussed their view that a purchased power capacity rider was good public policy. The PUCT issued an order in May 2013 adopting the rule allowing for a purchased power capacity rider, subject to an offsetting adjustment for load growth. The rule, as adopted, also includes a process for obtaining pre-approval by the PUCT of purchased power agreements. No Texas utility, including Entergy Texas, has exercised the option to recover capacity costs under the new rider mechanism, but Entergy Texas will continue to evaluate the benefits of utilizing the rider to recover future capacity costs.
Other Cost Recovery
As discussed above, Entergy Texas has available rate riders to recover the revenue requirements associated with certain incremental costs. These riders include a transmission cost recovery factor rider mechanism for the recovery of transmission-related capital investments, a distribution cost recovery factor rider mechanism for the recovery of distribution-related capital investment, and a generation cost recovery rider mechanism for the recovery of generation-related capital investments.
In June 2009 a law was enacted in Texas containing provisions that allow Entergy Texas to take advantage of a cost recovery mechanism that permits annual filings for the recovery of reasonable and necessary expenditures for transmission infrastructure improvement and changes in wholesale transmission charges. This mechanism was previously available to other non-ERCOT Texas utility companies, but not to Entergy Texas.
In September 2011 the PUCT adopted a proposed rule implementing a distribution cost recovery factor to recover capital and capital-related costs related to distribution infrastructure. The distribution cost recovery factor permits utilities once per year to implement an increase or decrease in rates above or below amounts reflected in base rates to reflect distribution-related depreciation expense, federal income tax and other taxes, and return on
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investment. The distribution cost recovery factor rider may be changed a maximum of four times between base rate cases.
In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery rider rule, implementing legislation passed in the 2019 Texas legislative session intended to allow electric utilities to recover generation investments between base rate proceedings. The PUCT approved the final rule in July 2020.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Texas’s filings to recover storm-related costs.
Electric Industry Restructuring
In June 2009 a law was enacted in Texas that required Entergy Texas to cease all activities relating to Entergy Texas’s transition to competition. The law allows Entergy Texas to remain a part of the SERC Reliability Corporation (SERC) Region, although it does not prevent Entergy Texas from joining another power region. The law provides that proceedings to certify a power region that Entergy Texas belongs to as a qualified power region can be initiated by the PUCT, or on motion by another party, when the conditions supporting such a proceeding exist. Under the law, the PUCT may not approve a transition to competition plan for Entergy Texas until the expiration of four years from the PUCT’s certification of a qualified power region for Entergy Texas.
The law further amended already existing law that had required Entergy Texas to propose for PUCT approval a tariff to allow eligible customers the ability to contract for competitive generation. The amending language in the law provides, among other things, that: 1) the tariff shall not be implemented in a manner that harms the sustainability or competitiveness of manufacturers who choose not to participate in the tariff; 2) Entergy Texas shall “purchase competitive generation service, selected by the customer, and provide the generation at retail to the customer;” and 3) Entergy Texas shall provide and price transmission service and ancillary services under that tariff at a rate that is unbundled from its cost of service. The law directs that the PUCT may not issue an order on the tariff that is contrary to an applicable decision, rule, or policy statement of a federal regulatory agency having jurisdiction. The PUCT determined that unrecovered costs that may be recovered through the rider consist only of those costs necessary to implement and administer the competitive generation program and do not include lost revenues or embedded generation costs. The amount of customer load that may be included in the competitive generation service program is limited to 115 MW.
System Energy
Cost of Service
The rates of System Energy are established by the FERC, and the costs allowed to be charged pursuant to these rates are, in turn, passed through to the participating Utility operating companies through the Unit Power Sales Agreement, which has monthly billings that reflect the current operating costs of, and investment in, Grand Gulf. Retail regulators and other parties may seek to initiate proceedings at FERC to investigate the prudence of costs included in the rates charged under the Unit Power Sales Agreement and examine, among other things, the reasonableness or prudence of the operation and maintenance practices, level of expenditures, allowed rates of return and rate base, and previously incurred capital expenditures. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC, including a challenge with respect to System Energy’s uncertain tax positions, sale leaseback arrangement, authorized return on equity and capital structure, and a separate proceeding for a broader investigation of rates under the Unit Power Sales Agreement. In addition, certain of the Utility operating companies’ retail regulators have filed a complaint at FERC challenging the 2012 extended power uprate of Grand Gulf and the operation and management of the plant, particularly during the time period 2016 - 2020. Beginning in 2021, System Energy implemented billing protocols to provide retail regulators with
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information regarding rates billed under the Unit Power Sales Agreement. Entergy cannot predict the outcome of any of these proceedings, and an adverse outcome in any of them could have a material adverse effect on Entergy’s or System Energy’s results of operations, financial condition, or liquidity. See Note 2 to the financial statements for further discussion of the proceedings.
Franchises
Entergy Arkansas holds exclusive franchises to provide electric service in approximately 308 incorporated cities and towns in Arkansas. These franchises generally are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas, franchises are considered to be contracts and, therefore, are governed pursuant to the terms of the franchise agreement and applicable statutes.
Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 175 incorporated municipalities and in the unincorporated areas of approximately 59 parishes of Louisiana. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and in East Baton Rouge Parish. Municipal franchise agreement terms range from 25 to 60 years while parish franchise terms range from 25 to 99 years.
Entergy Mississippi has received from the MPSC certificates of public convenience and necessity to provide electric service to areas within 45 counties, including a number of municipalities, in western Mississippi. Under Mississippi statutory law, such certificates are exclusive. Entergy Mississippi may continue to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence.
Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city ordinances. These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans’s electric and gas utility properties.
Entergy Texas holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 27 counties in eastern Texas and holds non-exclusive franchises to provide electric service in approximately 70 incorporated municipalities. Entergy Texas typically obtains 25-year franchise agreements as existing agreements expire. Entergy Texas’s electric franchises expire over the period 2023-2058.
The business of System Energy is limited to wholesale power sales. It has no distribution franchises.
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Property and Other Generation Resources
Owned Generating Stations
The total capability of the generating stations owned and leased by the Utility operating companies and System Energy as of December 31, 2022 is indicated below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Owned and Leased Capability MW(a) |
| Company | | Total | | CT / CCGT (b) | | Legacy Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
| Entergy Arkansas | | 5,276 | | | 1,567 | | | 522 | | | 1,822 | | | 1,192 | | | 73 | | | 100 | |
| Entergy Louisiana | | 10,829 | | | 5,595 | | | 2,766 | | | 2,129 | | | 339 | | | — | | | — | |
| Entergy Mississippi | | 2,857 | | | 1,738 | | | 707 | | | — | | | 310 | | | — | | | 102 | |
| Entergy New Orleans | | 663 | | | 636 | | | — | | | — | | | — | | | — | | | 27 | |
| Entergy Texas | | 3,190 | | | 980 | | | 1,960 | | | — | | | 250 | | | — | | | — | |
| System Energy | | 1,260 | | | — | | | — | | | 1,260 | | | — | | | — | | | — | |
| Total | | 24,075 | | | 10,516 | | | 5,955 | | | 5,211 | | | 2,091 | | | 73 | | | 229 | |
(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.
(b)Represents Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.
Summer peak load for the Utility has averaged 21,602 MW over the previous decade.
The Utility operating companies’ load and capacity projections are reviewed periodically to assess the need and timing for additional generating capacity and interconnections. These reviews consider existing and projected demand, the availability and price of power, the location of new load, the economy, Entergy’s clean energy and other public policy goals, environmental regulations, and the age and condition of Entergy’s existing infrastructure.
The Utility operating companies’ long-term resource strategy (Portfolio Transformation Strategy) calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Over the past decade, the Portfolio Transformation Strategy has resulted in the addition of about 8,975 MW of new long-term resources and the deactivation of about 4,881 MW of legacy generation. As MISO market participants, the Utility operating companies also participate in MISO’s Day Ahead and Real Time Energy and Ancillary Services markets to economically dispatch generation and purchase energy to serve customers reliably and at the lowest reasonable cost.
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Other Generation Resources
RFP Procurements
The Utility operating companies from time to time issue requests for proposals (RFP) to procure supply-side resources from sources other than the spot market to meet the unique regional needs of the Utility operating companies. The RFPs issued by the Utility operating companies have sought resources needed to meet near-term MISO reliability requirements as well as long-term requirements through a broad range of wholesale power products, including long-term contractual products and asset acquisitions. The RFP process has resulted in selections or acquisitions, including, among other things:
•Entergy Louisiana’s construction of the 980 MW, combined-cycle, gas turbine J. Wayne Leonard Power Station (previously referred to as the St. Charles generating facility) at its existing Little Gypsy electric generating station. The facility began commercial operation in May 2019;
•Entergy Louisiana’s construction of the 994 MW, combined-cycle, gas turbine Lake Charles generating facility at its existing Nelson electric generating station site. The facility began commercial operation in March 2020;
•Entergy Texas’s construction of the 993 MW, combined-cycle, gas turbine Montgomery County Power Station at its existing Lewis Creek electric generating station. The facility began commercial operation in January 2021;
•Entergy New Orleans’s construction of the 20 MW solar photovoltaic facility, New Orleans Solar Station, located at the NASA Michoud Facility. The facility began commercial operation in December 2020;
•In December 2020, Entergy Texas selected the self-build alternative, Orange County Advanced Power Station, out of the 2020 Entergy Texas combined-cycle, gas turbine RFP. Regulatory approval was received in November 2022 and construction has commenced. The facility is expected to be in service by mid-2026;
•In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Searcy Solar facility, sited on approximately 800 acres in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the APSC in April 2020, and closed on the acquisition, through use of a tax equity partnership, in December 2021. The Searcy Solar facility was placed in service in January 2022;
•In November 2018, Entergy Mississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Sunflower Solar facility, sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and the Sunflower Solar facility began commercial operation in September 2022;
•In June 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Walnut Bend Solar facility, that will be sited on approximately 1,000 acres in Lee County, Arkansas. In July 2021 the APSC issued an order approving the acquisition of the Walnut Bend Solar facility. The counter-party notified Entergy Arkansas that it was terminating the project, though it was willing to consider an alternative for the site. Entergy Arkansas disputed the right of termination. Negotiations are ongoing, including with respect to cost and schedule and to updates arising as a result of the Inflation Reduction Act of 2022, and the updates would require additional APSC approval. At this time the project, if approved, is expected to achieve commercial operation in 2024;
•In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility, West Memphis Solar facility, that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In October 2021 the APSC issued an order approving the acquisition of the West Memphis Solar facility. The counter-party notified Entergy Arkansas that it was seeking changes to certain terms of the build-own-transfer agreement, including both cost and schedule. In January 2023, Entergy Arkansas made a supplemental filing with the APSC. Following APSC supplemental approval, full notice to proceed will be issued with closing expected to occur in 2024;
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•In November 2021, Entergy Louisiana signed an agreement for the purchase of an approximately 150 MW to-be-constructed solar photovoltaic energy facility, St. Jacques facility, that will be sited in St. James Parish near Vacherie, Louisiana. In September 2022 the LPSC voted to approve the order including the St. Jacques facility; however, project details could be adjusted pending a final St. James Parish ruling on land use permit requirements. Closing is expected to occur in 2025 dependent upon the final St. James Parish ruling; and
•In August 2022, Entergy Arkansas signed an agreement for the purchase of an approximately 250 MW to-be-constructed solar photovoltaic energy facility, Driver Solar facility, that will be sited near Osceola, Arkansas. Also in August 2022, Entergy Arkansas received necessary approvals for the Driver Solar facility, and Entergy Arkansas has issued the counter-party full notice to proceed to begin construction. The parties are evaluating the effects of certain matters related to the Inflation Reduction Act of 2022, including the viability of a tax equity partnership. Closing is expected to occur by the end of 2024.
The RFP process has also resulted in the selection, or confirmation of the economic merits of, long-term purchased power agreements (PPAs), including, among others:
•River Bend’s 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’s 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 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. In November 2019, LS Power sold and transferred the Carville Energy Center and facility to Argo Infrastructure Partners, which included the power purchase agreement;
•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 to-be-constructed solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and the PPA began in November 2020;
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•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 to-be-constructed solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the PPA began in October 2020;
•In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in the first half of 2023;
•In August 2018, Entergy Louisiana and South Alexander Development I, LLC executed a 5-year agreement for 5 MW from a solar photovoltaic electric generating facility located in Livingston Parish, Louisiana. The PPA began in December 2020 and received regulatory approval in January 2021;
•In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and achieved commercial operation in November 2022;
•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in Polk County, Texas. The PPA is expected to start when the facility reaches commercial operation in December 2023;
•In June 2021, Entergy Louisiana and Sunlight Road Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. In September 2022 the LPSC voted to approve the order including this project. The facility is expected to reach commercial operation in December 2024;
•In June 2021, Entergy Louisiana and Vacherie Solar Energy Center, LLC executed a 20-year PPA for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. In September 2022 the LPSC voted to approve the order including this project; however, project details could be adjusted pending a final St. James Parish ruling on land use permit requirements. The facility is expected to reach commercial operation in 2025;
•In November 2021, Entergy Louisiana signed a PPA for approximately 125 MW from a to-be-constructed solar photovoltaic energy facility located in Allen, Louisiana. In September 2022 the LPSC voted to approve the order including this project. The facility is expected to reach commercial operation in February 2024;
•In December 2022, Entergy Mississippi signed a PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Hinds County, Mississippi. Following execution of the agreement, Entergy Mississippi filed a petition with the MPSC requesting all necessary approvals. The facility is expected to reach commercial operation in June 2026;
•In October 2022, Entergy Mississippi signed a PPA for approximately 100 MW from a to-be-constructed solar photovoltaic energy facility located in Tallahatchie County, Mississippi. Following execution of the agreement, Entergy Mississippi filed a petition with the MPSC requesting all necessary approvals. The facility is expected to reach commercial operation as early as May 2026;
•In October 2022, Entergy Mississippi signed a PPA for approximately 170 MW from a to-be-constructed solar photovoltaic energy facility located in Washington County, Mississippi. Following execution of the agreement, Entergy Mississippi filed a petition with the MPSC requesting all necessary approvals. The facility is expected to reach commercial operation as early as May 2026;
•In October 2022, Entergy Arkansas signed a PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in St. Francis County, Arkansas. Following execution of the agreement, Entergy Arkansas filed a petition with the APSC requesting all necessary approvals. The facility is expected to reach commercial operation as early as May 2025;
•In October 2022, Entergy Arkansas signed a PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in Mississippi County, Arkansas. Following execution of the agreement, Entergy Arkansas filed a petition with the APSC requesting all necessary approvals. The facility is expected to reach commercial operation as early as May 2025; and
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•In January 2023, Entergy Texas signed a PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Walker County, Texas. The facility is expected to reach commercial operation as early as June 2026.
In March 2021, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic resources. Entergy Louisiana selected a combination of PPA and build-own-transfer resources by March 2022, some of which have been executed and are noted above and the remainder are in progress working through definitive agreements.
In July 2021, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar generation resources. Entergy Texas selected a combination of PPA and build-own-transfer resources in March 2022. One PPA was executed in January 2023 as noted above, and definitive agreements for the remaining resources are in progress.
In August 2021, Entergy Services, on behalf of Entergy Arkansas, issued an RFP for solar photovoltaic and wind resources. Entergy Arkansas selected a combination of PPA and build-own-transfer resources in February 2022, some of which have been executed and are noted above and the remainder are in progress working through definitive agreements.
In January 2022, Entergy Services, on behalf of Entergy Mississippi, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 500 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Mississippi customers.
In June 2022, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 1500 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Louisiana customers.
In April 2022, Entergy Services, on behalf of Entergy Arkansas, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 1000 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Arkansas customers.
In October 2022, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 2000 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Texas customers.
In November 2022, Entergy Services, on behalf of Entergy Mississippi, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 500 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Mississippi customers.
Other Procurements From Third Parties
The Utility operating companies have also made resource acquisitions outside of the RFP process, including Entergy Arkansas’s (Power Block 2), Entergy Louisiana’s (Power Blocks 3 and 4), and Entergy New Orleans’s (Power Block 1) March 2016 acquisitions of the 1,980 MW (summer rating), natural gas-fired, combined-cycle gas turbine Union Power Station power blocks, each rated at 495 MW (summer rating); and Entergy Mississippi’s October 2019 acquisition of the 810 MW, combined-cycle, natural gas-fired Choctaw Generating Station. The
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Utility operating companies have also entered into various limited- and long-term contracts in recent years as a result of bilateral negotiations.
The Washington Parish Energy Center is a 361 MW natural gas-fired peaking power plant approximately 60 miles north of New Orleans on a site Entergy Louisiana purchased from Calpine in 2019. In May 2018, Entergy Louisiana received LPSC approval of its certification application for this simple-cycle power plant to be developed pursuant to an agreement between Calpine and Entergy Louisiana. Calpine began construction on the plant in early 2019 and Entergy Louisiana purchased the plant upon completion in November 2020.
The Hardin County Peaking Facility, an existing 147 MW simple-cycle gas-fired peaking power plant in Kountze, Texas, previously owned by East Texas Electric Cooperative, was acquired by Entergy Texas in June 2021. The facility has been in operation since January 2010.
Power Through Programs
In December 2020, Entergy Texas filed an application with the PUCT to amend its certificate of convenience and necessity to own and operate up to 75 MW of natural gas-fired distributed generation to be installed at commercial and industrial customer premises. Under this proposal, Entergy Texas would own and operate a fleet of generators ranging from 100 kW to 10 MW that would supply a portion of Entergy Texas’s long-term resource needs and enhance the resiliency of Entergy Texas’s electric grid. This fleet of generators would also be available to customers during outages to supply backup electric service as part of a program known as “Power Through.” In its 2021 session, the Texas legislature modified the Texas Utilities Code to exempt generators under 10 megawatts from the requirement to obtain a certificate of convenience and necessity. In addition, the PUCT announced an intent to conduct a broad rulemaking related to distributed generation and recommended that utilities with pending applications addressing distributed generation withdraw them. Accordingly, Entergy Texas withdrew its application for a certificate of convenience and necessity and associated tariff from the PUCT without prejudice to refiling. Entergy Texas continues to deploy certain customer-sited distributed generators under an existing PUCT-approved tariff. In August 2022, Entergy Texas filed an application for PUCT approval of voluntary Rate Schedule Utility Owned Distributed Generation (UODG) through which it would charge host customers for back-up service from customer-sited Power Through generators. Based on the exemption enacted by the Texas legislature in 2021, Entergy Texas’s application was not required to, and did not, seek an amendment to its certificate of convenience and necessity in order to continue deploying Power Through generators. In October 2022 two intervenors filed requests for a hearing on Entergy Texas’s application. In October 2022 the PUCT staff filed a request that the proceeding be referred to the State Office of Administrative Hearings. In January 2023 the PUCT announced an intent to develop certain broadly applicable reliability metrics against which to measure distributed generation resources and directed Entergy Texas to withdraw its application. However, the PUCT did allow Entergy Texas to continue its pilot program for Power Through generators. Entergy Texas has withdrawn its application and is considering next steps.
In August 2021, Entergy Arkansas filed with the APSC an application for authority to deploy natural gas-fired distributed generation. The application was supported by a number of letters of interest from Entergy Arkansas customers. In December 2021 the APSC general staff requested briefing, which Entergy Arkansas opposed. In January 2022, Entergy Arkansas filed to support the establishment of a procedural schedule with a hearing in April 2022. Also in January 2022, the APSC granted the general staff’s request for briefing but on an expedited schedule; briefing concluded in February 2022. Based on testimony filed to date the APSC general staff, Arkansas Electric Energy Consumers, Sierra Club, and Audubon oppose Entergy Arkansas’s proposed “Power Through” offering, which has been demonstrated to be in high demand by interested customers, some of which directly have filed public comments encouraging the APSC to approve the application. A paper hearing was held in August and September 2022 with Entergy Arkansas responding to several written commissioner questions. The parties are awaiting a decision from the APSC.
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In July 2021, Entergy Louisiana filed with the LPSC an application for authority to deploy natural gas-fired distributed generation. The application was supported by a number of letters of interest from Entergy Louisiana customers. In October 2021, a procedural schedule was established with a hearing in April 2022. Staff and certain intervenors filed direct testimony in December 2021, and cross-answering testimony was filed in January 2022. Entergy Louisiana filed rebuttal testimony in February 2022. The parties reached an uncontested settlement which, among other things, recommended approval of 120 MW of natural gas fired distributed generation and an additional 30 MW of solar and battery distributed generation, for a total distributed generation program of 150 MW. Pursuant to the terms of the settlement agreement, Entergy Louisiana may seek to expand the distributed generation program following the earlier of two years after issuance of an order approving the settlement or the installation of 60 MW of distributed generation pursuant to this program. The settlement was approved by the LPSC in November 2022.
Interconnections
The Utility operating companies’ generating units are interconnected to a transmission system operating at various voltages up to 500 kV. These generating units consist of steam-turbine generators fueled by natural gas and coal, combustion-turbine generators, and reciprocating internal combustion engine generators that are fueled by natural gas, generators powered by pressurized and boiling water nuclear reactors and inverter-based resources interconnecting both solar photovoltaic systems and energy storage devices that operate in the MISO wholesale electric market. Additionally, some of the Utility operating companies also offer customer services and products that include resources interconnected to both the distribution and transmission systems that also participate in the wholesale market. Entergy’s Utility operating companies are MISO market participants and the companies’ transmission systems are interconnected with those of many neighboring utilities. MISO is an essential link in the safe, cost-effective delivery of electric power across all or parts of 15 U.S. states and the Canadian province of Manitoba. In addition, the Utility operating companies are members of SERC Reliability Corporation (SERC), the Regional Entity with delegated authority from the North American Electric Reliability Corporation (NERC) for the purpose of proposing and enforcing Bulk Electric System reliability standards within 16 central and southeastern states.
Gas Property
As of December 31, 2022, Entergy New Orleans distributed and transported natural gas for distribution within New Orleans, Louisiana, through approximately 2,600 miles of gas pipeline. As of December 31, 2022, the gas properties of Entergy Louisiana, which are located in and around Baton Rouge, Louisiana, were not material to Entergy Louisiana’s financial position.
Title
The Utility operating companies’ generating stations are generally located on properties owned in fee simple. Most of the substations and transmission and distribution lines are constructed on private property or public rights-of-way pursuant to easements, servitudes, or appropriate franchises. Some substation properties are owned in fee simple. The Utility operating companies generally have the right of eminent domain, whereby they may perfect title to, or secure easements or servitudes on, private property for their utility operations.
Substantially all of the physical properties and assets owned by Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are subject to the liens of mortgages securing bonds issued by those companies. The Lewis Creek generating station of Entergy Texas was acquired by merger with a subsidiary of Entergy Texas and is currently not subject to the lien of the Entergy Texas indenture.
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Fuel Supply
The average fuel cost per kWh for the Utility operating companies and System Energy for the years 2020-2022 were:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year | | Natural Gas | | Nuclear | | Coal | | Renewables (a) | | Purchased Power | | MISO Purchases (b) |
| 2022 | | (Cents Per kWh) |
| Entergy Arkansas | | 4.98 | | | 0.52 | | | 2.93 | | | 2.11 | | | 10.90 | | | (2.65) | |
| Entergy Louisiana | | 5.50 | | | 0.57 | | | 2.84 | | | 10.70 | | | 6.95 | | | 6.45 | |
| Entergy Mississippi | | 4.38 | | | — | | | 2.85 | | | 0.04 | | | 6.53 | | | 6.68 | |
| Entergy New Orleans (c) | | 5.10 | | | — | | | — | | | (5.16) | | | — | | | 7.21 | |
| Entergy Texas | | 5.77 | | | — | | | 2.83 | | | 6.26 | | | 5.61 | | | 6.68 | |
| System Energy | | — | | | 0.65 | | | — | | | — | | | — | | | — | |
| Utility | | 5.27 | | | 0.57 | | | 2.89 | | | 7.00 | | | 6.54 | | | 5.95 | |
| | | | | | | | | | | | |
| 2021 | | | | | | | | | | | | |
| Entergy Arkansas | | 4.11 | | | 0.56 | | | 2.43 | | | 2.85 | | | 2.53 | | | 3.87 | |
| Entergy Louisiana | | 3.77 | | | 0.56 | | | 2.62 | | | 10.87 | | | 5.52 | | | 4.04 | |
| Entergy Mississippi | | 2.71 | | | — | | | 2.53 | | | 1.22 | | | 2.70 | | | 4.16 | |
| Entergy New Orleans (c) | | 3.47 | | | — | | | — | | | (2.82) | | | — | | | 4.50 | |
| Entergy Texas | | 4.65 | | | — | | | 2.60 | | | 3.97 | | | 4.53 | | | 4.10 | |
| System Energy | | — | | | 0.55 | | | — | | | — | | | — | | | — | |
| Utility | | 3.75 | | | 0.56 | | | 2.48 | | | 9.07 | | | 4.76 | | | 4.08 | |
| | | | | | | | | | | | |
| 2020 | | | | | | | | | | | | |
| Entergy Arkansas | | 1.78 | | | 0.62 | | | 2.35 | | | 2.28 | | | 7.39 | | | 0.63 | |
| Entergy Louisiana | | 1.98 | | | 0.58 | | | 3.27 | | | 9.99 | | | 3.48 | | | 2.65 | |
| Entergy Mississippi | | 1.73 | | | — | | | 2.52 | | | 0.25 | | | 3.23 | | | 2.26 | |
| Entergy New Orleans | | 1.56 | | | — | | | — | | | 0.02 | | | — | | | 2.99 | |
| Entergy Texas | | 2.23 | | | — | | | 3.17 | | | 3.61 | | | 3.29 | | | 2.71 | |
| System Energy | | — | | | 0.39 | | | — | | | — | | | — | | | — | |
| Utility | | 1.92 | | | 0.57 | | | 2.54 | | | 8.28 | | | 3.35 | | | 2.48 | |
(a)Includes average fuel costs from both owned and purchased power resources.
(b)Includes activity from financial transmission rights. See Note 15 to the financial statements for discussion of financial transmission rights.
(c)Entergy New Orleans’s renewables include liquidated damage payments of $2.9 million in 2022 and $1 million in 2021 due to the delay of in-service dates related to purchased power agreements.
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Actual 2022 and projected 2023 sources of generation for the Utility operating companies and System Energy, including certain power purchases from affiliates under life of unit power purchase agreements, including the Unit Power Sales Agreement, are:
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| 2022 |
| | CT / CCGT (b) | | Legacy Gas | | Nuclear | | Coal | | Renewables (c) | | Purchased Power (d) | | MISO Purchases (e) |
| Entergy Arkansas | 30 | % | | 1 | % | | 50 | % | | 12 | % | | 3 | % | | — | % | | 4 | % |
| Entergy Louisiana | 44 | % | | 9 | % | | 23 | % | | 3 | % | | 2 | % | | 8 | % | | 11 | % |
| Entergy Mississippi | 59 | % | | 6 | % | | 18 | % | | 7 | % | | 1 | % | | — | % | | 9 | % |
| Entergy New Orleans | 54 | % | | 1 | % | | 35 | % | | 1 | % | | 1 | % | | 1 | % | | 7 | % |
| Entergy Texas | 31 | % | | 20 | % | | 11 | % | | 5 | % | | — | % | | 9 | % | | 24 | % |
| System Energy (a) | — | % | | — | % | | 100 | % | | — | % | | — | % | | — | % | | — | % |
| Utility | 42 | % | | 8 | % | | 27 | % | | 5 | % | | 2 | % | | 5 | % | | 11 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2023 |
| | CT / CCGT (b) | | Legacy Gas | | Nuclear | | Coal | | Renewables (c) | | Purchased Power (d) | | MISO Purchases (e) |
| Entergy Arkansas | 26 | % | | — | % | | 58 | % | | 13 | % | | 3 | % | | — | % | | — | % |
| Entergy Louisiana | 47 | % | | 5 | % | | 30 | % | | 3 | % | | 3 | % | | 12 | % | | — | % |
| Entergy Mississippi | 63 | % | | — | % | | 26 | % | | 10 | % | | 1 | % | | — | % | | — | % |
| Entergy New Orleans | 48 | % | | 1 | % | | 45 | % | | 2 | % | | 3 | % | | 1 | % | | — | % |
| Entergy Texas | 44 | % | | 31 | % | | 15 | % | | 9 | % | | — | % | | 1 | % | | — | % |
| System Energy (a) | — | % | | — | % | | 100 | % | | — | % | | — | % | | — | % | | — | % |
| Utility | 44 | % | | 6 | % | | 36 | % | | 7 | % | | 2 | % | | 5 | % | | — | % |
(a)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.
(b)Represents natural gas sourced for Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.
(c)Includes generation from both owned and purchased power resources.
(d)Excludes MISO purchases and renewables purchased through purchased power agreements.
(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 2022 is not projected for 2023.
Some of the Utility’s gas-fired plants are also capable of using fuel oil, if necessary. Although based on current economics the Utility does not expect fuel oil use in 2023, it is possible that various operational events including weather or pipeline maintenance may require the use of fuel oil.
Natural Gas
The Utility operating companies have long-term firm and short-term interruptible gas contracts for both supply and transportation. Over 50% of the Utility operating companies’ power plants maintain some level of long-term firm transportation. Short-term contracts and spot-market purchases satisfy additional gas requirements.
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Entergy Texas owns a gas storage facility and Entergy Louisiana has a firm storage service agreement that provide reliable and flexible natural gas service to certain generating stations.
Many factors, including wellhead deliverability, storage, pipeline capacity, and demand requirements of end users, influence the availability and price of natural gas supplies for power plants. Demand is primarily tied to weather conditions as well as to the prices and availability of other energy sources. Pursuant to federal and state regulations, gas supplies to power plants may be interrupted during periods of shortage. To the extent natural gas supplies are disrupted or natural gas prices significantly increase, the Utility operating companies may in some instances use alternate fuels, such as oil when available, or rely to a larger extent on coal, nuclear generation, and purchased power.
Coal
Entergy Arkansas has committed to six two- to three-year contracts that will supply approximately 85% of the total coal supply needs in 2023. These contracts are staggered in term so that not all contracts have to be renewed the same year. If needed, additional Powder River Basin (PRB) coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. Based on the high cost of alternate sources, modes of transportation, and infrastructure improvements necessary for its delivery, no alternative coal consumption is expected at Entergy Arkansas during 2023. Coal will be transported to Arkansas via an existing Union Pacific transportation agreement that is expected to provide all of Entergy Arkansas’s rail transportation requirements for 2023.
Entergy Louisiana has committed to four two- to three-year contracts that will supply approximately 90% of Nelson Unit 6 coal needs in 2023. If needed, additional PRB coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. For the same reasons as the Entergy Arkansas plants, no alternative coal consumption is expected at Nelson Unit 6 during 2023. Coal will be transported to Nelson via an existing transportation agreement that is expected to provide all of Entergy Louisiana’s rail transportation requirements for 2023.
Coal transportation delivery rates to Entergy Arkansas- and Entergy Louisiana-operated coal-fired units became constrained and were unable to fully meet supply needs and obligations beginning in August 2021. Deliveries remained constrained through 2022 with modest improvement expected later in 2023. Both Entergy Arkansas and Entergy Louisiana control enough railcars to satisfy the rail transportation requirement.
The operator of Big Cajun 2 - Unit 3, Louisiana Generating, LLC, has advised Entergy Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2023, but is also currently experiencing delivery constraints. Entergy Louisiana’s and Entergy Texas’s coal nomination requests to Big Cajun 2 - Unit 3 are made on an annual basis.
Nuclear Fuel
The nuclear fuel cycle consists of the following:
•mining and milling of uranium ore to produce a concentrate;
•conversion of the concentrate to uranium hexafluoride gas;
•enrichment of the uranium hexafluoride gas;
•fabrication of nuclear fuel assemblies for use in fueling nuclear reactors; and
•disposal of spent fuel.
The Registrant Subsidiaries that own nuclear plants, Entergy Arkansas, Entergy Louisiana, and System Energy, are responsible through a shared regulated uranium pool for contracts to acquire nuclear material to be used in fueling Entergy’s Utility nuclear units. These companies own the materials and services in this shared regulated
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uranium pool on a pro rata fractional basis determined by the nuclear generation capability of each company. Any liabilities for obligations of the pooled contracts are on a several but not joint basis. The shared regulated uranium pool maintains inventories of nuclear materials during the various stages of processing. The Registrant Subsidiaries purchase enriched uranium hexafluoride for their nuclear plant reload requirements at the average inventory cost from the shared regulated uranium pool. Entergy Operations, Inc. contracts separately for the fabrication of nuclear fuel as agent on behalf of each of the Registrant Subsidiaries that owns a nuclear plant. All contracts for the disposal of spent nuclear fuel are between the DOE and the owner of a nuclear power plant.
Based upon currently planned fuel cycles, the Utility nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable or fixed prices through most of 2027. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners, including their ability to work through supply disruptions caused by global events, such as the COVID-19 pandemic, or national events, such as political disruption. There are a number of possible supply alternatives that may be accessed to mitigate any supplier performance failure, including potentially drawing upon Entergy’s inventory intended for later generation periods depending upon its risk management strategy at that time, although the pricing of any alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. In addition, some nuclear fuel contracts are on a non-fixed price basis subject to prevailing prices at the time of delivery.
The effects of market price changes may be reduced and deferred by risk management strategies, such as negotiation of floor and ceiling amounts for long-term contracts, buying for inventory or entering into forward physical contracts at fixed prices when Entergy believes it is appropriate and useful. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S.
Entergy’s ability to assure nuclear fuel supply also depends upon the performance reliability of conversion, enrichment, and fabrication services providers. There are fewer of these providers than for uranium. For conversion and enrichment services, like uranium, Entergy diversifies its supply by supplier and country and may take special measures as needed to ensure supply of enriched uranium for the reliable fabrication of nuclear fuel. For fabrication services, each plant is dependent upon the effective performance of the fabricator of that plant’s nuclear fuel, therefore, Entergy provides additional monitoring, inspection, and oversight for the fabrication process to assure reliability and quality.
Entergy Arkansas, Entergy Louisiana, and System Energy each have made arrangements to lease nuclear fuel and related equipment and services. The lessors, which are consolidated in the financial statements of Entergy and the applicable Registrant Subsidiary, finance the acquisition and ownership of nuclear fuel through credit agreements and the issuance of notes. These credit facilities are subject to periodic renewal, and the notes are issued periodically, typically for terms between three and seven years.
Natural Gas Purchased for Resale
Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with one interstate and three intrastate pipelines. Entergy New Orleans has a “no-notice” service gas purchase contract with Symmetry Energy Solutions which guarantees Entergy New Orleans gas delivery at specific delivery points and at any volume within the minimum and maximum set forth in the contract amounts. The Symmetry Energy Solutions gas supply is transported to Entergy New Orleans pursuant to a transportation service agreement with Gulf South Pipeline Co. This service is subject to FERC-approved rates. Entergy New Orleans also makes interruptible spot market purchases.
Entergy Louisiana purchased natural gas for resale in 2022 under a firm contract from Sequent Energy Management L.P. The gas is delivered through a combination of intrastate and interstate pipelines.
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As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy Louisiana’s or Entergy New Orleans’s suppliers failed to perform their obligations to deliver gas under their supply agreements. Gulf South Pipeline Co. could curtail transportation capacity only in the event of pipeline system constraints.
Federal Regulation of the Utility
State or local regulatory authorities, as described above, regulate the retail rates of the Utility operating companies. The FERC regulates wholesale sales of electricity rates and interstate transmission of electricity, including System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. See Note 2 to the financial statements for further discussion of federal regulation proceedings.
Transmission and MISO Markets
In December 2013 the Utility operating companies integrated into the MISO RTO. Although becoming a member of MISO did not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities, MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. MISO also exercises functional control of transmission planning and congestion management and provides schedules and pricing for the commitment and dispatch of generation that is offered into MISO’s markets, as well as pricing for load that bids into the markets. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their generating facilities into the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. Each Utility operating company has its own transmission pricing zone and a formula rate template (included as Attachment O to the MISO tariff) used to establish transmission rates within MISO. The terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets and the allocation of transmission upgrade costs, are subject to regulation by the FERC.
System Energy and Related Agreements
System Energy recovers costs related to its interest in Grand Gulf through rates charged to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans for capacity and energy under the Unit Power Sales Agreement (described below). In 1998 the FERC approved requests by Entergy Arkansas and Entergy Mississippi to accelerate a portion of their Grand Gulf purchased power obligations. Entergy Arkansas’s and Entergy Mississippi’s acceleration of Grand Gulf purchased power obligations ceased effective July 2001 and July 2003, respectively, as approved by the FERC. See Note 2 to the financial statements for discussion of proceedings at the FERC related to System Energy.
Unit Power Sales Agreement
The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System Energy’s ownership and leasehold interests in Grand Gulf to Entergy Arkansas (36%), Entergy Louisiana (14%), Entergy Mississippi (33%), and Entergy New Orleans (17%). Each of these companies is obligated to make payments to System Energy for its entitlement of capacity and energy on a full cost-of-service basis regardless of the quantity of energy delivered. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenue. The financial condition of System Energy depends upon the continued commercial operation of Grand Gulf and the receipt of such payments. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans generally recover payments made under the Unit Power Sales Agreement through rates charged to their customers.
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In the case of Entergy Arkansas and Entergy Louisiana, payments are also recovered through sales of electricity from their respective retained shares of Grand Gulf. Under a settlement agreement entered into with the APSC in 1985 and amended in 1988, Entergy Arkansas retains 22% of its 36% share of Grand Gulf-related costs and recovers the remaining 78% of its share in rates. In the event that Entergy Arkansas is not able to sell its retained share to third parties, it may sell such energy to its retail customers at a price equal to its avoided cost, which is currently less than Entergy Arkansas’s cost from its retained share. Entergy Arkansas has life-of-resources purchased power agreements with Entergy Louisiana and Entergy New Orleans that sell a portion of the output of Entergy Arkansas’s retained share of Grand Gulf to those companies, with the remainder of the retained share being sold to Entergy Mississippi through a separate life-of-resources purchased power agreement. In a series of LPSC orders, court decisions, and agreements from late 1985 to mid-1988, Entergy Louisiana was granted cost recovery with respect to costs associated with Entergy Louisiana’s share of capacity and energy from Grand Gulf, subject to certain terms and conditions. Entergy Louisiana retains and does not recover from retail ratepayers 18% of its 14% share of the costs of Grand Gulf capacity and energy and recovers the remaining 82% of its share in rates. Entergy Louisiana is allowed to recover through the fuel adjustment clause at 4.6 cents per kWh for the energy related to its retained portion of these costs. Alternatively, Entergy Louisiana may sell such energy to non-affiliated parties at prices above the fuel adjustment clause recovery amount, subject to the LPSC’s approval. Entergy Arkansas also has a life-of-resources purchased power agreement with Entergy Mississippi to sell a portion of the output of Entergy Arkansas’s non-retained share of Grand Gulf. Entergy Mississippi was granted cost recovery for those purchases by the MPSC through its annual unit power cost rate mechanism.
Availability Agreement
The Availability Agreement among System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans was entered into in 1974 in connection with the original financing by System Energy of Grand Gulf. The Availability Agreement provides that System Energy make available to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans all capacity and energy available from System Energy’s share of Grand Gulf.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans also agreed severally to pay System Energy monthly for the right to receive capacity and energy from Grand Gulf in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement) would at least equal System Energy’s total operating expenses for Grand Gulf (including depreciation at a specified rate and expenses incurred in a permanent shutdown of Grand Gulf) and interest charges.
The allocation percentages under the Availability Agreement are fixed as follows: Entergy Arkansas - 17.1%; Entergy Louisiana - 26.9%; Entergy Mississippi - 31.3%; and Entergy New Orleans - 24.7%. The allocation percentages under the Availability Agreement would remain in effect and would govern payments made under such agreement in the event of a shortfall of operating expense funds available to System Energy from other sources, including payments under the Unit Power Sales Agreement.
System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for all of its outstanding series of first mortgage bonds, as well as for its outstanding term loan and the pollution control revenue refunding bonds issued on its behalf. In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they were prohibited by governmental action from making payments under the Availability Agreement (for example, if the FERC reduced or disallowed such payments as constituting excessive rates), they would then make subordinated advances to System Energy in the same amounts and at the same times as the prohibited payments. System Energy would not be allowed to repay these subordinated advances so long as it remained in default under the related indebtedness or in other similar circumstances.
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Each of the assignment agreements relating to the Availability Agreement provides that Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans will make payments directly to System Energy. However, if there is an event of default, those payments must be made directly to the holders of indebtedness that are the beneficiaries of such assignment agreements. The payments must be made pro rata according to the amount of the respective obligations secured.
The obligations of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans to make payments under the Availability Agreement are subject to the receipt and continued effectiveness of all necessary regulatory approvals. Sales of capacity and energy under the Availability Agreement would require that the Availability Agreement be submitted to the FERC for approval with respect to the terms of such sale. No such filing with the FERC has been made because sales of capacity and energy from Grand Gulf are being made pursuant to the Unit Power Sales Agreement. If, for any reason, sales of capacity and energy are made in the future pursuant to the Availability Agreement, the jurisdictional portions of the Availability Agreement would be submitted to the FERC for approval.
Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement to System Energy have exceeded the amounts payable under the Availability Agreement and, therefore, 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 certain of 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 because their Availability Agreement obligations exceed their Unit Power Sales Agreement obligations.
The Availability Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, without further consent of any assignees or other creditors.
Service Companies
Entergy Services, a limited liability company wholly-owned by Entergy Corporation, provides management, administrative, accounting, legal, engineering, and other services primarily to the Utility operating companies, but also provides services to Entergy Wholesale Commodities. Entergy Operations is also wholly-owned by Entergy Corporation and provides nuclear management, operations and maintenance services under contract for ANO, River Bend, Waterford 3, and Grand Gulf, subject to the owner oversight of Entergy Arkansas, Entergy Louisiana, and System Energy, respectively. Entergy Services and Entergy Operations provide their services to the Utility operating companies and System Energy on an “at cost” basis, pursuant to cost allocation methodologies for these service agreements that were approved by the FERC.
Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas
Effective December 31, 2007, Entergy Gulf States, Inc. completed a jurisdictional separation into two vertically integrated utility companies, one operating under the sole retail jurisdiction of the PUCT, Entergy Texas, and the other operating under the sole retail jurisdiction of the LPSC, Entergy Gulf States Louisiana. Entergy Texas owns all Entergy Gulf States, Inc. distribution and transmission assets located in Texas, the gas-fired generating plants located in Texas, undivided 42.5% ownership shares of Entergy Gulf States, Inc.’s 70% ownership interest in Nelson Unit 6 and 42% ownership interest in Big Cajun 2, Unit 3, which are coal-fired generating plants located in Louisiana, and other assets and contract rights to the extent related to utility operations in Texas. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, owns all of the remaining assets that were owned by Entergy Gulf States, Inc. On a book value basis, approximately 58.1% of the Entergy Gulf States, Inc. assets were allocated to Entergy Gulf States Louisiana and approximately 41.9% were allocated to Entergy Texas.
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Entergy Texas purchases from Entergy Louisiana pursuant to a life-of-unit purchased power agreement a 42.5% share of capacity and energy from the 70% of River Bend subject to retail regulation. Entergy Texas was allocated a share of River Bend’s nuclear and environmental liabilities that is identical to the share of the plant’s output purchased by Entergy Texas under the purchased power agreement. In connection with the termination of the System Agreement effective August 31, 2016, the purchased power agreements that were put in place for certain legacy units at the time of the jurisdictional separation were also terminated at that time. See Note 2 to the financial statements for additional discussion of the purchased power agreements.
Entergy Louisiana and Entergy Gulf States Louisiana Business Combination
On October 1, 2015, the businesses formerly conducted by Entergy Louisiana (Old Entergy Louisiana) and Entergy Gulf States Louisiana (Old Entergy Gulf States Louisiana) were combined into a single public utility. In order to effect the business combination, under the Texas Business Organizations Code (TXBOC), Old Entergy Louisiana allocated substantially all of its assets to a new subsidiary, Entergy Louisiana Power, LLC, a Texas limited liability company (New Entergy Louisiana), and New Entergy Louisiana assumed the liabilities of Old Entergy Louisiana, in a transaction regarded as a merger under the TXBOC. Under the TXBOC, Old Entergy Gulf States Louisiana allocated substantially all of its assets to a new subsidiary (New Entergy Gulf States Louisiana) and New Entergy Gulf States Louisiana assumed the liabilities of Old Entergy Gulf States Louisiana, in a transaction regarded as a merger under the TXBOC. New Entergy Gulf States Louisiana then merged into New Entergy Louisiana with New Entergy Louisiana surviving the merger. Thereupon, Old Entergy Louisiana changed its name from “Entergy Louisiana, LLC” to “EL Investment Company, LLC” and New Entergy Louisiana changed its name from “Entergy Louisiana Power, LLC” to “Entergy Louisiana, LLC” (Entergy Louisiana). With the completion of the business combination, Entergy Louisiana holds substantially all of the assets, and has assumed the liabilities, of Old Entergy Louisiana and Old Entergy Gulf States Louisiana.
Entergy New Orleans Internal Restructuring
In November 2017, pursuant to the agreement in principle, Entergy New Orleans, Inc. undertook a multi-step restructuring, including the following:
•Entergy New Orleans, Inc. redeemed its outstanding preferred stock at a price of approximately $21 million, which included a call premium of approximately $819,000, plus any accumulated and unpaid dividends.
•Entergy New Orleans, Inc. converted from a Louisiana corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy New Orleans, Inc. allocated substantially all of its assets to a new subsidiary, Entergy New Orleans Power, LLC, a Texas limited liability company (Entergy New Orleans Power), and Entergy New Orleans Power assumed substantially all of the liabilities of Entergy New Orleans, Inc. in a transaction regarded as a merger under the TXBOC. Entergy New Orleans, Inc. remained in existence and held the membership interests in Entergy New Orleans Power.
•Entergy New Orleans, Inc. contributed the membership interests in Entergy New Orleans Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy New Orleans Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2017, Entergy New Orleans, Inc. changed its name to Entergy Utility Group, Inc., and Entergy New Orleans Power then changed its name to Entergy New Orleans, LLC. Entergy New Orleans, LLC holds substantially all of the assets, and has assumed substantially all of the liabilities, of Entergy New Orleans, Inc. The restructuring was accounted for as a transaction between entities under common control.
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Entergy Arkansas Internal Restructuring
In November 2018, Entergy Arkansas undertook a multi-step restructuring, including the following:
•Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.
•Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Arkansas Power, LLC, a Texas limited liability company (Entergy Arkansas Power), and Entergy Arkansas Power assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.
•Entergy Arkansas, Inc. contributed the membership interests in Entergy Arkansas Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Arkansas Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Arkansas, Inc. changed its name to Entergy Utility Property, Inc., and Entergy Arkansas Power then changed its name to Entergy Arkansas, LLC. Entergy Arkansas, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Arkansas, Inc. The transaction was accounted for as a transaction between entities under common control.
Entergy Mississippi Internal Restructuring
In November 2018, Entergy Mississippi undertook a multi-step restructuring, including the following:
•Entergy Mississippi, Inc. redeemed its outstanding preferred stock, at the aggregate redemption price of approximately $21.2 million.
•Entergy Mississippi, Inc. converted from a Mississippi corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Mississippi, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Mississippi Power and Light, LLC, a Texas limited liability company (Entergy Mississippi Power and Light), and Entergy Mississippi Power and Light assumed substantially all of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Mississippi, Inc. remained in existence and held the membership interests in Entergy Mississippi Power and Light.
•Entergy Mississippi, Inc. contributed the membership interests in Entergy Mississippi Power and Light to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Mississippi Power and Light is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Mississippi, Inc. changed its name to Entergy Utility Enterprises, Inc., and Entergy Mississippi Power and Light then changed its name to Entergy Mississippi, LLC. Entergy Mississippi, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Mississippi, Inc. The restructuring was accounted for as a transaction between entities under common control.
Entergy Wholesale Commodities
See “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the shutdown and sale of each of the Entergy Wholesale Commodities nuclear power plants. With the sale of Palisades in June 2022, Entergy completed its multi-year strategy to exit the merchant power business.
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Entergy Wholesale Commodities includes the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. Entergy Wholesale Commodities also provides decommissioning-related services to nuclear power plants owned by non-affiliated entities in the United States.
Property
Entergy Wholesale Commodities includes ownership in the following non-nuclear power plants:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Plant | | Location | | Ownership | | Net Owned Capacity (a) | | Type |
| Independence Unit 2; 842 MW | | Newark, AR | | 14% | | 121 MW(b) | | Coal |
| Nelson Unit 6; 550 MW | | Westlake, LA | | 11% | | 60 MW(b) | | Coal |
(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.
All of Entergy Wholesale Commodities’ owned generation falls under the authority of MISO. Entergy Wholesale Commodities’ customers for the sale of both energy and capacity from its owned generation and its contracted power purchases include retail power providers, utilities, electric power co-operatives, power trading organizations, and other power generation companies. The majority of Entergy Wholesale Commodities’ owned generation and contracted power purchases are sold under cost-based contract.
Other Business Activities
TLG Services, a subsidiary in the Entergy Wholesale Commodities segment, offers decommissioning, engineering, and related services to nuclear power plant owners.
Regulation of Entergy’s Business
Federal Power Act
The Federal Power Act provides the FERC the authority to regulate:
•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.
The Federal Power Act gives the FERC jurisdiction over the rates charged by System Energy for Grand Gulf capacity and energy provided to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans and over the rates charged by Entergy Arkansas and Entergy Louisiana to unaffiliated wholesale customers. The FERC also regulates wholesale power sales between the Utility operating companies. In addition, the FERC regulates the MISO RTO, an independent entity that maintains functional control over the combined transmission systems of its members and administers wholesale energy, capacity, and ancillary services markets for market participants in the MISO region, including the Utility operating companies. FERC regulation of the MISO RTO includes regulation of the design and implementation of the wholesale markets administered by the MISO RTO, as
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well as the rates, terms, and conditions of open access transmission service over the member systems and the allocation of costs associated with transmission upgrades.
Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 65 MW of capacity.
State Regulation
Utility
Entergy Arkansas is subject to regulation by the APSC as to the following:
•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 non-exempt 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.
Additionally, Entergy Arkansas serves a limited number of retail customers in Tennessee. Pursuant to legislation enacted in Tennessee, Entergy Arkansas is subject to complaints before the Tennessee Regulatory Authority only if it fails to treat its retail customers in Tennessee in the same manner as its retail customers in Arkansas. Additionally, Entergy Arkansas maintains limited facilities in Missouri but does not provide retail electric service to customers in Missouri. Although Entergy Arkansas obtained a certificate with respect to its Missouri facilities, Entergy Arkansas is not subject to retail ratemaking jurisdiction in Missouri.
Entergy Louisiana’s electric and gas business is subject to regulation by the LPSC as to the following:
•utility service;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment clause, environmental adjustment charge, 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 for purchase power contracts that exceed either 5 MW or one year in term;
•procurement process to acquire capacity over 50 MW;
•audits of the energy efficiency rider;
•avoided cost payment to non-exempt Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers and acquisitions and other changes of control.
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Entergy Mississippi is subject to regulation by the MPSC as to the following:
•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;
•certification of generating facilities and certain transmission projects;
•avoided cost payments to non-exempt Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers, acquisitions, and other changes of control.
Entergy Mississippi is also subject to regulation by the APSC as to the certificate of environmental compatibility and public need for the Independence Station, which is located in Arkansas.
Entergy New Orleans is subject to regulation by the City Council as to the following:
•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;
•avoided cost payments to non-exempt Qualifying Facilities;
•issuance and sale of certain securities; and
•utility mergers and acquisitions and other changes of control.
To the extent authorized by governing legislation, Entergy Texas is subject to the original jurisdiction of the municipal authorities of a number of incorporated cities in Texas with appellate jurisdiction over such matters residing in the PUCT. Entergy Texas is also subject to regulation by the PUCT as to the following:
•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 non-exempt Qualifying Facilities;
•net energy metering; 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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Regulation of the Nuclear Power Industry
Atomic Energy Act of 1954 and Energy Reorganization Act of 1974
Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose civil penalties or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, Entergy Louisiana, and System Energy, as owners of all or portions of ANO, River Bend and Waterford 3, and Grand Gulf, respectively, and Entergy Operations, as the licensee and operator of these units, are subject to the jurisdiction of the NRC.
Nuclear Waste Policy Act of 1982
Spent Nuclear Fuel
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 Arkansas is the only one of the Utility operating companies that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 2022 of $195.0 million for the one-time fee. The fees payable to the DOE may be adjusted in the future to assure full recovery. 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. Entergy’s total spent fuel fees to date, including the one-time fee liability of Entergy Arkansas, have surpassed $1.7 billion (exclusive of amounts relating to Entergy plants that were paid or are owed by prior owners of those plants).
The permanent spent fuel repository in the U.S. has been legislated to be Yucca Mountain, Nevada. The DOE is required by law to proceed with the licensing (the DOE filed the license application in June 2008) and, after the license is granted by the NRC, proceed with the repository construction and commencement of receipt of spent fuel. 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. The DOE continues to delay meeting its obligation. Specific steps were taken to discontinue the Yucca Mountain project, including a motion to the NRC to withdraw the license application with prejudice and the establishment of a commission to develop recommendations for alternative spent fuel storage solutions. In August 2013 the U.S. Court of Appeals for the D.C. Circuit ordered the NRC to continue with the Yucca Mountain license review, but only to the extent of funds previously appropriated by Congress for that purpose and not yet used. Although the NRC completed the safety evaluation report for the license review in 2015, the previously appropriated funds are not sufficient to complete the review, including required hearings. The government has taken no effective action to date related to the recommendations of the appointed spent fuel study commission. Accordingly, large uncertainty remains regarding the time frame under which the DOE will begin to accept spent fuel from Entergy’s facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at Entergy’s nuclear sites.
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 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
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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.
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. These subsidiaries have been, and continue to be, involved in litigation to recover the damages caused by the DOE’s delay in performance. See Note 8 to the financial statements for discussion of final judgments recorded by Entergy in 2020, 2021, and 2022 related to Entergy’s nuclear owner licensee subsidiaries’ litigation with the DOE. Through 2022, Entergy’s subsidiaries have won and collected on judgments against the government totaling approximately $1 billion.
Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are providing their own spent fuel storage. Storage capability additions using dry casks began operations at ANO in 1996, at River Bend in 2005, at Grand Gulf in 2006, and at Waterford 3 in 2011. These facilities will be expanded as needed.
Nuclear Plant Decommissioning
Entergy Arkansas, Entergy Louisiana, and System Energy are entitled to recover from customers through electric rates the estimated decommissioning costs for ANO, Waterford 3, and Grand Gulf, respectively. In addition, Entergy Louisiana and Entergy Texas are entitled to recover from customers through electric rates the estimated decommissioning costs for the portion of River Bend subject to retail rate regulation. The collections are deposited in trust funds that can only be used in accordance with NRC and other applicable regulatory requirements. Entergy periodically reviews and updates the estimated decommissioning costs to reflect inflation and changes in regulatory requirements and technology, and then makes applications to the regulatory authorities to reflect, in rates, the changes in projected decommissioning costs.
In December 2018 the APSC ordered collections in rates for decommissioning ANO 2 and found that ANO 1’s decommissioning was adequately funded without additional collections. In November 2021, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that both ANO 1 and 2 decommissioning trusts were adequately funded without further collections, and in December 2021 the APSC ordered zero collections for ANO 1 and 2 decommissioning. In November 2022, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that ANO 1’s decommissioning trust was adequately funded, but that ANO 2’s fund had a projected shortage as a result of a decline in decommissioning trust fund investment values over the past year. The filing proposes a reinstatement of decommissioning cost recovery for ANO 2. Management cannot predict the outcome of this filing.
In July 2010 the LPSC approved increased decommissioning collections for Waterford 3 and the Louisiana regulated share of River Bend to address previously identified funding shortfalls. This LPSC decision contemplated that the level of decommissioning collections could be revisited should the NRC grant license extensions for both Waterford 3 and River Bend. In July 2019, following the NRC approval of license extensions for Waterford 3 and River Bend, Entergy Louisiana made a filing with the LPSC seeking to adjust decommissioning and depreciation rates for those plants, including one proposed scenario that would adjust Louisiana-jurisdictional decommissioning collections to zero for both plants (including an offsetting increase in depreciation rates). Because of the ongoing public health emergency arising from the COVID-19 pandemic and accompanying economic uncertainty, Entergy Louisiana determined that the relief sought in the filing was no longer appropriate, and in November 2020, filed an unopposed motion to dismiss the proceeding. Following that filing, in a December 2020 order, the LPSC dismissed the proceeding without prejudice. In July 2021, Entergy Louisiana made a filing with the LPSC to adjust Waterford 3 and River Bend decommissioning collections based on the latest site-specific decommissioning cost estimates for those plants. The filing seeks to increase Waterford 3 decommissioning collections and decrease River Bend decommissioning collections. The procedural schedule in the case has been suspended pending settlement negotiations. Management cannot predict the outcome of this filing.
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In December 2010 the PUCT approved increased decommissioning collections for the Texas share of River Bend to address previously identified funding shortfalls. In December 2018 the PUCT approved a settlement that eliminated River Bend decommissioning collections for the Texas jurisdictional share of the plant based on a determination by Entergy Texas that the existing decommissioning fund was adequate following license renewal. In July 2022, Entergy Texas filed a rate case that proposed continuation of the cessation of River Bend decommissioning collections. In December 2022, Entergy Texas filed on behalf of the parties a motion to abate the hearing on the merits to give parties additional time to finalize a settlement, which was approved by the presiding ALJ along with an order for the parties to file monthly settlement status reports. Management cannot predict the outcome of this filing.
In December 2016 the NRC issued a 20-year operating license renewal for Grand Gulf. In a 2017 filing at the FERC, System Energy stated that with the renewed operating license, Grand Gulf’s decommissioning trust was sufficiently funded, and proposed, among other things, to cease decommissioning collections for Grand Gulf effective October 1, 2017. The FERC accepted a settlement including the proposed decommissioning revenue requirement by letter order in August 2018.
Entergy currently believes its decommissioning funding will be sufficient for its nuclear plants subject to retail rate regulation, although decommissioning cost inflation and trust fund performance will ultimately determine the adequacy of the funding amounts.
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. In March 2021 filings with the NRC were made reporting on decommissioning funding for all of Entergy’s subsidiaries’ nuclear plants. Those reports showed that decommissioning funding for each of the nuclear plants met the NRC’s financial assurance requirements.
Additional information with respect to Entergy’s decommissioning costs and decommissioning trust funds is found in Note 9 and Note 16 to the financial statements.
Price-Anderson Act
The Price-Anderson Act requires that reactor licensees purchase and maintain the maximum amount of nuclear liability insurance available and participate in an industry assessment program called Secondary Financial Protection in order to protect 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 limits the contingent liability for a single nuclear incident to a maximum assessment of approximately $137.6 million per reactor (with 96 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, Entergy Louisiana, or System Energy is liable, protection is afforded through a combination of private insurance and the Secondary Financial Protection program. In addition to this, insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units is also purchased. The Price-Anderson Act and insurance applicable to the nuclear programs of Entergy are discussed in more detail in Note 8 to the financial statements.
NRC Reactor Oversight Process
The NRC’s Reactor Oversight Process is a program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response. The NRC evaluates plant performance by analyzing two distinct inputs: inspection findings resulting from the NRC’s inspection program and performance indicators reported by the licensee. The evaluations result in the placement of
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each plant in one of the NRC’s Reactor Oversight Process Action Matrix columns: “licensee response column,” or Column 1, “regulatory response column,” or Column 2, “degraded cornerstone column,” or Column 3, and “multiple/repetitive degraded cornerstone column,” or Column 4, and “unacceptable performance,” or Column 5. Plants in Column 1 are subject to normal NRC inspection activities. Plants in Column 2, Column 3, or Column 4 are subject to progressively increasing levels of inspection by the NRC. Continued plant operation is not permitted for plants in Column 5. All of the nuclear generating plants owned and operated by Entergy’s Utility business are currently in Column 1, except Waterford 3, which is in Column 2.
In September 2022 the NRC placed Waterford 3 in Column 2 based on an error associated with a radiation monitor calibration. Entergy corrected the issue with the radiation monitor in February 2022; however, Waterford 3 is expected to remain in Column 2 until third quarter 2023 based on a subsequent radiation monitor calibration issue.
Environmental Regulation
Entergy’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy’s businesses are in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted below. Because environmental regulations are subject to change, future compliance requirements and costs cannot be precisely estimated. Except to the extent discussed below, at this time compliance with federal, state, and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of Entergy’s businesses and is not expected to have a material effect on their competitive position, results of operations, cash flows, or financial position.
Clean Air Act and Subsequent Amendments
The Clean Air Act and its amendments establish several programs that currently or in the future may affect Entergy’s fossil-fueled generation facilities and, to a lesser extent, certain operations at nuclear and other facilities. Individual states also operate similar independent state programs or delegated federal programs that may include requirements more stringent than federal regulatory requirements. These programs include:
•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.
National Ambient Air Quality Standards
The Clean Air Act requires the EPA to set National Ambient Air Quality Standards (NAAQS) for ozone, carbon monoxide, lead, nitrogen dioxide, particulate matter, and sulfur dioxide, and requires periodic review of those standards. When an area fails to meet an ambient standard, it is considered to be in nonattainment and is classified as “marginal,” “moderate,” “serious,” or “severe.” When an area fails to meet the ambient air standard, the EPA requires state regulatory authorities to prepare state implementation plans meant to cause progress toward bringing the area into attainment with applicable standards.
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Ozone Nonattainment
Entergy Texas operates two fossil-fueled generating facilities (Lewis Creek and Montgomery County Power Station) in a geographic area that is not in attainment with the applicable NAAQS for ozone. The ozone nonattainment area that affects Entergy Texas is the Houston-Galveston-Brazoria area. Both Lewis Creek and the Montgomery County Power Station hold all necessary permits for operation and comply with applicable air quality program regulations. Measures enacted to return the area to ozone attainment could make these program regulations more stringent. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and nonattainment with the ozone NAAQS.
Potential SO2Nonattainment
The EPA issued a final rule in June 2010 adopting an SO2 1-hour national ambient air quality standard of 75 parts per billion. In Entergy’s utility service territory, only St. Bernard Parish and Evangeline Parish in Louisiana are designated as nonattainment. In August 2017 the EPA issued a letter indicating that East Baton Rouge and St. Charles parishes would be designated by December 31, 2020, as monitors were installed to determine compliance. In March 2021 the EPA published a final rule designating East Baton Rouge, St. Charles, St. James, and West Baton Rouge parishes in Louisiana as attainment/unclassifiable, and, in Texas, Jefferson County as attainment/unclassifiable and Orange County as unclassifiable. No challenges to these final designations were filed within the 60 day deadline. Entergy continues to monitor this situation.
Hazardous Air Pollutants
The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011, which had a compliance date, with a widely granted one-year extension, of April 2016. The required controls have been installed and are operational at all affected Entergy units. In May 2020 the EPA finalized a rule that finds that it is not “appropriate and necessary” to regulate hazardous air pollutants from electric steam generating units under the provisions of section 112(n) of the Clean Air Act. This is a reversal of the EPA’s previous finding requiring such regulation. The final appropriate and necessary finding does not revise the underlying MATS rule. Several lawsuits have been filed challenging the appropriate and necessary finding. In February 2021 the D.C. Circuit granted the EPA’s motion to hold the litigation in abeyance pending the agency’s review of the appropriate and necessary rule. In February 2022 the EPA issued a proposed rule revoking the 2020 rule and determining, again, that it is “appropriate and necessary” to regulate hazardous air pollutants. The EPA is seeking additional information, which it could use to further tighten the standard. Entergy will continue to monitor this situation.
Cross-State Air Pollution
In March 2005 the EPA finalized the Clean Air Interstate Rule (CAIR), which was intended to reduce SO2 and NOx emissions from electric generation plants in order to improve air quality in twenty-nine eastern states. The rule required a combination of capital investment to install pollution control equipment and increased operating costs through the purchase of emission allowances. Entergy began implementation in 2007, including installation of controls at several facilities and the development of an emission allowance procurement strategy. Based on several court challenges, CAIR and its subsequent versions, now known as the Cross-State Air Pollution Rule (CSAPR), have been remanded to and modified by the EPA on multiple occasions.
In April 2022 the EPA published a rule to address interstate transport for the 2015 ozone NAAQS which will increase the stringency of the CSAPR program in all four of the states where the Utility operating companies operate. If finalized as proposed, the rule will significantly reduce emission allowances and would likely require the installation of post-combustion nitrogen oxides (NOx) emissions controls on any coal or large legacy gas units that will operate beyond 2026 and are not currently equipped with such controls. Fifteen Entergy-owned units, totaling approximately 9,370 MW of total unit capacity, are identified by the EPA for selective catalytic reduction retrofits.
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Based on the EPA estimates, Entergy’s share of the capital costs would be approximately $1.6 billion if all the identified units were in fact retrofitted. Additionally, the EPA is proposing controls on certain non-electric generating NOx sources. Since releasing the proposed rule, the price for Group 3 NOx sources allowances has increased significantly, peaking at over $45,000 per allowance in late August 2022 before stabilizing in the range of $15,000 to $18,000 per allowance since September 2022. Comments on the proposed rule were due in June 2022. MISO, other impacted regional transmission organizations, and various state public service commissions all filed comments expressing reliability concerns if the rule is finalized as proposed. Entergy filed individual comments which assert, in addition to other issues, that the EPA’s proposal represents over-control of the Entergy units in Arkansas and Mississippi; the EPA should consider an alternative approach or provide flexibility for units with a limited remaining useful life; the EPA should consult with regional transmission organizations to determine the reliability impacts of the proposed rule; and the EPA should consider and incorporate current economic trends, including inflation, into any benefit-costs analysis supporting the rule.
Regional Haze
In June 2005 the EPA issued its final Clean Air Visibility Rule (CAVR) regulations that potentially could result in a requirement to install SO2 and NOx pollution control technology as Best Available Retrofit Control Technology to continue operating certain of Entergy’s fossil generation units. The rule leaves certain CAVR determinations to the states. This rule establishes a series of 10-year planning periods, with states required to develop State Implementation Plans (SIPs) for each planning period, with each SIP including such air pollution control measures as may be necessary to achieve the ultimate goal of the CAVR by the year 2064. The various states are currently in the process of developing SIPs to implement the second planning period of the CAVR, which addresses the 2018-2028 planning period.
In January and February 2018, Entergy Arkansas, Entergy Mississippi, Entergy Power, and other co-owners received 60-day notice of intent to sue letters from the Sierra Club and the National Parks Conservation Association concerning allegations of violations of new source review and permitting provisions of the Clean Air Act at the Independence and White Bluff coal-burning units, respectively. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims and reducing the risk that Entergy Arkansas, as operator of Independence and White Bluff, might be compelled under the Clean Air Act’s regional haze program to install costly emissions control technologies. Consistent with the terms of the settlement, Entergy Arkansas, along with co-owners, agreed to begin using only low-sulfur coal at Independence and White Bluff by mid-2021; agreed to cease using coal at White Bluff and Independence by the end of 2028 and 2030, respectively; agreed to cease operation of the remaining gas unit at Lake Catherine by the end of 2027; reserved the option to develop new generating sources at each plant site; and committed to installing or proposing to regulators at least 800 MWs of renewable generation by the end of 2027, with at least half installed or proposed by the end of 2022 (which includes two existing Entergy Arkansas projects) and with all qualifying co-owner projects counting toward satisfaction of the obligation. Under the settlement, the Sierra Club and the National Parks Conservation Association also waived certain potential existing claims under federal and state environmental law with respect to specified generating plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the National Parks Conservation Association, was subject to approval by the U.S. District Court for the Eastern District of Arkansas. In November 2020 the court denied motions by the Arkansas Attorney General and the Arkansas Affordable Energy Coalition to intervene and to stay the proceedings. The proposed intervenors did not appeal the ruling. The District Court approved and entered the proposed settlement in March 2021. Entergy met the settlement deadline to use low-sulfur coal and is on target to meet the other requirements of the settlement. See “Remaining Useful Lives Review” in the “State and Local Rate Regulation and Fuel-Cost Recovery” section of Entergy Arkansas, LLC and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the APSC’s proceeding related to Entergy Arkansas’s utility generation units.
The second planning period (2018-2028) for the regional haze program requires states to examine sources for impacts on visibility and to prepare SIPs by July 31, 2021 to ensure reasonable progress is being made to attain
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visibility improvements. Entergy received information collection requests from the Arkansas and Louisiana Departments of Environmental Quality requesting an evaluation of technical and economic feasibility of various NOx and SO2 control technologies for Independence, Nelson 6, Nelson Industrial Steam Company (NISCO), and Ninemile. Responses to the information collection requests have been submitted to the respective state agencies. Louisiana has issued its draft SIP which, at this time, does not propose any additional air emissions controls for the affected Entergy units in Louisiana. Some public commenters, however, believe additional air controls are cost-effective. It is not yet clear how the Louisiana Department of Environmental Quality (LDEQ) will respond in its final SIP, and the agency, like many other state agencies, did not meet the July 31, 2021 deadline to submit a SIP to the EPA for review.
Similar to the LDEQ, the Arkansas Department of Energy and Environment, Division of Environmental Quality (ADEQ) did not meet the July 31, 2021 SIP submission deadline, but subsequently submitted it to the EPA for review. The ADEQ reviewed Entergy’s Independence plant, but determined that additional air emission controls would not be cost-effective considering the facility’s commitment to cease coal-fired combustion by December 31, 2030.
The Texas Commission on Environmental Quality has completed its second-planning period SIP and submitted it to the EPA for review. There were no Entergy sources selected for additional emission controls. The Mississippi Department of Environmental Quality continues to develop its SIP, but there are no Entergy sources that are expected to be impacted.
In August 2022 the EPA issued findings of failure to submit regional haze SIPs to 15 states, including Louisiana and Mississippi. These findings were effective September 2022 and start the two-year period for the EPA to either approve a SIP submitted by the state or issue a final federal plan.
Greenhouse Gas Emissions
In July 2019 the EPA released the Affordable Clean Energy Rule (ACE), which applies only to existing coal-fired electric generating units. The ACE determines that heat rate improvements are the best system of emission reductions and lists six candidate technologies for consideration by states at each coal unit. The rule and associated rulemakings by the EPA replace the Obama administration’s Clean Power Plan, which established national emissions performance rates for existing fossil-fuel fired steam electric generating units and combustion turbines. The ACE rule provides states discretion in determining how the best system for emission reductions applies to individual units, including through the consideration of technical feasibility and the remaining useful life of the facility. The ADEQ and the LDEQ have issued information collection requests to Entergy facilities to help the states collect the information needed to determine the best system of emission reductions for each facility. Entergy responded to the requests. In January 2021 the U.S. Court of Appeals for the D.C. Circuit vacated ACE. The court held that ACE relied on an incorrect interpretation of the Clean Air Act that the statute expressly forecloses emission reduction approaches, such as emissions trading and generating shifting, that cannot be applied at and to the individual source. The court remanded ACE to the EPA for further consideration and also vacated the repeal of the Clean Power Plan. In March 2021 the D.C. Circuit issued a partial mandate vacating the ACE rule, but withheld the mandate vacating the repeal of the Clean Power Plan pending the EPA’s new rulemaking to regulate greenhouse gas emissions. Thus, there currently is no regulation in place with respect to greenhouse gas emissions from existing electric generating units and states are not expected to take further action to develop and submit plans at this time. In October 2021 the United States Supreme Court agreed to hear a challenge to the already vacated ACE rule. In June 2022 the United States Supreme Court held that the EPA could not use generation shifting as the best system of emission reduction under Section 111(d) of the Clean Air Act. The EPA does still have the authority to regulate greenhouse gas emissions, but those emissions reductions must be technology based. The EPA has announced its intent to propose a rule for existing power plants pursuant to the Clean Air Act by March 2023. The ultimate impact of the United States Supreme Court's decision cannot be determined at this time.
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In April 2021, President Biden announced a target for the United States in connection with the United Nations’ “Paris Agreement” on climate change. The target consists of a 50-52 percent reduction in economy-wide net greenhouse gas emissions from 2005 levels by 2030. President Biden has also stated that a goal of his administration is for the electric power industry to decarbonize fully by 2035. The details surrounding implementation of these targets are not finalized, and the impacts to Entergy of any potential related legislation cannot be predicted.
Entergy continues to support national legislation that would most efficiently reduce economy-wide greenhouse gas emissions and increase planning certainty for electric utilities. By virtue of its proportionally large investment in low-emitting generation technologies, Entergy has a low overall carbon dioxide emission “intensity,” or rate of carbon dioxide emitted per megawatt-hour of electricity generated. In anticipation of the imposition of carbon dioxide emission limits on the electric industry, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included a formal program to stabilize owned power plant carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in reducing emissions below 2000 levels. In 2006, Entergy started including emissions from controllable power purchases in addition to its ownership share of generation and established a second formal voluntary program to stabilize power plant carbon dioxide emissions and emissions from controllable power purchases, cumulatively over the period, at 20% below 2000 levels through 2010. In 2011, Entergy extended this commitment through 2020, which it ultimately outperformed by approximately 8% both cumulatively and on an annual basis. In 2019, in connection with a climate scenario analysis following the recommendations of the Task Force on Climate-related Financial Disclosures describing climate-related governance, strategy, risk management, and metrics and targets, Entergy announced a 2030 carbon dioxide emission rate goal focused on a 50% reduction from Entergy’s base year - 2000. Entergy now anticipates achieving this reduction several years early. In September 2020, Entergy announced a commitment to achieve net-zero greenhouse gas emissions by 2050 inclusive of all businesses, all applicable gases, and all emission scopes. In 2022, Entergy enhanced its commitment to include an interim goal of 50% carbon-free energy generating capacity by 2030 and expanded its interim emission rate goal to include all purchased power. See “Risk Factors” in Part I Item 1A for discussion of the risks associated with achieving these climate goals. Entergy’s comprehensive, third-party verified greenhouse gas inventory and progress against its voluntary goals are published on its website.
Entergy participates in the M.J. Bradley & Associates’ Annual Benchmarking Air Emissions Report, an annual analysis of the 100 largest U.S. electric power producers. The report is available on the M.J. Bradley website. Entergy participates annually in the Dow Jones Sustainability Index and in 2022 was listed on the North American Index. Entergy has been listed on the World or North American Index, or both, for 21 consecutive years. Entergy also participated in the 2022 CDP Climate Change and CDP Water Security evaluations, receiving a ‘B’ for both responses.
Potential Legislative, Regulatory, and Judicial Developments
In addition to the specific instances described above, there are a number of legislative and regulatory initiatives that are under consideration at the federal, state, and local level. Because of the nature of Entergy’s business, the imposition of any of these initiatives could affect Entergy’s operations. Entergy continues to monitor these initiatives and activities in order to analyze their potential operational and cost implications. These initiatives include:
•reconsideration and revision of ambient air quality standards downward which could lead to additional areas of nonattainment;
•designation by the EPA and state environmental agencies of areas that are not in attainment with national ambient air quality standards;
•introduction of bills in Congress and development of regulations by the EPA proposing further limits on SO2, mercury, carbon dioxide, and other air emissions. New legislation or regulations applicable to
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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 cap and trade programs to limit carbon dioxide and other greenhouse gases;
•efforts on the local, 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 polychlorinated biphenyls (PCBs);
•efforts by certain external groups to encourage reporting and disclosure of environmental, social, and governance 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;
•the regulation of the management, disposal, and beneficial reuse of coal combustion residuals; and
•the regulation of the management and disposal and recycling of equipment associated with renewable and clean energy sources such as used solar panels, wind turbine blades, hydrogen usage, or battery storage.
Clean Water Act
The 1972 amendments to the Federal Water Pollution Control Act (known as the Clean Water Act) provide the statutory basis for the National Pollutant Discharge Elimination System permit program, section 402, and the basic structure for regulating the discharge of pollutants from point sources to waters of the United States. The Clean Water Act requires virtually all discharges of pollutants to waters of the United States to be permitted. Section 316(b) of the Clean Water Act regulates cooling water intake structures, section 401 of the Clean Water Act requires a water quality certification from the state in support of certain federal actions and approvals, and section 404 regulates the dredge and fill of waters of the United States, including jurisdictional wetlands.
Federal Jurisdiction of Waters of the United States
In June 2020 the EPA’s revised definition of waters of the United States in the Navigable Waters Protection Rule (NWPR) became effective, narrowing the scope of Clean Water Act jurisdiction, as compared to a 2015 definition which had been stayed by several federal courts. In August 2021 a federal district court vacated and remanded the NWPR for further consideration. The EPA and the U.S. Army Corps of Engineers (Corps) subsequently issued a statement that the agencies would revert to pre-2015 regulations pending a new rulemaking. In December 2022 the EPA and the Corps released a final definition of waters of the United States that replaces the NWPR with a definition that is consistent with the pre-2015 regulatory regime as interpreted by several United States Supreme Court decisions. Most notably, the exclusion for waste treatment systems is retained.
Comprehensive Environmental Response, Compensation, and Liability Act of 1980
The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), authorizes the EPA to mandate clean-up by, or to collect reimbursement of clean-up costs from, owners or operators of sites at which hazardous substances may be or have been released. Certain private parties also may use CERCLA to recover response costs. Parties that transported hazardous substances to these sites or arranged for the disposal of the substances are also deemed liable by CERCLA. CERCLA has been interpreted to impose strict, joint, and several liability on responsible parties. Many states have adopted programs similar to CERCLA. Entergy subsidiaries in the Utility and Entergy Wholesale Commodities businesses have sent waste materials to various
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disposal sites over the years, and releases have occurred at Entergy facilities including nuclear facilities that have been or will be sold to decommissioning companies. In addition, environmental laws now regulate certain of Entergy’s operating procedures and maintenance practices that historically were not subject to regulation. Some disposal sites used by Entergy subsidiaries have been the subject of governmental action under CERCLA or similar state programs, resulting in site clean-up activities. Entergy subsidiaries have participated to various degrees in accordance with their respective potential liabilities in such site clean-ups and have developed experience with clean-up costs. The affected Entergy subsidiaries have established provisions for the liabilities for such environmental clean-up and restoration activities. Details of potentially material CERCLA and similar state program liabilities are discussed in the “Other Environmental Matters” section below.
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. As of December 31, 2022, Entergy has recorded asset retirement obligations related to CCR management of $27 million.
Pursuant to the EPA Rule, Entergy operates groundwater monitoring systems surrounding its coal combustion residual landfills located at White Bluff, Independence, and Nelson. Monitoring to date has detected concentrations of certain listed constituents in the area, but has not indicated that these constituents originated at the active landfill cells. Reporting has occurred as required, and detection monitoring will continue as the rule requires. In late-2017, Entergy determined that certain in-ground wastewater treatment system recycle ponds at its White Bluff and Independence facilities require management under the new EPA regulations. Consequently, in order to move away from using the recycle ponds, White Bluff and Independence each have installed a new permanent bottom ash handling system that does not fall under the CCR rule. As of November 2020, both sites are operating the new system and no longer are sending waste to the recycle ponds. Each site has commenced closure of its two recycle ponds (four ponds total), prior to the April 11, 2021 deadline under the finalized CCR rule for unlined recycle ponds. Any potential requirements for corrective action or operational changes under the new CCR rule continue to be assessed. Notably, ongoing litigation has resulted in the EPA’s continuing review of the rule. Consequently, the nature and cost of additional corrective action requirements may depend, in part, on the outcome of the EPA’s review.
Other Environmental Matters
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas
The EPA notified Entergy that the EPA believes Entergy is a PRP concerning PCB contamination at the F.J. Doyle Salvage facility in Leonard, Texas. The facility operated as a scrap salvage business during the 1970s to the 1990s. In May 2018 the EPA investigated the site surface and sub-surface soils and, in November 2018 the EPA conducted a removal action, including disposal of PCB contaminated soils. Entergy responded to the EPA’s information requests in May and July 2019. In November 2020 the EPA sent Entergy and other PRPs a demand letter seeking reimbursement for response costs totaling $4 million expended at the site. Liability and PRP
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allocation of response costs are yet to be determined. In December 2020, Entergy responded to the demand letter, without admitting liability or waiving any rights, indicating that it would engage in good faith negotiations with the EPA with respect to the demand. An initial meeting between the EPA and the PRPs took place in June 2021. Negotiations between the PRPs and the EPA are ongoing.
Litigation
Entergy uses legal and appropriate means to contest litigation threatened or filed against it, but certain states in which Entergy operates have proven to be unusually litigious environments. Judges and juries in Louisiana, Mississippi, and Texas have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. The litigation environment in these states poses a significant business risk to Entergy.
Asbestos Litigation(Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas)
See Note 8 to the financial statements for a discussion of this litigation.
Employment and Labor-related Proceedings (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
See Note 8 to the financial statements for a discussion of these proceedings.
Human Capital
Employees
Employees are an integral part of Entergy’s commitment to serving customers. As of December 31, 2022, Entergy subsidiaries employed 11,707 people.
| | | | | |
| Utility: | |
| Entergy Arkansas | 1,227 | |
| Entergy Louisiana | 1,597 | |
| Entergy Mississippi | 716 | |
| Entergy New Orleans | 296 | |
| Entergy Texas | 648 | |
| System Energy | — | |
| Entergy Operations | 3,317 | |
| Entergy Services | 3,870 | |
| Entergy Nuclear Operations | 13 | |
| Other subsidiaries | 23 | |
| Total Entergy | 11,707 | |
Approximately 3,084 employees are represented by the International Brotherhood of Electrical Workers, the United Government Security Officers of America, and the International Union, Security, Police, and Fire Professionals of America.
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Below is the breakdown of Entergy’s employees by gender and race/ethnicity:
| | | | | | | | | | | |
| Gender (%) | 2022 | | 2021 |
| Female | 22.2 | | 21.4 |
| Male | 77.8 | | 78.6 |
| | | | | | | | | | | |
| Race/Ethnicity (%) | 2022 | | 2021 |
| White | 74.8 | | 76.4 |
| Black/African American | 17.3 | | 16.4 |
| Hispanic/Latino | 3.0 | | 2.7 |
| Asian | 2.3 | | 2.0 |
| Other | 2.6 | | 2.5 |
Entergy’s Approach to Human Resources
Entergy’s people and culture enable its success; that is why acquiring, retaining, and developing talent are important components of Entergy’s human resources strategy. Entergy focuses on an approach that includes, among other things, governance and oversight; safety; organizational health, including diversity, inclusion, and belonging; and talent management.
Governance and Oversight
Ensuring that workplace processes support the desired culture and strategy begins with the Board of Directors and the Office of the Chief Executive. The Talent and Compensation Committee (formerly Personnel Committee) establishes priorities and each quarter reviews strategies and results on a range of topics covering the workforce, the workplace, and the marketplace. It oversees Entergy’s incentive plan design and administers its executive compensation plans to incentivize the behaviors and outcomes that support achievement of Entergy’s corporate objectives. Annually, it reviews executive performance, development, succession plans, and talent pipeline to align a high performing executive team with Entergy’s priorities. The Talent and Compensation Committee also oversees Entergy’s performance through regular briefings on a wide variety of human resources topics including Entergy’s safety culture and performance; organizational health; and diversity, inclusion, and belonging initiatives and performance.
The Talent and Compensation Committee’s Charter was revised in 2021 to acknowledge the committee’s responsibility for overseeing and monitoring the effectiveness of Entergy’s human capital strategies, including its workforce diversity, inclusion, and organizational health and safety strategies, programs, and initiatives. In recognition of the importance that organizational health and diversity, inclusion, and belonging play in enabling Entergy to achieve its business strategies, the committee receives periodic reports on Entergy’s organization health and diversity, inclusion, and belonging programs, strategies, and performance, including briefings at each of its regular meetings. The committee also receives updates on Entergy’s performance to date on key workforce, workplace, and marketplace measures, including progress in the representation of women and underrepresented minorities, both in the total workforce and in director level and above placements, progress in key diversity, inclusion, and belonging initiatives and diverse supplier spend.
Other committees of the Board oversee other key aspects of Entergy’s culture. For example, the Audit Committee reviews reports on enterprise risks, ethics, and compliance training and performance, as well as regular reports on calls made to Entergy’s ethics line and related investigations. To maximize the sharing of information and facilitate the participation of all Board members in these discussions, the Board schedules its regular committee meetings in a manner such that all directors can attend.
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The Office of the Chief Executive, which includes the Senior Vice President and Chief Human Resources Officer, ensures annual business plans are designed to support Entergy’s talent objectives, reviews workforce-related metrics, and regularly discusses the development, succession planning, and performance of their direct reports and other company officers.
Safety
Entergy’s safety objective is: Everyone Safe. All Day. Every Day. The continuation of the COVID-19 pandemic and another historic hurricane season presented significant challenges. Entergy employees achieved a total recordable incident rate of 0.51 in 2022, compared to 0.46 in 2021, and 0.40 in 2020. The results of 2021 unfortunately included an employee fatality. Entergy has enhanced dramatically leadership efforts and field presence to further its objective of zero fatalities, which it achieved in 2022. Also in 2022, there was a significant decrease in the number of serious injuries. The recordable incident rate equals the number of recordable incidents per 100 full-time equivalents. Recordable incidents include fatalities, lost-time accidents, restricted-duty accidents, and medical attentions and is not inclusive of potential work-related COVID-19 cases.
Organizational Health, including Diversity, Inclusion and Belonging (DIB)
Entergy believes that organizational health fosters an engaged and productive culture that positions Entergy to deliver sustainable value to its stakeholders. Entergy measures its progress through an organizational health survey coordinated by an external third party. Since initially administering the survey in 2014, Entergy improved from an initial score of 49 (fourth quartile) to a score in 2020 of 72 (second quartile), in 2021 of 63 (third quartile), and in 2022 of 61 (third quartile). Although the score declined slightly in 2022 as compared to 2021, it improved from the 2014 baseline. Management uses the results of the annual survey to design and implement strategies to positively influence organizational health. Initial employee participation of 66 percent in 2014 rose to and remains at approximately 90 percent in 2019-2022.
Entergy believes that creating a culture of diversity, inclusion, and belonging drives foundational engagement. Entergy is committed to developing and retaining a workforce that reflects the rich diversity of the communities it serves. In 2019, Entergy embarked on a three-year phased approach to enhance inclusion for individuals and teams. In 2022, Entergy continued to focus its actions to engage a diverse workforce, infusing DIB into hiring policies, practices and procedures, aligning Employee Resource Group goals to DIB goals, growing its DIB Champion network, integrating DIB into Entergy’s leadership development programs, and facilitating training from the executive leadership ranks down to the frontline. Through these efforts, Entergy aspires to create greater understanding and accountability regarding the behaviors and outcomes that are indicative of a premier utility.
Talent Management
Entergy’s focus on talent management is organized in three areas: developing and attracting a diverse pool of talent, equipping its leaders to develop the organization, and building premier utility capability through employee performance management and succession programs. Entergy believes that developing a diverse pool of local talent equipped with the skills needed, today and in the future, and reflecting the communities Entergy serves will give it a long-term competitive advantage. The focus of Entergy’s leadership development programs is to equip managers with the skills needed to effectively develop their teams and improve the leader-employee relationship. Entergy’s talent development infrastructure, which includes a combination of business function-specific and enterprise-wide learning and development programs, is designed to ensure Entergy has qualified staff with the skills, experiences, and behaviors needed to perform today and prepare for the future. Entergy strives to achieve its strategic priorities by aligning and enhancing team and individual performance with business objectives, effectively deploying talent through succession planning, and managing workforce transitions.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Availability of SEC filings and other information on Entergy’s website
Entergy electronically files reports with the SEC, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxies, and amendments to such reports. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding registrants that file electronically with the SEC at http://www.sec.gov. Copies of the reports that Entergy files with the SEC can be obtained at the SEC’s website.
Entergy uses its website, http://www.entergy.com, as a routine channel for distribution of important information, including news releases, analyst presentations and financial information. Filings made with the SEC are posted and available without charge on Entergy’s website as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. These filings include annual and quarterly reports on Forms 10-K and 10-Q and current reports on Form 8-K (including related filings in XBRL format); proxy statements; and any amendments to those reports or statements. All such postings and filings are available on Entergy’s Investor Relations website free of charge. Entergy is providing the address to its internet site solely for the information of investors and does not intend the address to be an active link. The contents of the website are not incorporated into this report.
Part I Item 1A and 1B
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Item 1A. RISK FACTORS
See “RISK FACTORS SUMMARY” in Part I Item 1 for a summary of Entergy’s and the Registrant Subsidiaries’ risk factors.
Investors should review carefully the following risk factors and the other information in this Form 10-K. The risks that Entergy faces are not limited to those in this section. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely affect Entergy’s financial condition, results of operations, and liquidity. See “FORWARD-LOOKING INFORMATION.”
Utility Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The terms and conditions of service, including electric and gas rates, of the Utility operating companies and System Energy are determined through regulatory approval proceedings that can be lengthy and subject to appeal, that could resultpotentially resulting in delays in effecting rate changes, lengthy litigation, the risk of disallowance of recovery of certain costs, and uncertainty as to ultimate results.
The Utility operating companies are regulated on a cost-of-service and rate of return basis and are subject to statutes and regulatory commission rules and procedures. The rates that the Utility operating companies and System Energy charge reflect their capital expenditures, operations and maintenance costs, allowed rates of return, financing costs, and related costs of service. These rates significantly influence the financial condition, results of operations, and liquidity of Entergy and each of the Utility operating companies and System Energy. These rates are determined in regulatory proceedings and are subject to periodic regulatory review and adjustment, including adjustment upon the initiative of a regulator or, in some cases, affected stakeholders. Regulators in a future rate proceeding may alter the timing or amount of certain costs for which recovery is allowed or modify the current authorized rate of return. Rate refunds may also be required, subject to applicable law.
In addition, regulators have initiated and may initiate additional proceedings to investigate the prudence of costs in the Utility operating companies’ and System Energy’s base rates and examine, among other things, the reasonableness or prudence of the companies’ operation and maintenance practices, level of expenditures (including storm costs and costs associated with capital projects), allowed rates of return and rate base, proposed resource acquisitions, and previously incurred capital expenditures that the operating companies seek to place in rates. The regulators may disallow costs subject to their jurisdiction found not to have been prudently incurred or found not to have been incurred in compliance with applicable tariffs, creating some risk to the ultimate recovery of those costs. Regulatory proceedings relating to rates and other matters typically involve multiple parties seeking to limit or reduce rates. Traditional base rate proceedings, as opposed to formula rate plans, generally have long timelines, are primarily based on historical costs, and may or may not be limited in scope or duration by statute. The length of these base rate proceedings can cause the Utility operating companies and System Energy to experience regulatory lag in recovering costs through rates, such that the Utility operating companies may not fully recover all costs during the rate effective period and the Utility operating companies may, therefore, earn less than their allowed returns. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with rate case proceedings. For a discussion of such appeals and related litigation for both the Utility operating companies and System Energy, see Note 2 to the financial statements.
The Utility operating companies have large customer and stakeholder bases and, as a result, could be the subject of public criticism or adverse publicity focused on issues including the operation and maintenance of their assets and infrastructure, their preparedness for major storms or other extreme weather events and/or the time it takes to restore service after such events, or the quality of their service or the reasonableness of the cost of their
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service. Criticism or adverse publicity of this nature could render legislatures and other governing bodies, public service commissions and other regulatory authorities, and government officials less likely to view the applicable operating company in a favorable light and could potentially negatively affect legislative or regulatory processes or outcomes, as well as lead to increased regulatory oversight or more stringent legislative or regulatory requirements.
The base rates of Entergy Texas are established largely in traditional base rate case proceedings. Between base rate proceedings, Entergy Texas has available rate riders to recoverrequirements or other legislation or regulatory actions that adversely affect the revenue requirements associated with certain incremental costs. For example, Entergy Texas has recovered distribution-related capital investments through the distribution cost recovery factor rider mechanism, transmission-related capital investments and certain non-fuel MISO charges through the transmission cost recovery factor rider mechanism, and MISO fuel and energy-related costs
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energycompanies.
through the fixed fuel factor mechanism. Entergy Texas is also required to make a filing every three years, at a minimum, reconciling its fuel and purchased power costs and fuel factor revenues. In the course of this reconciliation, the PUCT determines whether eligible fuel and fuel-related expenses and revenues are necessary and reasonable, and makes a prudence finding for each of the fuel-related contracts for the reconciliation period.
Between base rate cases, Entergy Arkansas and Entergy Mississippi are able to adjust base rates annually through formula rate plans that utilize a forward test year (Entergy Arkansas) or forward-looking features (Entergy Mississippi). In response to Entergy Arkansas’s application for a general change in rates in 2015, the APSC approved the formula rate plan tariff proposed by Entergy Arkansas including its use of a projected year test period and an initial five-year term. The initial five-year term expires in 2021 unless Entergy Arkansas requests, and the APSC approves, the extension of the formula rate plan tariff for an additional five years through 2026. If Entergy Arkansas’s formula rate plan were terminated or not extended beyond the initial term, Entergy Arkansas could file an application for a general change in rates that may include a request for continued regulation under a formula rate review mechanism. If Entergy Mississippi’s formula rate plan is terminated, it would revert to the more traditional rate case environment or seek approval of a new formula rate plan. Entergy Arkansas and Entergy Mississippi recover fuel and purchased energy and certain non-fuel costs through other APSC-approved and MPSC-approved tariffs, respectively.
Entergy Louisiana historically sets electric base rates annually through a formula rate plan using an historic test year. The form of the formula rate plan, on a combined basis, was approved in connection with the business combination of Entergy Louisiana and Entergy Gulf States Louisiana and largely followed the formula rate plans that were approved by the LPSC in connection with the full electric base rate cases filed by those companies in February 2013. The formula rate plan was most recently extended through the test year 2019; certain modifications were made in that extension, including a decrease to the allowed return on equity and the addition of a transmission cost recovery mechanism. The formula rate plan continues to include exceptions from the rate cap and sharing requirements for certain large capital investment projects, including acquisition or construction of generating facilities and purchase power agreements approved by the LPSC and as noted, for certain transmission investment, among other items. MISO fuel and energy-related costs are recoverable in Entergy Louisiana’s fuel adjustment clause. In the event that the electric formula rate plan is not renewed or extended, Entergy Louisiana would revert to the more traditional rate case environment.
Entergy New Orleans previously operated under a formula rate plan that ended with the 2011 test year. Based on a settlement agreement approved by the City Council, with limited exceptions, the base rates of Entergy New Orleans were frozen until rates were implemented in connection with the base rate case filed by Entergy New Orleans in 2018. In November 2019 the City Council issued a resolution resolving the rate case, with rates to become effective retroactive to August 2019. The resolution allows Entergy New Orleans to implement a three-year formula rate plan, beginning with the 2019 test year as adjusted for forward-looking known and measurable changes. Entergy New Orleans has appealed the resolution. See Note 2 to the financial statements for further discussion.
The rates of System Energy are established by the FERC, and the costs allowed to be charged pursuant to these rates are, in turn, passed through to the participating Utility operating companies through the Unit Power Sales Agreement, which allows monthly adjustments to reflect the current operating costs of, and investment in, Grand Gulf. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC, including a challenge with respect to System Energy’s authorized return on equity and capital structure and a request in a separate proceeding for FERC to initiate a broader investigation of rates under the Unit Power Sales Agreement. See Note 2 to the financial statements for further discussion of the proceedings. The Utility operating companies have agreed to implement certain protocols for providing retail regulators with information regarding rates billed under the Unit Power Sales Agreement.
The Utility operating companies and System Energy, and the energy industry as a whole, have experienced a period of rising costs and investments and an upward trend in spending, especially with respect to infrastructure investments, which is likely to continue in the foreseeable future and could result in more frequent rate cases and
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requests for, and the continuation of, cost recovery mechanisms.mechanisms, all of which could face resistance from customers and other stakeholders especially in a rising cost environment, whether due to inflation or high fuel prices or otherwise, and/or in periods of economic decline or hardship. Significant increases in costs could increase financing needs and otherwise adversely affect Entergy, the Utility operating companies, and System Energy’s business, financial position, results of operation, or cash flows. For information regarding rate case proceedings and formula rate plans applicable to the Utility operating companies, see Note 2 to the financial statements.
Changes to state or federal legislation or regulation affecting electric generation, electric and natural gas transmission, distribution, and related activities could adversely affect Entergy and the Utility operating companies’ financial position, results of operations, or cash flows and their utility businesses.
If legislative and regulatory structures evolve in a manner that erodes the Utility operating companies’ exclusive rights to serve their regulated customers, they could lose customers and sales and their results of operations, financial position, or cash flows could be materially affected. Additionally, technological advances in energy efficiency and distributed energy resources are reducing the costs of these technologies and, together with ongoing state and federal subsidies, the increasing penetration of these technologies could result in reduced sales by the Utility operating companies. Such loss of sales, due to the methodology used to determine cost of service rates or otherwise, could put upward pressure on rates, possibly resulting in adverse regulatory actions to mitigate such effects on rates. Further, the failure of regulatory structures to evolve to accommodate the changing needs and desires of customers with respect to the sourcing and use of electricity also could diminish sales by the operating companies. Entergy and the Utility operating companies cannot predict if or when they may be subject to changes in legislation or regulation, or the extent and timing of reductions of the cost of distributed energy resources, nor can they predict the impact of these changes on their results of operations, financial position, or cash flows.
The Utility operating companies recover fuel, purchased power, and associated costs through rate mechanisms that are subject to risks of delay or disallowance in regulatory proceedings.proceedings, and sudden or prolonged increases in fuel and purchased power costs could lead to increased customer arrearages or bad debt expenses.
The Utility operating companies recover their fuel, purchased power, and associated costs from their customers through rate mechanisms subject to periodic regulatory review and adjustment. Because regulatory review can result in the disallowance of incurred costs found not to have been prudently incurred or not reflected in rates as permitted by approved rate schedules and accounting rules, including the cost of replacement power purchased when generators experience outages or when planned outages are extended, with the possibility of refunds to ratepayers, there exists some risk to the ultimate recovery of those costs, particularly when there are substantial or sudden increases in such costs. Regulators also may also initiate proceedings to investigate the continued usage or the adequacy and operation of the fuel and purchased power recovery clauses of the Utility operating companies and, therefore, there can be no assurance that existing recovery mechanisms will remain unchanged or in effect at all.
The Utility operating companies’ cash flows can be negatively affected by the time delays between when gas, power, or other commodities are purchased and the ultimate recovery from customers of the costs in rates. On occasion, when the level of incurred costs for fuel and purchased power rises very dramatically, some
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of the Utility operating companies may agree to defer recovery of a portion of that period’s fuel and purchased power costs for recovery at a later date, which could increase the near-term working capital and borrowing requirements of those companies. The Utility operating companies also may experience, and in some instances have experienced, an increase in customer bill arrearages and bad debt expenses due to, among other reasons, increases in fuel and purchased power costs, especially in periods of economic decline or hardship. For a description of fuel and purchased power recovery mechanisms and information regarding the regulatory proceedings for fuel and purchased power costscost recovery, see Note 2 to the financial statements.
There remains uncertainty regarding the effect of the termination of the System Agreement on the Utility operating companies.
The Utility operating companies historically engaged in the coordinated planning, construction, and operation of generating resources and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that had been approved by the FERC. The System Agreement terminated in its entirety on August 31, 2016.
There remains uncertainty regarding the long-term effect of the termination of the System Agreement on the Utility operating companies because of the significant effect of the agreement on the generation and transmission functions of the Utility operating companies and the significant period of time (over 30 years) that it had been in existence. In the absence of the System Agreement, there remains uncertainty around the effectiveness of governance processes and the potential absence of federal authority to resolve certain issues among the Utility operating companies and their retail regulators.
In addition, although the System Agreement terminated in its entirety in August 2016, there are a number of outstanding System Agreement proceedings at the FERC that may require future adjustments, including challenges to
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Entergy Corporation, Utility operating companies, and System Energy
the level and timing of payments made by Entergy Arkansas under the System Agreement. The outcome and timing of these FERC proceedings and resulting recovery and impact on rates cannot be predicted at this time.
For further information regarding the regulatory proceedings relating to the System Agreement, see Note 2 to the financial statements.
The Utility operating companies are subject to economic risks associated with participation in the MISO markets and the allocation of transmission upgrade costs. The operation of the Utility operating companies’ transmission system pursuant to the MISO RTO tariff and their participation in the MISO RTO’s wholesale markets may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
On December 19, 2013, the Utility operating companies integrated into the MISO RTO. MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their owned and controlled generating facilities into the MISO resource adequacy construct (the annual Planning Resource Auction, discussed below), as well as the day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. The Utility operating companies are subject to economic risks associated with participation in the MISO markets.markets and resource adequacy construct. MISO tariff rules and system conditions, including transmission congestion, could affect the Utility operating companies’ ability to sell powercapacity, energy, and/or ancillary services in certain regions and/or the economic value of such sales, andor the cost of serving the Utility operating companies’ respective loads. MISO market rules may change or be interpreted in ways that cause additional cost and risk, including compliance risk.
The Utility operating companies participate in the MISO regional transmission planning process and are subject to risks associated with planning decisions that MISO makes in the exercise of control over the planning of the Utility operating companies’ transmission assets that are under MISO’s functional control. The Utility operating companies pay transmission rates that reflect the cost of transmission projects that the Utility operating companies do not own, which could increase cash or financing needs. MISO has made filings withFurther, FERC proposing changes in thepolicies and regulation addressing cost responsibility for transmission project criteria in MISO. These changes, if adopted, couldprojects, including transmission projects to interconnect new generation facilities, may potentially give rise to cash and financing-related risks as well as result in a larger volumeupward pressure on the retail rates of competitively bid and regionally cost allocated transmission projects.the Utility operating companies, which, in turn, may result in adverse actions by the Utility operating companies’ retail regulators. In addition to the cash and financing-related risks arising from the potential additional cost allocation to the Utility operating companies from thesetransmission projects of others or changes in FERC policies or regulation related to cost responsibility for transmission projects, there is a risk that the Utility operating companies’ business and financial position could be harmed as a result of lost investment opportunities and other effects that flow from an increased number of competitive projects being approved and constructed that are interconnected with their transmission systems.
Further, the terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets, the allocation of transmission upgrade costs, the MISO-wide allowed base rate of return on equity, and any required MISO-related charges and credits are subject to regulation by the FERC. The operation of the Utility operating companies’ transmission system pursuant to the MISO tariff and their participation in the MISO wholesale markets, and the resulting costs, may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
Moreover, the resource adequacy construct provided under the MISO tariff confers certain rights and imposes certain obligations upon load-serving entities, including the Utility operating companies, that are served
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from the transmission systems subject to MISO’s functional control, including the transmission facilities of the Utility operating companies. The MISO tariff provisions governing these rights and obligations are subject to change and have recently undergone significant changes, some of which are the subject of pending litigation and/or appeals. Due to their magnitude and the speed with which they have been implemented, these changes carry risk, including compliance risk, and may result in material additional costs being passed through to the Utility operating companies’ customers in retail rates, including but not limited to additional capacity costs incurred in the annual MISO Planning Resource Auction. Also, by virtue of the Utility operating companies’ participation in MISO and the design and terms of the MISO resource adequacy construct, other load-serving entities served by the Utility operating companies’ transmission assets, which are under MISO’s functional control, may be able to circumvent reasonable resource planning obligations and avoid, in whole or in part, the full cost of procuring the resources reasonably needed to reliably supply their respective loads. In particular, the design of the current MISO resource adequacy construct and the absence of a minimum capacity obligation in MISO create a risk of other load-serving entities engaging in “free ridership” through their strategy for participation in the MISO resource adequacy construct and energy and ancillary services markets – specifically, by using energy and ancillary services available from the Utility operating companies’ owned and controlled generating units without paying a reasonable share of the cost of the capacity required to provide such energy and ancillary services. As a result, there are a variety of risks to the Utility operating companies and their customers, including the risk of bearing additional costs for resources needed to ensure reliable service, the risk of reduced reliability and the enhanced risk of outages and lost sales which, because of the methodology for establishing cost of service rates, presents the risk of upward pressure on the Utility operating companies’ rates.
In addition, orders from each of the Utility operating companies’ respective retail regulators generally require that the Utility operating companies make periodic filings, or generally allow the retail regulator to direct the making of such filings, setting forth the results of analysis of the costs and benefits realized from MISO membership as well as the projected costs and benefits of continued membership in MISO and/or requesting approval of their continued membership in MISO. These filings have been submitted periodically by each of the Utility operating companies as required by their respective retail regulators, and the outcome of the resulting proceedings may affect the Utility operating companies’ continued membership in MISO.
The continued impacts of the COVID-19 pandemic and responsive measures taken on Entergy’s and its Utility operating companies’ business, results of operations, and financial condition are highly uncertain and cannot be predicted.
The global 2019 novel coronavirus pandemic continues to be an evolving situation and could lead to further disruption of the general economy, impacts on the customers of Entergy’s Utility operating companies, and disruption of the operations of Entergy’s subsidiaries, whether due to, among other things, the emergence or spread of new variants of COVID-19, precautionary or reactionary measures, market reactions or impacts, or supply chain constraints.
Entergy and its Utility operating companies experienced an increase in arrearages and bad debt expense due to non-payment by customers. The arrearages due to COVID-19 have begun to decline, although management cannot predict the timing of the completion of collections of such arrearages. While the Utility operating companies are working with regulators to ensure ultimate recovery for those and other COVID-19 related costs, the amount, method, and timing of such recovery is subject to approval by the retail regulators.
Entergy and its Registrant Subsidiaries also could experience, and in some cases have experienced, among other challenges that originated during or have been exacerbated by the COVID-19 pandemic: supply chain, vendor, and contractor disruptions, including shortages or delays in the availability of key components, parts, and supplies such as electronic components and solar panels; delays in completion of capital or other construction projects, maintenance, and other operations activities, including prolonged or delayed refueling and maintenance outages; delays in regulatory proceedings; workforce availability challenges, including from COVID-19 infections, health, or safety issues; increased storm recovery costs; increased cybersecurity risks as a result of many employees
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telecommuting; volatility in the credit or capital markets (and any related increased cost of capital or any inability to access the capital markets or draw on available credit facilities); or other adverse impacts on their ability to execute on business strategies and initiatives.
Although the economy has been recovering, another economic decline could adversely impact Entergy’s and the Utility operating companies’ liquidity and cash flows, including through declining sales, reduced revenues, delays in receipts of customer payments, or increased bad debt expense. The Utility operating companies also may experience regulatory outcomes that require them to postpone planned investment and otherwise reduce costs due to the impact of the COVID-19 pandemic on their customers, especially in an environment of higher inflation. In addition, if the COVID-19 pandemic or related impacts create additional disruptions or turmoil in the credit or financial markets, or adversely impact Entergy’s credit metrics or ratings, such developments could adversely affect its ability to access capital on favorable terms and continue to meet its liquidity needs or cause a decrease in the value of its defined benefit pension trust funds, as well as its nuclear decommissioning trust funds, all of which are highly uncertain and cannot be predicted.
Entergy cannot predict the extent or duration of the ongoing COVID-19 pandemic, the impact of new or existing variants of COVID-19, the effectiveness of mitigation efforts, further governmental responsive measures, or the extent of the effects or ultimate impacts on the global, national or local economy, the capital markets, or its customers, suppliers, operations, financial condition, results of operations, or cash flows.
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather, the impact on customer bills of permitted storm cost recovery, or the inability to securitize future storm restoration costs could have material effects on Entergy and thoseits Utility operating companies affected by severe weather.companies.
Entergy’s and its Utility operating companies’ results of operations, liquidity, and financial condition can be materially affected by the destructive effects of severe weather. Severe weather can also result in significant outages for the customers of the Utility operating companies and, therefore, reduced revenues for the Utility operating companies during the period of the outages. A delay or failure in recovering amounts for storm restoration costs incurred, inability to securitize future storm restoration costs, or loss of revenues lost as a result of severe weather could have a material effect on Entergy and those Utility operating companies affected by severe weather.weather, including lower credit ratings and, thus, higher costs for future debt issuances. The inability to recover losses either excluded by insurance or in excess of the insurance limits that can be secured economically also could have a material effect on Entergy and its Utility operating companies. In addition, the recovery of major storm restoration costs from customers could effectively limit our ability to make planned capital or other investments due to the impact of such storm cost recovery on customer bills, especially in a rising cost environment.
In August 2021, Hurricane Ida caused extensive damage to the Entergy distribution and, to a lesser extent, transmission systems across Louisiana, resulting in storm costs of $2.5 billion. Entergy Louisiana began recovering a portion of these costs through securitization financings in 2022. In January 2023 the LPSC issued orders finding prudent the costs incurred by Entergy Louisiana in responding to Hurricane Ida and allowing Entergy Louisiana to securitize the remaining $1.491 billion in such costs. Because such orders are not yet final and non-appealable (due to the forty-five day appeal period) and, further, because the bond rating and marketing process has yet to occur, there is an element of risk, and Entergy Louisiana is unable to predict with certainty the ultimate success of its recovery initiatives or the timing of such recovery.
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
Weather, economic conditions, technological developments, and other factors may have a material impact on electricity and gas sales and otherwise materially affect the Utility operating companies’ results of operations and system reliability.
Temperatures above normal levels in the summer tend to increase electric cooling demand and revenues, and temperatures below normal levels in the winter tend to increase electric and gas heating demand and revenues. As a corollary, mild temperatures in either season tend to decrease energy usage and resulting revenues. Higher consumption levels coupled with seasonal pricing differentials typically cause the Utility operating companies to report higher revenues in the third quarter of the fiscal year than in the other quarters. Changing weather patterns and extreme weather conditions, including hurricanes or tropical storms, flooding events, or ice storms, the frequency or intensity of which may be exacerbated by climate change, may stress the Utility operating companies’ generation facilities and transmission and distribution systems, resulting in increased maintenance and capital costs (and potential increased financing needs), limits on their ability to meet peak customer demand, increased regulatory oversight, criticism or adverse publicity, and reduced customer satisfaction. These extreme conditions could have a material effect on the Utility operating companies’ financial condition, results of operations, and liquidity.
Entergy’s electricity sales volumes are affected by a number of factors including weather and economic conditions, trends in energy efficiency, new technologies, and self-generation alternatives, including the willingness and ability of large industrial customers to develop co-generation facilities that greatly reduce their grid demand. In addition, changes to regulatory policies, such as those that allow customers to directly access the market to procure wholesale energy or those that incentivize development and utilization of new, developing, or alternative sources of generation, could, and in some instances, have reduced sales, and other non-traditional procurements, such as virtual purchase power agreements, could, and in some instances have limited growth opportunities or reduced sales at the Utility operating companies. Some of these factors are inherently cyclical or temporary in nature, such as the weather or economic conditions, and rarely have a long-lasting effect on Entergy’s operating results. Others, such as the organic turnover of appliances and lighting and their replacement with more efficient ones and adoption of newer technologies, including smart thermostats, new building codes, distributed energy resources, energy storage, demand side management, and rooftop solar, are having a more permanent effect by reducing sales growth rates from historical norms. As a result of these emerging efficiencies and technologies, the Utility operating companies may lose customers or experience lower average use per customer in the residential and commercial classes, and continuing advances have the potential to further limit sales or sales growth in the future.
The Utility operating companies also may face competition from other companies offering products and services to Entergy’s customers. Electricity sales to industrial customers, in particular, benefit from steady economic growth and favorable commodity markets; however, industrial sales are sensitive to changes in conditions in the markets in which its customers operate. Negative changes in any of these or other factors, particularly sustained economic downturns or sluggishness, have the potential to result in slower sales growth or sales declines and increased bad debt expense, which could materially affect Entergy’s and the Utility operating companies’ results of operations, financial condition, and liquidity. The Utility operating companies also may not realize anticipated or expected growth in industrial sales from electrification opportunities to help such customers achieve their environmental and sustainability goals. This could occur because of changes in customers’ goals or business priorities, competition from other companies, or decisions by such customers to seek to achieve such goals through methods not offered by Entergy.
Part I Item 1A and 1B
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Nuclear Operating, Shutdown, and Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)
Certain of the Utility operating companies and System Energy and Entergy Wholesale Commodities mustare expected to consistently operate their nuclear power plants at high capacity factors in order to be successful, and lower capacity factors could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Nuclear capacity factors significantly affect the results of operations of certain Utility operating companies and System Energy, and Entergy Wholesale Commodities.Energy. Nuclear plant operations involve substantial fixed operating costs. Consequently, there is pressure on plant owners to be successful, a plant owner must consistently operate its nuclear power plants at highhigher capacity factors, though such operations always must be consistent with safety, reliability, and nuclear regulatory requirements. For the Utility operating companies that own nuclear plants, lower nuclear plant capacity factors can increase production costs by requiring the affected companies to generate additional energy, sometimes at higher costs, from their owned or contractually controlled facilities or purchase additional energy in the spot or forward markets in order to satisfy their supply needs. For the Entergy Wholesale Commodities nuclear plants, lower capacity factors directly affect revenues and cash flow from operations. Entergy Wholesale Commodities’ forward sales are comprised of various hedge products, many of which have some degree of operational-contingent price risk. Certain unit-contingent contracts guarantee specified minimum capacity factors. In the event plants with these contracts were operating below the guaranteed capacity factors, Entergy would be subject to price risk for the undelivered power. Further, Entergy Wholesale Commodities’ nuclear forward sales contracts can also be on a firm LD basis, which subjects Entergy to increasing price risk as capacity factors decrease. Many of these firm hedge products have damages risk.
Certain of the Utility operating companies and System Energy and the Entergy Wholesale Commodities nuclear plant owners periodically shut down their nuclear power plants to replenish fuel. Plant maintenance and upgrades are often scheduled during such refueling outages. If refueling outages last longer than anticipated or if unplanned outages arise, Entergy’s and their results of operations, financial condition, and liquidity could be materially affected.
Outages at nuclear power plants to replenish fuel require the plant to be “turned off.” Refueling outages generally are planned to occur once every 18 to 24 months. Plant maintenance and upgrades are often scheduled during such planned outages, which typically extendsmay extend the planned outage duration.duration beyond that required for only refueling activities. When refueling outages last longer than anticipated or a plant experiences unplanned outages, capacity factors decrease, and maintenance costs may increase. Lower than forecasted capacity factors may cause Entergy Wholesale Commodities to experience reduced revenues and may also create damages risk with certain hedge products as previously discussed.
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Entergy Corporation, Utility operating companies, and System Energy
Certain of the Utility operating companies and System Energy and Entergy Wholesale Commodities face risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication). These risks could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Based upon currently planned fuel cycles, Entergy’s nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable prices through 2020 and beyond. The nuclear fuel supply portfolio for the Entergy Wholesale Commodities segment has been adjusted to reflect reduced overall requirements related to the planned permanent shutdown and salemost of the Palisades, Indian Point 2 and Indian Point 3 plants over the next three years and fuel procurement is limited to the final refueling of the Palisades plant in 2020.2027. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners. While there are a number of possible alternate suppliers that may be accessed to mitigate any supplier performance failure, the pricing of any such alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S. Market prices for nuclear fuel have been extremely volatile from time to time in the past and may be subject to increased volatility due to the imposition of tariffs, domestic purchase requirements or limitations on importation of uranium or uranium products from foreign countries, geopolitical conditions, or shifting trade arrangements between countries. Although Entergy’s nuclear fuel contract portfolio provides a degree of hedging against market risks for several years, costs for nuclear fuel in the future cannot be predicted with certainty due to normal inherent market uncertainties, and price changes could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy, and Entergy Wholesale Commodities.Energy.
Entergy’s ability to assure nuclear fuel supply also depends upon the performance and reliability of conversion, enrichment, and fabrication services providers. These service providers are fewer in number than uranium suppliers. For conversion and enrichment services, Entergy diversifies its supply by supplier and country and may take special measures to ensure a reliable supply of enriched uranium for fabrication into nuclear fuel. For fabrication services, each plant is dependent upon the performance of the fabricator of that plant’s nuclear fuel;
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
therefore, Entergy relies upon additional monitoring, inspection, and oversight of the fabrication process to assure reliability and quality of its nuclear fuel. Certain of the suppliers and service providers are located in or dependent upon foreign countries, such as Russia, in whichand international sanctions or tariffs impacting trade with such countries could further restrict the ability of such suppliers or service providers to continue to supply fuel or provide such services at acceptable prices or at all. The inability of such suppliers or service providers to perform such obligations could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.
Certain of the Utility operating companies and System Energy and Entergy Wholesale Commodities.
Entergy Arkansas, Entergy Louisiana, System Energy, and the Entergy Wholesale Commodities business face the risk that the NRC will change or modify its regulations, suspend or revoke their licenses, or increase oversight of their nuclear plants, which could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Under the Atomic Energy Act and Energy Reorganization Act, the NRC regulates the operation of nuclear power plants. The NRC may modify, suspend, or revoke licenses, shut down a nuclear facility and impose civil penalties for failure to comply with the Atomic Energy Act, related regulations, or the terms of the licenses for nuclear facilities. Interested parties may also intervene which could result in prolonged proceedings. A change in the Atomic Energy Act, other applicable statutes, or the applicable regulations or licenses, or the NRC’s interpretation thereof, may require a substantial increase in capital expenditures or may result in increased operating or decommissioning costs and could materially affect the results of operations, liquidity, or financial condition of Entergy, (through Entergy Wholesale Commodities), itscertain of the Utility operating companies, or System Energy. A change in the classification of a plant owned by one of these companies under the NRC’s Reactor Oversight Process, which is the NRC’s program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response, also could cause the owner of the plant to incur material additional costs as a result of the increased oversight activity and potential response costs associated with the change in classification.For additional information concerning the current classification of the plants owned by Entergy Arkansas, Entergy Louisiana, System Energy, and
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy,
the Entergy Wholesale Commodities business, see “Regulation of Entergy’s Business - Regulation of the Nuclear Power Industry - NRC Reactor Oversight Process” in Part I, Item 1 and Note 8 to the financial statements.1.
Events at nuclear plants owned by one of these companies, as well as those owned by others, may lead to a change in laws or regulations or the terms of the applicable licenses, or the NRC’s interpretation thereof, or may cause the NRC to increase oversight activity or initiate actions to modify, suspend, or revoke licenses, shut down a nuclear facility, or impose civil penalties. As a result, if an incident were to occur at any nuclear generating unit, whether an Entergy nuclear generating unit or not, it could materially affect the financial condition, results of operations, and liquidity of Entergy, certain of the Utility operating companies, or System Energy, or Entergy Wholesale Commodities. Energy.
Certain of the Utility operating companies and System Energy and Entergy Wholesale Commodities are exposed to risks and costs related to operating and maintaining their nuclear power plants, and their failure to maintain operational efficiency at their nuclear power plants could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
The nuclear generating units owned by certain of the Utility operating companies and System Energyand the Entergy Wholesale Commodities business began commercial operations in the 1970s-1980s. Older equipment may require more capital expenditures to keep each of these nuclear power plants operating safely and efficiently. This equipment is also likely to require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages, or any unanticipated capital expenditures, could result in increased costs, some of which costs may not be fully recoverable by thethese Utility operating companies and System Energy in regulatory proceedings should there be a determination of imprudence. Operations at any of the nuclear generating units owned and operated by Entergy’s subsidiaries could degrade to the point where the affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. A decision may be made to close a unit rather than incur the expense of restarting it or returning the unit to full capacity. For thethese Utility operating companies and System Energy, this could result in certain costs being stranded
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
and potentially not fully recoverable in regulatory proceedings. For Entergy Wholesale Commodities, this could result in lost revenue and increased fuel and purchased power expense to meet supply commitments and penalties for failure to perform under their contracts with customers. In addition, the operation and maintenance of Entergy’s nuclear facilities require the commitment of substantial human resources that can result in increased costs.
The nuclear industry continues to address susceptibility to the effects of stress corrosion cracking and other corrosion mechanisms on certain materials within plant systems. The issue is applicable at all nuclear units to varying degrees and is managed in accordance with industry standard practices and guidelines that include in-service examinations, replacements, and mitigation strategies. Developments in the industry or identification of issues at the nuclear units could require unanticipated remediation efforts that cannot be quantified in advance.
Moreover, Entergy is becoming more dependent on fewer suppliers for key parts of Entergy’s nuclear power plants that may need to be replaced or refurbished, and in some cases, parts are no longer available and have to be reverse-engineered for replacement. In addition, certain major parts have long lead-times to manufacture if an unplanned replacement is needed. This dependence on a reduced number of suppliers and long lead-times on certain major parts for unplanned replacements could result in delays in obtaining qualified replacement parts and, therefore, greater expense for Entergy.Entergy, certain of the Utility operating companies, and System Energy.
The costs associated with the storage of the spent nuclear fuel of certain of the Utility operating companies and System Energy, and the owners of the Entergy Wholesale Commodities nuclear power plants, as well as the costs of and their ability to fully decommission their nuclear power plants, could be significantly affected by the timing of the opening of a spent nuclear fuel disposal facility, as well as interim storage and transportation requirements.
Certain of the Utility operating companies and System Energy and the owners of the Entergy Wholesale Commodities nuclear plants incur costs for the on-site storage of spent nuclear fuel. The approval of a license for a national repository for the disposal of spent nuclear fuel, such as the one proposed for Yucca Mountain, Nevada, or
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
any interim storage facility, and the timing of such facility opening, will significantly affect the costs associated with on-site storage of spent nuclear fuel. For example, while the DOE is required by law to proceed with the licensing of Yucca Mountain and, after the license is granted by the NRC, to construct the repository and commence the receipt of spent fuel, the NRC licensing of the Yucca Mountain repository is effectively at a standstill. These actions are prolonging the time before spent fuel is removed from Entergy’s plant sites. Because the DOE has not accomplished its objectives, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts, and Entergy has sued the DOE for such breach. Furthermore, Entergy is uncertain as to when the DOE will commence acceptance of spent fuel from its facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at the companies’ nuclear sites and maintenance costs on existing storage facilities, including aging management of fuel storage casks, may increase. The costs of on-site storage are also affected by regulatory requirements for such storage. In addition, the availability of a repository or other off-site storage facility for spent nuclear fuel may affect the ability to fully decommission the nuclear units and the costs relating to decommissioning. For further information regarding spent fuel storage, see the “Critical Accounting Estimates – Nuclear Decommissioning Costs – Spent Fuel Disposal” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy and Note 8 to the financial statements.
Certain of the Utility operating companies and System Energy and the Entergy Wholesale Commodities nuclear plant owners may be required to pay substantial retrospective premiums imposed under the Price-Anderson Act and/or by Nuclear Electric Insurance Limited (NEIL) in the event of a nuclear incident, and losses not covered by insurance could have a material effect on Entergy’s and their results of operations, financial condition, or liquidity.
Accidents and other unforeseen problems at nuclear power plants have occurred both in the United States and elsewhere. As required by the Price-Anderson Act, the Utility operating companies and System Energy carry the maximum available amount of primary nuclear off-site liability insurance with American Nuclear Insurers, which is $450 million for each operating site. Claims for any nuclear incident exceeding that amount are covered under Secondary Financial Protection. The Price-Anderson Act limits each reactor owner’s public liability (off-site) for a single nuclear incident to the payment of retrospective premiums into a secondary insurance pool, which is referred to as Secondary Financial Protection, up to approximately $137.6 million per reactor. With 9896 reactors currently participating, this translates to a total public liability cap of approximately $14$13 billion per incident. The limit is subject to change to account for the effects of inflation, a change in the primary limit of insurance coverage, and changes in the number of licensed reactors. As required by the Price-Anderson Act, the Utility operating companies, System Energy, and Entergy Wholesale Commodities carry the maximum available amount of primary nuclear off-site liability insurance with American Nuclear Insurers, which is $450 million for each operating site. Claims for any nuclear incident exceeding that amount are covered under Secondary Financial Protection. As a result, in the event of a nuclear incident that causes damages (off-site) in excess of the primary insurance coverage, each owner of a nuclear plant reactor, including Entergy’s Utility operating companies and System Energy, and the Entergy Wholesale Commodities plant owners, regardless of fault or proximity to the incident, will be required to
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
pay a retrospective premium, equal to its proportionate share of the loss in excess of the primary insurance level, 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)$688 million). The retrospective premium payment is currently limited to approximately $21 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $137.6 million cap.
NEIL is a utility industry mutual insurance company, owned by its members, including the Utility operating companies and System Energy,Energy. NEIL provides onsite property and the owners of the Entergy Wholesale Commodities plants.decontamination coverage. All member plants could be subject to an annual assessment (retrospective premium of up to 10 times current annual premium for all policies) should the NEIL surplus (reserve) be significantly depleted due to insured losses. As of December 31, 2019,January 1, 2023, the maximum annual assessment amounts total $112approximately $70 million for the Utility plants. Retrospective premium insurance available through NEIL’s reinsurance treaty can cover the potential assessments and the Entergy Wholesale Commodities plants currently maintain the retrospective premium insurance to cover those potential assessments.
As mentioned above, as an owner of nuclear power plants, Entergy participates in industry self-insurance programs and could be liable to fund claims should a plant owned by a different company experience a major event. Any resulting liability from a nuclear accident may exceed the applicable primary insurance coverage and require contribution of additional funds through the industry-wide program that could significantly affect the results of operations, financial condition,
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
or liquidity of Entergy, certain of the Utility operating companies, or System Energy, or the Entergy Wholesale Commodities subsidiaries.Energy.
The decommissioning trust fund assets for the nuclear power plants owned by certain of the Utility operating companies and System Energy and the Entergy Wholesale Commodities nuclear plant owners may not be adequate to meet decommissioning obligations if market performance and other changes decrease the value of assets in the decommissioning trusts, if one or more of Entergy’s nuclear power plants is retired earlier than the anticipated shutdown date, if the plants cost more to decommission than estimated, or if current regulatory requirements change, which then could require significant additional funding.
Owners of nuclear generating plants have an obligation to decommission those plants. Certain of the Utility operating companies and System Energy and owners of the Entergy Wholesale Commodities nuclear power plants maintain decommissioning trust funds for this purpose. Certain of the Utility operating companies and System Energy collect funds from their customers, which are deposited into the trusts covering the units operated for or on behalf of those companies. Those rate collections, as adjusted from time to time by rate regulators, are generally based upon operating license lives and trust fund balances as well as estimated trust fund earnings and decommissioning costs. Assets in these trust funds are subject to market fluctuations, will yield uncertain returns that may fall below projected return rates, and may result in losses resulting from the recognition of impairments of the value of certain securities held in these trust funds.
Under NRC regulations, nuclear plant owners are permitted to project the NRC-required decommissioning amount, based on an NRC formula or a site-specific estimate, and the amount that will be available in each nuclear power plant’s decommissioning trusts combined with any other decommissioning financial assurances in place. The projections are made based on the operating license expiration date and the mid-point of the subsequent decommissioning process, or the anticipated actual completion of decommissioning if a site-specific estimate is used. If the projected amount of each individual plant’s decommissioning trusts exceeds the NRC-required decommissioning amount, then its NRC license termination decommissioning obligations are considered to be funded in accordance with NRC regulations. If the projected costs do not sufficiently reflect the actual costs required to decommission these nuclear power plants, or funding is otherwise inadequate, or if the formula, formula inputs, or site-specific estimate is changed to require increased funding, additional resources or commitments would be required. Furthermore, depending upon the level of funding available in the trust funds, the NRC may not permit the trust funds to be used to pay for related costs such as the management of spent nuclear fuel that are not included in the NRC’s formula. The NRC may also require a plan for the provision of separate funding for spent fuel management costs. In addition to NRC requirements, there are other decommissioning-related obligations for certain
Part I Item 1A and 1B
Entergy Wholesale Commodities nuclear power plants, which management believes it will be able to satisfy.Corporation, Utility operating companies, and System Energy
Further, federal or state regulatory changes, including mandated increases in decommissioning funding or changes in the methods or standards for decommissioning operations, may also increase the funding requirements of, or accelerate the timing for funding of, the obligations related to the decommissioning of the nuclear generating plant owned by certain of the Utility operating companies or System Energy or Entergy Wholesale Commodities nuclear power plants or may restrict the decommissioning-related costs that can be paid from the decommissioning trusts. Such changes also could result in the need for additional contributions to decommissioning trusts, or the posting of parent guarantees, letters of credit, or other surety mechanisms. As a result, under any of these circumstances, Entergy’sthe results of operations, liquidity, and financial condition of Entergy, certain of the Utility operating companies, or System Energy could be materially affected.
An early plant shutdown (either generally or relative to current expectations), poor investment results, or higher than anticipated decommissioning costs (including as a result of changing regulatory requirements) could cause trust fund assets to be insufficient to meet the decommissioning obligations, with the result that certain of the Utility operating companies or System Energy or the Entergy Wholesale Commodities nuclear plant owners may be required to provide significant additional funds or credit support to satisfy regulatory requirements for decommissioning, which, with respect to thethese Utility operating companies or System Energy, may not be recoverable from customers in a timely fashion or at all.
For further information regarding nuclear decommissioning costs, management’s decision to exit the merchant
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
power business, and the impairment charges that resulted from such decision, and the planned sale of Palisades (which will include the transfer of the decommissioning trust), see the “Critical Accounting Estimates - Nuclear Decommissioning Costs” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy, the “Entergy Wholesale Commodities Exit from the Merchant Power Business” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries, and Notes 9, 14, and 1416 to the financial statements.
New or existing safety concerns regarding operating nuclear power plants and nuclear fuel could lead to restrictions upon the operation and decommissioning of Entergy’s nuclear power plants.
New and existing concerns are being expressed in public forums about the safety of nuclear generating units and nuclear fuel. These concerns have led to, and may continue to lead to, various proposals to Federalfederal regulators and governing bodies in some localities where Entergy’s subsidiaries own nuclear generating units for legislative and regulatory changes that might lead to the shutdown of nuclear units, additional requirements or restrictions related to spent nuclear fuel on-site storage and eventual disposal, or other adverse effects on owning, operating, and decommissioning nuclear generating units. Entergy vigorously responds to these concerns and proposals. If any of the existing proposals, or any proposals that may arise in the future with respect to legislative and regulatory changes, become effective, they could have a material effect on Entergy’s results of operations and financial condition.
(Entergy Corporation)
Entergy Wholesale Commodities nuclear power plants are exposed to price risk.
Entergy and its subsidiaries do not have a regulator-authorized rate of return on their capital investments in non-utility businesses. As a result, the sale of capacity and energy from the Entergy Wholesale Commodities nuclear power plants, unless otherwise contracted, is subject to the fluctuation of market power prices. In order to reduce future price risk to desired levels, Entergy Wholesale Commodities utilizes contracts that are unit-contingent and Firm LD and various products such as forward sales, options, and collars. As of December 31, 2019, Entergy Wholesale Commodities’ nuclear power generation plants had sold forward 97% in 2020, 92% in 2021, and 66% in 2022 of its generation portfolio’s planned energy output, reflecting the planned shutdown and sale of the remaining Entergy Wholesale Commodities nuclear power plants by mid-2022.
Market conditions such as product cost, market liquidity, and other portfolio considerations influence the product and contractual mix. The obligations under unit-contingent agreements depend on a generating asset that is operating; if the generation asset is not operating, the seller generally is not liable for damages. For some unit-contingent obligations, however, there is also a guarantee of availability that provides for the payment to the power purchaser of contract damages, if incurred, in the event the unit owner 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. Firm LD sales transactions may be exposed to substantial operational price risk, a portion of which may be capped through the use of risk management products, to the extent that the plants do not run as expected and market prices exceed contract prices.
Market prices may fluctuate substantially, sometimes over relatively short periods of time, and at other times experience sustained increases or decreases. Demand for electricity and its fuel stock can fluctuate dramatically, creating periods of substantial under- or over-supply. During periods of over-supply, prices might be depressed. Also, from time to time there may be political pressure, or pressure from regulatory authorities with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations, credit requirements, bidding rules and other mechanisms to address volatility and other issues in these markets.
The effects of sustained low natural gas prices and power market structure challenges have resulted in lower market prices for electricity in the power regions where the Entergy Wholesale Commodities nuclear power plants are located. In addition, currently the market design under which the plants operate does not adequately compensate merchant nuclear plants for their environmental and fuel diversity benefits in the region. These conditions were primary
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
factors leading to Entergy’s decision to shut down (or sell) Entergy Wholesale Commodities’ nuclear power plants before the end of their operating licenses (or requested operating licenses for Indian Point 2 and Indian Point 3).
The price that different counterparties offer for various products including forward sales is influenced both by market conditions as well as the contract terms such as damage provisions, credit support requirements, and the number of available counterparties interested in contracting for the desired forward period. Depending on differences between market factors at the time of contracting versus current conditions, Entergy Wholesale Commodities’ contract portfolio may have average contract prices above or below current market prices, including at the expiration of the contracts, which may significantly affect Entergy Wholesale Commodities’ results of operations, financial condition, or liquidity. New hedges are generally layered into on a rolling forward basis, which tends to drive hedge over-performance to market in a falling price environment, and hedge underperformance to market in a rising price environment; however, hedge timing, product choice, and hedging costs will also affect these results. See the “Market and Credit Risk Sensitive Instruments” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries. Since Entergy Wholesale Commodities has announced the closure (or sale) of its nuclear plants, Entergy Wholesale Commodities may enter into fewer forward sales contracts for output from such plants.
The Entergy Wholesale Commodities business is subject to substantial governmental regulation and may be adversely affected by legislative, regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
The Entergy Wholesale Commodities business is subject to extensive regulation under federal, state, and local laws. Compliance with the requirements under these various regulatory regimes may cause the Entergy Wholesale Commodities business to incur significant additional costs, and failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of liens, fines and/or civil or criminal liability.
Public utilities under the Federal Power Act are required to obtain FERC acceptance of their rate schedules for wholesale sales of electricity. Each of the owners of the Entergy Wholesale Commodities nuclear power plants that generates electricity, as well as Entergy Nuclear Power Marketing, LLC, is a “public utility” under the Federal Power Act by virtue of making wholesale sales of electric energy and/or owning wholesale electric transmission facilities. The FERC has granted these generating and power marketing companies the authority to sell electricity at market-based rates. The FERC’s orders that grant the Entergy Wholesale Commodities’ generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that the Entergy Wholesale Commodities business can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, the Entergy Wholesale Commodities’ market-based sales are subject to certain market behavior rules, and if any of its generating and power marketing companies were deemed to have violated one of those rules, they would be subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority and potential penalties of up to $1 million per day per violation. If the Entergy Wholesale Commodities’ generating or power marketing companies were to lose their market-based rate authority, such companies would be required to obtain the FERC’s acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have an adverse effect on the rates the Entergy Wholesale Commodities business charges for power from its facilities.
The Entergy Wholesale Commodities business is also affected by legislative and regulatory changes, as well as changes to market design, market rules, tariffs, cost allocations, and bidding rules imposed by the existing Independent System Operators. The Independent System Operators that oversee most of the wholesale power markets may impose, and in the future may continue to impose, mitigation, including price limitations, offer caps and other mechanisms, to address some of the volatility and the potential exercise of market power in these markets. These types of price limitations and other regulatory mechanisms may have an adverse effect on the profitability of the Entergy Wholesale Commodities business’ generation facilities that sell energy and capacity into the wholesale power markets. For further information regarding federal, state and local laws and regulation applicable to the Entergy Wholesale Commodities business, see the “Regulation of Entergy’s Business” section in Part I, Item 1.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The regulatory environment applicable to the electric power industry is subject to changes as a result of restructuring initiatives at both the state and federal levels. Entergy cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on the Entergy Wholesale Commodities business. In addition, in some of these markets, interested parties have proposed material market design changes, including the elimination of a single clearing price mechanism, have raised claims that the competitive marketplace is not working because energy prices in wholesale markets exceed the marginal cost of operating nuclear power plants, and have made proposals to re-regulate the markets, impose a generation tax, or require divestitures by generating companies to reduce their market share. Other proposals to re-regulate may be made and legislative or other attention to the electric power market restructuring process may delay or reverse the deregulation process, which could require material changes to business planning models. If competitive restructuring of the electric power markets is reversed, modified, discontinued, or delayed, the Entergy Wholesale Commodities business’ results of operations, financial condition, and liquidity could be materially affected.
The power plants owned by the Entergy Wholesale Commodities business are subject to impairment charges in certain circumstances, which could have a material effect on Entergy’s results of operations, financial condition or liquidity.
Entergy 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 the operations of such 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. In particular, the remaining assets of the Entergy Wholesale Commodities business are subject to further impairment in connection with the closure and sale of its nuclear power plants. Moreover, prior to the closure and sale of these plants, the failure of the Entergy Wholesale Commodities business to achieve forecasted operating results and cash flows, an unfavorable change in forecasted operating results or cash flows, a reduction in the expected remaining useful life of a unit, or a decline in observable industry market multiples could all result in potential additional impairment charges for the affected assets.
If Entergy concludes that any of its nuclear power plants is unlikely to operate through its planned shutdown date, which conclusion would be based on a variety of factors, such a conclusion could result in a further impairment of part or all of the carrying value of the plant. Any impairment charge taken by Entergy with respect to its long-lived assets, including the remaining power plants owned by the Entergy Wholesale Commodities business, would likely be material in the quarter that the charge is taken and could otherwise have a material effect on Entergy’s results of operations, financial condition, or liquidity. For further information regarding evaluating long-lived assets for impairment, see the “Critical Accounting Estimates - Impairment of Long-lived Assets and Trust Fund Investments” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries and for further discussion of the impairment charges, see Note 14 to the financial statements.
GeneralProduction Cost Allocation Rider
Entergy Arkansas has in place an APSC-approved production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of System Agreement proceedings.
Entergy Louisiana
Formula Rate Plan
Entergy Louisiana historically sets electric base rates annually through a formula rate plan using a historic test year. The form of the formula rate plan, on a combined basis, was approved in connection with the business combination of Entergy Louisiana and Entergy Gulf States Louisiana and largely followed the formula rate plans that were approved by the LPSC in connection with the full electric base rate cases filed by those companies in February 2013. The formula rate plan was most recently extended through the test year 2022; certain modifications were made in that extension, including a decrease to the allowed return on equity, narrowing of the earnings “dead band” around the mid-point allowed return on equity, elimination of sharing above and below the earnings “dead band,” and the addition of a distribution cost recovery mechanism. The formula rate plan continues to include exceptions from the rate cap and sharing requirements for certain large capital investment projects, including acquisition or construction of generating facilities and purchase power agreements approved by the LPSC, certain transmission investments, and most recently, certain distribution investments, among other items. In the event that the electric formula rate plan is not renewed or extended or otherwise replaced, Entergy Louisiana would revert to the more traditional rate case environment with a rate case filing occurring as soon as mid-2023.
Fuel Recovery
Entergy Louisiana’s rate schedules include a fuel adjustment clause designed to recover the cost of fuel and purchased power costs. The fuel adjustment clause contains a surcharge or credit for deferred fuel expense and related carrying charges arising from the monthly reconciliation of actual fuel costs incurred with fuel cost revenues billed to customers, including carrying charges. See Note 2 to the financial statements for a discussion of proceedings related to audits of Entergy Louisiana’s fuel adjustment clause filings.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
To help stabilize electricity costs, Entergy Louisiana received approval from the LPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Louisiana historically hedged approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity was reviewed on an annual basis. In January 2018, Entergy Louisiana filed an application with the LPSC to suspend these seasonal hedging programs and implement financial hedges with terms up to five years for a portion of its natural gas exposure, which was approved in November 2018.
Entergy Louisiana’s gas rates include a purchased gas adjustment clause based on estimated gas costs 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.
Retail Rates - Gas
In accordance with the settlement of Entergy Gulf States Louisiana’s gas rate stabilization plan for the test year ended September 30, 2012, in August 2014, Entergy Gulf States Louisiana submitted for consideration a proposal for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment and relocation projects mandated by local governments. After review by the LPSC staff and inclusion of certain customer safeguards required by the LPSC staff, in December 2014, Entergy Gulf States Louisiana and the LPSC staff submitted a joint settlement for implementation of an accelerated gas pipe replacement program providing for the replacement of approximately 100 miles of pipe over the next ten years, as well as relocation of certain existing pipe resulting from local government-related infrastructure projects, and for a rider to recover the investment associated with these projects. The rider allows for recovery of approximately $65 million over ten years. The rider recovery will be adjusted on a quarterly basis to include actual investment incurred for the prior quarter and is subject to the following conditions, among others: a ten-year term; application of any earnings in excess of the upper end of the earnings band as an offset to the revenue requirement of the infrastructure rider; adherence to a specified spending plan, within plus or minus 20% annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding 10%; and an annual true-up. The joint settlement was approved by the LPSC in January 2015. Implementation of the infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2015. In April 2022 Entergy Louisiana submitted for consideration a proposal to extend the infrastructure rider to address replacement of an additional 187 miles of pipe. In December 2022 Entergy Louisiana and the LPSC staff submitted an uncontested settlement that extends the rider for an additional ten years beginning after the end of the current term of the rider in 2025. The extension is subject to the same customer safeguards and conditions as the original term of the rider. The extension allows for recovery of approximately $95 million over ten years. In February 2023, the uncontested settlement was approved by the LPSC.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Louisiana’s filings to recover storm-related costs.
Other
In March 2016 the LPSC opened two dockets to examine, on a generic basis, issues that it identified in connection with its review of Cleco Corporation’s acquisition by third party investors. The first docket is captioned “In re: Investigation of double leveraging issues for all LPSC-jurisdictional utilities,” and the second is captioned “In re: Investigation of tax structure issues for all LPSC-jurisdictional utilities.” In April 2016 the LPSC clarified that the concerns giving rise to the two dockets arose as a result of its review of the structure of the Cleco-Macquarie transaction and that the specific intent of the directives is to seek more information regarding intra-corporate debt financing of a utility’s capital structure as well as the use of investment tax credits to mitigate the tax
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Entergy Corporation, Utility operating companies, and System Energy
obligation at the parent level of a consolidated entity. No schedule has been set for either docket, and limited discovery has occurred.
In December 2019 an LPSC commissioner issued an unopposed directive to staff to research customer-centered options for all customer classes, as well as other regulatory environments, and recommend a plan for how to ensure customers are the focus. There was no opposition to the directive from other commissioners but several remarked that the intent of the directive was not initiated to pursue retail open access. In furtherance of the directive, the LPSC issued a notice of the opening of a docket to conduct a rulemaking to research and evaluate customer-centered options for all electric customer classes as well as other regulatory environments in January 2020. To date, the LPSC staff has requested multiple rounds of comments from stakeholders and conducted one technical conference. Topics on which comments have been filed include full and limited retail access, demand response, sleeved power purchase agreements, and energy efficiency. Neither the LPSC or the LPSC staff have made recommendations or adopted any rules.
Entergy Mississippi
Formula Rate Plan
Since the conclusion in 2015 of Entergy Mississippi’s most recent base rate case, Entergy Mississippi has set electric base rates annually through a formula rate plan. Between base rate cases, Entergy Mississippi is able to adjust base rates annually, subject to certain caps, through formula rate plans that utilize forward-looking features. In addition, Entergy Mississippi is subject to an annual “look-back” evaluation. Entergy Mississippi is allowed a maximum rate increase of 4% of each test year’s retail revenue. Any increase above 4% requires a base rate case. If Entergy Mississippi’s formula rate plan were terminated without replacement, it would revert to the more traditional rate case environment or seek approval of a new formula rate plan.
In August 2012 the MPSC opened inquiries to review whether the then current formulaic methodology used to calculate the return on common equity in both Entergy Mississippi’s formula rate plan and Mississippi Power Company’s annual formula rate plan was still appropriate or could be improved to better serve the public interest. The intent of this inquiry and review was for informational purposes only; the evaluation of any recommendations for changes to the existing methodology would take place in a general rate case or in the existing formula rate plan proceeding. In March 2013 the Mississippi Public Utilities Staff filed its consultant’s report which noted the return on common equity estimation methods used by Entergy Mississippi and Mississippi Power Company are commonly used throughout the electric utility industry. The report suggested ways in which the methods used by Entergy Mississippi and Mississippi Power Company might be improved, but did not recommend specific changes in the return on common equity formulas or calculations at that time. In June 2014 the MPSC expanded the scope of the August 2012 inquiry to study the merits of adopting a uniform formula rate plan that could be applied, where possible in whole or in part, to both Entergy Mississippi and Mississippi Power Company in order to achieve greater consistency in the plans. The MPSC directed the Mississippi Public Utilities Staff to investigate and review Entergy Mississippi’s formula rate plan rider schedule and Mississippi Power Company’s Performance Evaluation Plan by considering the merits and deficiencies and possibilities for improvement of each and then to propose a uniform formula rate plan that, where possible, could be applicable to both companies. No procedural schedule has been set. In October 2014 the Mississippi Public Utilities Staff conducted a public technical conference to discuss performance benchmarking and its potential application to the electric utilities’ formula rate plans. The docket remains open.
In December 2019 the MPSC approved Entergy Mississippi’s proposed revisions to its formula rate plan to 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 as well as to allow similar cost recovery treatment for other capacity acquisitions that are approved by the MPSC. 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
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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.
Fuel Recovery
Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased power costs. The energy cost rate for each calendar year is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy costs as of the 12-month period ended September 30. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC. The energy cost recovery riders allow interim rate adjustments depending on the level of over- or under-recovery of fuel and purchased energy costs.
To help stabilize electricity costs, Entergy Mississippi received approval from the MPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Mississippi hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of recovery of Entergy Mississippi’s storm-related costs.
Entergy New Orleans
Formula Rate Plan
As part of its determination of rates in the base rate case filed by Entergy New Orleans in 2018, in November 2019, the City Council issued a resolution resolving the rate case, with rates to become effective retroactive to August 2019. The resolution allows Entergy New Orleans to implement a three-year formula rate plan, beginning with the 2019 test year as adjusted for forward-looking known and measurable changes, with the filing for the first test year to be made in 2020. As part of a settlement of Entergy New Orleans’ appeal of the Council’s decision in its 2018 base rate case, Entergy New Orleans agreed to postpone the filing of its first test year formula rate plan to 2021 and, in return, to be provided an additional test year for the three-year cycle. Accordingly, Entergy New Orleans will submit its final formula rate plan filing of the three-year cycle in April 2023 unless the formula rate plan is extended or renewed. See Note 2 to the financial statements for further discussion.
Fuel Recovery
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.
To help stabilize gas costs, Entergy New Orleans seeks approval annually from the City Council to continue implementation of its natural gas hedging program consistent with the City Council’s stated policy objectives. The program uses financial instruments to hedge exposure to volatility in the wholesale price of natural gas purchased to
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serve Entergy New Orleans gas customers. Entergy New Orleans hedges up to 25% of actual gas sales made during the winter months.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy New Orleans’s filings to recover storm-related costs.
Entergy Texas
Base Rates
The base rates of Entergy Texas are established largely in traditional base rate case proceedings. Between base rate proceedings, Entergy Texas has available rate riders to recover the revenue requirements associated with certain incremental costs. Entergy Texas is required to file full base rate case proceedings every four years and within eighteen months of utilizing its generation cost recovery rider for investments above $200 million.
Fuel Recovery
Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, that are not included 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 every three years, at a minimum. In the course of this reconciliation, the PUCT determines whether eligible fuel and fuel-related expenses and revenues are necessary and reasonable and makes a prudence finding for each of the fuel-related contracts entered into during the reconciliation period. The PUCT fuel cost proceedings are discussed in Note 2 to the financial statements.
At the PUCT’s April 2013 open meeting, the PUCT Commissioners discussed their view that a purchased power capacity rider was good public policy. The PUCT issued an order in May 2013 adopting the rule allowing for a purchased power capacity rider, subject to an offsetting adjustment for load growth. The rule, as adopted, also includes a process for obtaining pre-approval by the PUCT of purchased power agreements. No Texas utility, including Entergy Texas, has exercised the option to recover capacity costs under the new rider mechanism, but Entergy Texas will continue to evaluate the benefits of utilizing the rider to recover future capacity costs.
Other Cost Recovery
As discussed above, Entergy Texas has available rate riders to recover the revenue requirements associated with certain incremental costs. These riders include a transmission cost recovery factor rider mechanism for the recovery of transmission-related capital investments, a distribution cost recovery factor rider mechanism for the recovery of distribution-related capital investment, and a generation cost recovery rider mechanism for the recovery of generation-related capital investments.
In June 2009 a law was enacted in Texas containing provisions that allow Entergy Texas to take advantage of a cost recovery mechanism that permits annual filings for the recovery of reasonable and necessary expenditures for transmission infrastructure improvement and changes in wholesale transmission charges. This mechanism was previously available to other non-ERCOT Texas utility companies, but not to Entergy Texas.
In September 2011 the PUCT adopted a proposed rule implementing a distribution cost recovery factor to recover capital and capital-related costs related to distribution infrastructure. The distribution cost recovery factor permits utilities once per year to implement an increase or decrease in rates above or below amounts reflected in base rates to reflect distribution-related depreciation expense, federal income tax and other taxes, and return on
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investment. The distribution cost recovery factor rider may be changed a maximum of four times between base rate cases.
In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery rider rule, implementing legislation passed in the 2019 Texas legislative session intended to allow electric utilities to recover generation investments between base rate proceedings. The PUCT approved the final rule in July 2020.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Texas’s filings to recover storm-related costs.
Electric Industry Restructuring
In June 2009 a law was enacted in Texas that required Entergy Texas to cease all activities relating to Entergy Texas’s transition to competition. The law allows Entergy Texas to remain a part of the SERC Reliability Corporation (SERC) Region, although it does not prevent Entergy Texas from joining another power region. The law provides that proceedings to certify a power region that Entergy Texas belongs to as a qualified power region can be initiated by the PUCT, or on motion by another party, when the conditions supporting such a proceeding exist. Under the law, the PUCT may not approve a transition to competition plan for Entergy Texas until the expiration of four years from the PUCT’s certification of a qualified power region for Entergy Texas.
The law further amended already existing law that had required Entergy Texas to propose for PUCT approval a tariff to allow eligible customers the ability to contract for competitive generation. The amending language in the law provides, among other things, that: 1) the tariff shall not be implemented in a manner that harms the sustainability or competitiveness of manufacturers who choose not to participate in the tariff; 2) Entergy Texas shall “purchase competitive generation service, selected by the customer, and provide the generation at retail to the customer;” and 3) Entergy Texas shall provide and price transmission service and ancillary services under that tariff at a rate that is unbundled from its cost of service. The law directs that the PUCT may not issue an order on the tariff that is contrary to an applicable decision, rule, or policy statement of a federal regulatory agency having jurisdiction. The PUCT determined that unrecovered costs that may be recovered through the rider consist only of those costs necessary to implement and administer the competitive generation program and do not include lost revenues or embedded generation costs. The amount of customer load that may be included in the competitive generation service program is limited to 115 MW.
System Energy
Cost of Service
The rates of System Energy are established by the FERC, and the costs allowed to be charged pursuant to these rates are, in turn, passed through to the participating Utility operating companies through the Unit Power Sales Agreement, which has monthly billings that reflect the current operating costs of, and investment in, Grand Gulf. Retail regulators and other parties may seek to initiate proceedings at FERC to investigate the prudence of costs included in the rates charged under the Unit Power Sales Agreement and examine, among other things, the reasonableness or prudence of the operation and maintenance practices, level of expenditures, allowed rates of return and rate base, and previously incurred capital expenditures. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC, including a challenge with respect to System Energy’s uncertain tax positions, sale leaseback arrangement, authorized return on equity and capital structure, and a separate proceeding for a broader investigation of rates under the Unit Power Sales Agreement. In addition, certain of the Utility operating companies’ retail regulators have filed a complaint at FERC challenging the 2012 extended power uprate of Grand Gulf and the operation and management of the plant, particularly during the time period 2016 - 2020. Beginning in 2021, System Energy implemented billing protocols to provide retail regulators with
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information regarding rates billed under the Unit Power Sales Agreement. Entergy cannot predict the outcome of any of these proceedings, and an adverse outcome in any of them could have a material adverse effect on Entergy’s or System Energy’s results of operations, financial condition, or liquidity. See Note 2 to the financial statements for further discussion of the proceedings.
Franchises
Entergy Arkansas holds exclusive franchises to provide electric service in approximately 308 incorporated cities and towns in Arkansas. These franchises generally are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas, franchises are considered to be contracts and, therefore, are governed pursuant to the terms of the franchise agreement and applicable statutes.
Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 175 incorporated municipalities and in the unincorporated areas of approximately 59 parishes of Louisiana. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and in East Baton Rouge Parish. Municipal franchise agreement terms range from 25 to 60 years while parish franchise terms range from 25 to 99 years.
Entergy Mississippi has received from the MPSC certificates of public convenience and necessity to provide electric service to areas within 45 counties, including a number of municipalities, in western Mississippi. Under Mississippi statutory law, such certificates are exclusive. Entergy Mississippi may continue to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence.
Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city ordinances. These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans’s electric and gas utility properties.
Entergy Texas holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 27 counties in eastern Texas and holds non-exclusive franchises to provide electric service in approximately 70 incorporated municipalities. Entergy Texas typically obtains 25-year franchise agreements as existing agreements expire. Entergy Texas’s electric franchises expire over the period 2023-2058.
The business of System Energy is limited to wholesale power sales. It has no distribution franchises.
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Property and Other Generation Resources
Owned Generating Stations
The total capability of the generating stations owned and leased by the Utility operating companies and System Energy as of December 31, 2022 is indicated below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Owned and Leased Capability MW(a) |
| Company | | Total | | CT / CCGT (b) | | Legacy Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
| Entergy Arkansas | | 5,276 | | | 1,567 | | | 522 | | | 1,822 | | | 1,192 | | | 73 | | | 100 | |
| Entergy Louisiana | | 10,829 | | | 5,595 | | | 2,766 | | | 2,129 | | | 339 | | | — | | | — | |
| Entergy Mississippi | | 2,857 | | | 1,738 | | | 707 | | | — | | | 310 | | | — | | | 102 | |
| Entergy New Orleans | | 663 | | | 636 | | | — | | | — | | | — | | | — | | | 27 | |
| Entergy Texas | | 3,190 | | | 980 | | | 1,960 | | | — | | | 250 | | | — | | | — | |
| System Energy | | 1,260 | | | — | | | — | | | 1,260 | | | — | | | — | | | — | |
| Total | | 24,075 | | | 10,516 | | | 5,955 | | | 5,211 | | | 2,091 | | | 73 | | | 229 | |
(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.
(b)Represents Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.
Summer peak load for the Utility has averaged 21,602 MW over the previous decade.
The Utility operating companies’ load and capacity projections are reviewed periodically to assess the need and timing for additional generating capacity and interconnections. These reviews consider existing and projected demand, the availability and price of power, the location of new load, the economy, Entergy’s clean energy and other public policy goals, environmental regulations, and the age and condition of Entergy’s existing infrastructure.
The Utility operating companies’ long-term resource strategy (Portfolio Transformation Strategy) calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Over the past decade, the Portfolio Transformation Strategy has resulted in the addition of about 8,975 MW of new long-term resources and the deactivation of about 4,881 MW of legacy generation. As MISO market participants, the Utility operating companies also participate in MISO’s Day Ahead and Real Time Energy and Ancillary Services markets to economically dispatch generation and purchase energy to serve customers reliably and at the lowest reasonable cost.
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Other Generation Resources
RFP Procurements
The Utility operating companies from time to time issue requests for proposals (RFP) to procure supply-side resources from sources other than the spot market to meet the unique regional needs of the Utility operating companies. The RFPs issued by the Utility operating companies have sought resources needed to meet near-term MISO reliability requirements as well as long-term requirements through a broad range of wholesale power products, including long-term contractual products and asset acquisitions. The RFP process has resulted in selections or acquisitions, including, among other things:
•Entergy Louisiana’s construction of the 980 MW, combined-cycle, gas turbine J. Wayne Leonard Power Station (previously referred to as the St. Charles generating facility) at its existing Little Gypsy electric generating station. The facility began commercial operation in May 2019;
•Entergy Louisiana’s construction of the 994 MW, combined-cycle, gas turbine Lake Charles generating facility at its existing Nelson electric generating station site. The facility began commercial operation in March 2020;
•Entergy Texas’s construction of the 993 MW, combined-cycle, gas turbine Montgomery County Power Station at its existing Lewis Creek electric generating station. The facility began commercial operation in January 2021;
•Entergy New Orleans’s construction of the 20 MW solar photovoltaic facility, New Orleans Solar Station, located at the NASA Michoud Facility. The facility began commercial operation in December 2020;
•In December 2020, Entergy Texas selected the self-build alternative, Orange County Advanced Power Station, out of the 2020 Entergy Texas combined-cycle, gas turbine RFP. Regulatory approval was received in November 2022 and construction has commenced. The facility is expected to be in service by mid-2026;
•In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Searcy Solar facility, sited on approximately 800 acres in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the APSC in April 2020, and closed on the acquisition, through use of a tax equity partnership, in December 2021. The Searcy Solar facility was placed in service in January 2022;
•In November 2018, Entergy Mississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Sunflower Solar facility, sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and the Sunflower Solar facility began commercial operation in September 2022;
•In June 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Walnut Bend Solar facility, that will be sited on approximately 1,000 acres in Lee County, Arkansas. In July 2021 the APSC issued an order approving the acquisition of the Walnut Bend Solar facility. The counter-party notified Entergy Arkansas that it was terminating the project, though it was willing to consider an alternative for the site. Entergy Arkansas disputed the right of termination. Negotiations are ongoing, including with respect to cost and schedule and to updates arising as a result of the Inflation Reduction Act of 2022, and the updates would require additional APSC approval. At this time the project, if approved, is expected to achieve commercial operation in 2024;
•In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility, West Memphis Solar facility, that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In October 2021 the APSC issued an order approving the acquisition of the West Memphis Solar facility. The counter-party notified Entergy Arkansas that it was seeking changes to certain terms of the build-own-transfer agreement, including both cost and schedule. In January 2023, Entergy Arkansas made a supplemental filing with the APSC. Following APSC supplemental approval, full notice to proceed will be issued with closing expected to occur in 2024;
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•In November 2021, Entergy Louisiana signed an agreement for the purchase of an approximately 150 MW to-be-constructed solar photovoltaic energy facility, St. Jacques facility, that will be sited in St. James Parish near Vacherie, Louisiana. In September 2022 the LPSC voted to approve the order including the St. Jacques facility; however, project details could be adjusted pending a final St. James Parish ruling on land use permit requirements. Closing is expected to occur in 2025 dependent upon the final St. James Parish ruling; and
•In August 2022, Entergy Arkansas signed an agreement for the purchase of an approximately 250 MW to-be-constructed solar photovoltaic energy facility, Driver Solar facility, that will be sited near Osceola, Arkansas. Also in August 2022, Entergy Arkansas received necessary approvals for the Driver Solar facility, and Entergy Arkansas has issued the counter-party full notice to proceed to begin construction. The parties are evaluating the effects of certain matters related to the Inflation Reduction Act of 2022, including the viability of a tax equity partnership. Closing is expected to occur by the end of 2024.
The RFP process has also resulted in the selection, or confirmation of the economic merits of, long-term purchased power agreements (PPAs), including, among others:
•River Bend’s 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’s 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 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. In November 2019, LS Power sold and transferred the Carville Energy Center and facility to Argo Infrastructure Partners, which included the power purchase agreement;
•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 to-be-constructed solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and the PPA began in November 2020;
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•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 to-be-constructed solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the PPA began in October 2020;
•In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in the first half of 2023;
•In August 2018, Entergy Louisiana and South Alexander Development I, LLC executed a 5-year agreement for 5 MW from a solar photovoltaic electric generating facility located in Livingston Parish, Louisiana. The PPA began in December 2020 and received regulatory approval in January 2021;
•In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and achieved commercial operation in November 2022;
•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in Polk County, Texas. The PPA is expected to start when the facility reaches commercial operation in December 2023;
•In June 2021, Entergy Louisiana and Sunlight Road Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. In September 2022 the LPSC voted to approve the order including this project. The facility is expected to reach commercial operation in December 2024;
•In June 2021, Entergy Louisiana and Vacherie Solar Energy Center, LLC executed a 20-year PPA for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. In September 2022 the LPSC voted to approve the order including this project; however, project details could be adjusted pending a final St. James Parish ruling on land use permit requirements. The facility is expected to reach commercial operation in 2025;
•In November 2021, Entergy Louisiana signed a PPA for approximately 125 MW from a to-be-constructed solar photovoltaic energy facility located in Allen, Louisiana. In September 2022 the LPSC voted to approve the order including this project. The facility is expected to reach commercial operation in February 2024;
•In December 2022, Entergy Mississippi signed a PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Hinds County, Mississippi. Following execution of the agreement, Entergy Mississippi filed a petition with the MPSC requesting all necessary approvals. The facility is expected to reach commercial operation in June 2026;
•In October 2022, Entergy Mississippi signed a PPA for approximately 100 MW from a to-be-constructed solar photovoltaic energy facility located in Tallahatchie County, Mississippi. Following execution of the agreement, Entergy Mississippi filed a petition with the MPSC requesting all necessary approvals. The facility is expected to reach commercial operation as early as May 2026;
•In October 2022, Entergy Mississippi signed a PPA for approximately 170 MW from a to-be-constructed solar photovoltaic energy facility located in Washington County, Mississippi. Following execution of the agreement, Entergy Mississippi filed a petition with the MPSC requesting all necessary approvals. The facility is expected to reach commercial operation as early as May 2026;
•In October 2022, Entergy Arkansas signed a PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in St. Francis County, Arkansas. Following execution of the agreement, Entergy Arkansas filed a petition with the APSC requesting all necessary approvals. The facility is expected to reach commercial operation as early as May 2025;
•In October 2022, Entergy Arkansas signed a PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in Mississippi County, Arkansas. Following execution of the agreement, Entergy Arkansas filed a petition with the APSC requesting all necessary approvals. The facility is expected to reach commercial operation as early as May 2025; and
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•In January 2023, Entergy Texas signed a PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Walker County, Texas. The facility is expected to reach commercial operation as early as June 2026.
In March 2021, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic resources. Entergy Louisiana selected a combination of PPA and build-own-transfer resources by March 2022, some of which have been executed and are noted above and the remainder are in progress working through definitive agreements.
In July 2021, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar generation resources. Entergy Texas selected a combination of PPA and build-own-transfer resources in March 2022. One PPA was executed in January 2023 as noted above, and definitive agreements for the remaining resources are in progress.
In August 2021, Entergy Services, on behalf of Entergy Arkansas, issued an RFP for solar photovoltaic and wind resources. Entergy Arkansas selected a combination of PPA and build-own-transfer resources in February 2022, some of which have been executed and are noted above and the remainder are in progress working through definitive agreements.
In January 2022, Entergy Services, on behalf of Entergy Mississippi, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 500 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Mississippi customers.
In June 2022, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 1500 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Louisiana customers.
In April 2022, Entergy Services, on behalf of Entergy Arkansas, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 1000 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Arkansas customers.
In October 2022, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 2000 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Texas customers.
In November 2022, Entergy Services, on behalf of Entergy Mississippi, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 500 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Mississippi customers.
Other Procurements From Third Parties
The Utility operating companies have also made resource acquisitions outside of the RFP process, including Entergy Arkansas’s (Power Block 2), Entergy Louisiana’s (Power Blocks 3 and 4), and Entergy New Orleans’s (Power Block 1) March 2016 acquisitions of the 1,980 MW (summer rating), natural gas-fired, combined-cycle gas turbine Union Power Station power blocks, each rated at 495 MW (summer rating); and Entergy Mississippi’s October 2019 acquisition of the 810 MW, combined-cycle, natural gas-fired Choctaw Generating Station. The
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Utility operating companies have also entered into various limited- and long-term contracts in recent years as a result of bilateral negotiations.
The Washington Parish Energy Center is a 361 MW natural gas-fired peaking power plant approximately 60 miles north of New Orleans on a site Entergy Louisiana purchased from Calpine in 2019. In May 2018, Entergy Louisiana received LPSC approval of its certification application for this simple-cycle power plant to be developed pursuant to an agreement between Calpine and Entergy Louisiana. Calpine began construction on the plant in early 2019 and Entergy Louisiana purchased the plant upon completion in November 2020.
The Hardin County Peaking Facility, an existing 147 MW simple-cycle gas-fired peaking power plant in Kountze, Texas, previously owned by East Texas Electric Cooperative, was acquired by Entergy Texas in June 2021. The facility has been in operation since January 2010.
Power Through Programs
In December 2020, Entergy Texas filed an application with the PUCT to amend its certificate of convenience and necessity to own and operate up to 75 MW of natural gas-fired distributed generation to be installed at commercial and industrial customer premises. Under this proposal, Entergy Texas would own and operate a fleet of generators ranging from 100 kW to 10 MW that would supply a portion of Entergy Texas’s long-term resource needs and enhance the resiliency of Entergy Texas’s electric grid. This fleet of generators would also be available to customers during outages to supply backup electric service as part of a program known as “Power Through.” In its 2021 session, the Texas legislature modified the Texas Utilities Code to exempt generators under 10 megawatts from the requirement to obtain a certificate of convenience and necessity. In addition, the PUCT announced an intent to conduct a broad rulemaking related to distributed generation and recommended that utilities with pending applications addressing distributed generation withdraw them. Accordingly, Entergy Texas withdrew its application for a certificate of convenience and necessity and associated tariff from the PUCT without prejudice to refiling. Entergy Texas continues to deploy certain customer-sited distributed generators under an existing PUCT-approved tariff. In August 2022, Entergy Texas filed an application for PUCT approval of voluntary Rate Schedule Utility Owned Distributed Generation (UODG) through which it would charge host customers for back-up service from customer-sited Power Through generators. Based on the exemption enacted by the Texas legislature in 2021, Entergy Texas’s application was not required to, and did not, seek an amendment to its certificate of convenience and necessity in order to continue deploying Power Through generators. In October 2022 two intervenors filed requests for a hearing on Entergy Texas’s application. In October 2022 the PUCT staff filed a request that the proceeding be referred to the State Office of Administrative Hearings. In January 2023 the PUCT announced an intent to develop certain broadly applicable reliability metrics against which to measure distributed generation resources and directed Entergy Texas to withdraw its application. However, the PUCT did allow Entergy Texas to continue its pilot program for Power Through generators. Entergy Texas has withdrawn its application and is considering next steps.
In August 2021, Entergy Arkansas filed with the APSC an application for authority to deploy natural gas-fired distributed generation. The application was supported by a number of letters of interest from Entergy Arkansas customers. In December 2021 the APSC general staff requested briefing, which Entergy Arkansas opposed. In January 2022, Entergy Arkansas filed to support the establishment of a procedural schedule with a hearing in April 2022. Also in January 2022, the APSC granted the general staff’s request for briefing but on an expedited schedule; briefing concluded in February 2022. Based on testimony filed to date the APSC general staff, Arkansas Electric Energy Consumers, Sierra Club, and Audubon oppose Entergy Arkansas’s proposed “Power Through” offering, which has been demonstrated to be in high demand by interested customers, some of which directly have filed public comments encouraging the APSC to approve the application. A paper hearing was held in August and September 2022 with Entergy Arkansas responding to several written commissioner questions. The parties are awaiting a decision from the APSC.
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In July 2021, Entergy Louisiana filed with the LPSC an application for authority to deploy natural gas-fired distributed generation. The application was supported by a number of letters of interest from Entergy Louisiana customers. In October 2021, a procedural schedule was established with a hearing in April 2022. Staff and certain intervenors filed direct testimony in December 2021, and cross-answering testimony was filed in January 2022. Entergy Louisiana filed rebuttal testimony in February 2022. The parties reached an uncontested settlement which, among other things, recommended approval of 120 MW of natural gas fired distributed generation and an additional 30 MW of solar and battery distributed generation, for a total distributed generation program of 150 MW. Pursuant to the terms of the settlement agreement, Entergy Louisiana may seek to expand the distributed generation program following the earlier of two years after issuance of an order approving the settlement or the installation of 60 MW of distributed generation pursuant to this program. The settlement was approved by the LPSC in November 2022.
Interconnections
The Utility operating companies’ generating units are interconnected to a transmission system operating at various voltages up to 500 kV. These generating units consist of steam-turbine generators fueled by natural gas and coal, combustion-turbine generators, and reciprocating internal combustion engine generators that are fueled by natural gas, generators powered by pressurized and boiling water nuclear reactors and inverter-based resources interconnecting both solar photovoltaic systems and energy storage devices that operate in the MISO wholesale electric market. Additionally, some of the Utility operating companies also offer customer services and products that include resources interconnected to both the distribution and transmission systems that also participate in the wholesale market. Entergy’s Utility operating companies are MISO market participants and the companies’ transmission systems are interconnected with those of many neighboring utilities. MISO is an essential link in the safe, cost-effective delivery of electric power across all or parts of 15 U.S. states and the Canadian province of Manitoba. In addition, the Utility operating companies are members of SERC Reliability Corporation (SERC), the Regional Entity with delegated authority from the North American Electric Reliability Corporation (NERC) for the purpose of proposing and enforcing Bulk Electric System reliability standards within 16 central and southeastern states.
Gas Property
As of December 31, 2022, Entergy New Orleans distributed and transported natural gas for distribution within New Orleans, Louisiana, through approximately 2,600 miles of gas pipeline. As of December 31, 2022, the gas properties of Entergy Louisiana, which are located in and around Baton Rouge, Louisiana, were not material to Entergy Louisiana’s financial position.
Title
The Utility operating companies’ generating stations are generally located on properties owned in fee simple. Most of the substations and transmission and distribution lines are constructed on private property or public rights-of-way pursuant to easements, servitudes, or appropriate franchises. Some substation properties are owned in fee simple. The Utility operating companies generally have the right of eminent domain, whereby they may perfect title to, or secure easements or servitudes on, private property for their utility operations.
Substantially all of the physical properties and assets owned by Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are subject to the liens of mortgages securing bonds issued by those companies. The Lewis Creek generating station of Entergy Texas was acquired by merger with a subsidiary of Entergy Texas and is currently not subject to the lien of the Entergy Texas indenture.
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Fuel Supply
The average fuel cost per kWh for the Utility operating companies and System Energy for the years 2020-2022 were:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year | | Natural Gas | | Nuclear | | Coal | | Renewables (a) | | Purchased Power | | MISO Purchases (b) |
| 2022 | | (Cents Per kWh) |
| Entergy Arkansas | | 4.98 | | | 0.52 | | | 2.93 | | | 2.11 | | | 10.90 | | | (2.65) | |
| Entergy Louisiana | | 5.50 | | | 0.57 | | | 2.84 | | | 10.70 | | | 6.95 | | | 6.45 | |
| Entergy Mississippi | | 4.38 | | | — | | | 2.85 | | | 0.04 | | | 6.53 | | | 6.68 | |
| Entergy New Orleans (c) | | 5.10 | | | — | | | — | | | (5.16) | | | — | | | 7.21 | |
| Entergy Texas | | 5.77 | | | — | | | 2.83 | | | 6.26 | | | 5.61 | | | 6.68 | |
| System Energy | | — | | | 0.65 | | | — | | | — | | | — | | | — | |
| Utility | | 5.27 | | | 0.57 | | | 2.89 | | | 7.00 | | | 6.54 | | | 5.95 | |
| | | | | | | | | | | | |
| 2021 | | | | | | | | | | | | |
| Entergy Arkansas | | 4.11 | | | 0.56 | | | 2.43 | | | 2.85 | | | 2.53 | | | 3.87 | |
| Entergy Louisiana | | 3.77 | | | 0.56 | | | 2.62 | | | 10.87 | | | 5.52 | | | 4.04 | |
| Entergy Mississippi | | 2.71 | | | — | | | 2.53 | | | 1.22 | | | 2.70 | | | 4.16 | |
| Entergy New Orleans (c) | | 3.47 | | | — | | | — | | | (2.82) | | | — | | | 4.50 | |
| Entergy Texas | | 4.65 | | | — | | | 2.60 | | | 3.97 | | | 4.53 | | | 4.10 | |
| System Energy | | — | | | 0.55 | | | — | | | — | | | — | | | — | |
| Utility | | 3.75 | | | 0.56 | | | 2.48 | | | 9.07 | | | 4.76 | | | 4.08 | |
| | | | | | | | | | | | |
| 2020 | | | | | | | | | | | | |
| Entergy Arkansas | | 1.78 | | | 0.62 | | | 2.35 | | | 2.28 | | | 7.39 | | | 0.63 | |
| Entergy Louisiana | | 1.98 | | | 0.58 | | | 3.27 | | | 9.99 | | | 3.48 | | | 2.65 | |
| Entergy Mississippi | | 1.73 | | | — | | | 2.52 | | | 0.25 | | | 3.23 | | | 2.26 | |
| Entergy New Orleans | | 1.56 | | | — | | | — | | | 0.02 | | | — | | | 2.99 | |
| Entergy Texas | | 2.23 | | | — | | | 3.17 | | | 3.61 | | | 3.29 | | | 2.71 | |
| System Energy | | — | | | 0.39 | | | — | | | — | | | — | | | — | |
| Utility | | 1.92 | | | 0.57 | | | 2.54 | | | 8.28 | | | 3.35 | | | 2.48 | |
(a)Includes average fuel costs from both owned and purchased power resources.
(b)Includes activity from financial transmission rights. See Note 15 to the financial statements for discussion of financial transmission rights.
(c)Entergy New Orleans’s renewables include liquidated damage payments of $2.9 million in 2022 and $1 million in 2021 due to the delay of in-service dates related to purchased power agreements.
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Actual 2022 and projected 2023 sources of generation for the Utility operating companies and System Energy, including certain power purchases from affiliates under life of unit power purchase agreements, including the Unit Power Sales Agreement, are:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2022 |
| | CT / CCGT (b) | | Legacy Gas | | Nuclear | | Coal | | Renewables (c) | | Purchased Power (d) | | MISO Purchases (e) |
| Entergy Arkansas | 30 | % | | 1 | % | | 50 | % | | 12 | % | | 3 | % | | — | % | | 4 | % |
| Entergy Louisiana | 44 | % | | 9 | % | | 23 | % | | 3 | % | | 2 | % | | 8 | % | | 11 | % |
| Entergy Mississippi | 59 | % | | 6 | % | | 18 | % | | 7 | % | | 1 | % | | — | % | | 9 | % |
| Entergy New Orleans | 54 | % | | 1 | % | | 35 | % | | 1 | % | | 1 | % | | 1 | % | | 7 | % |
| Entergy Texas | 31 | % | | 20 | % | | 11 | % | | 5 | % | | — | % | | 9 | % | | 24 | % |
| System Energy (a) | — | % | | — | % | | 100 | % | | — | % | | — | % | | — | % | | — | % |
| Utility | 42 | % | | 8 | % | | 27 | % | | 5 | % | | 2 | % | | 5 | % | | 11 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2023 |
| | CT / CCGT (b) | | Legacy Gas | | Nuclear | | Coal | | Renewables (c) | | Purchased Power (d) | | MISO Purchases (e) |
| Entergy Arkansas | 26 | % | | — | % | | 58 | % | | 13 | % | | 3 | % | | — | % | | — | % |
| Entergy Louisiana | 47 | % | | 5 | % | | 30 | % | | 3 | % | | 3 | % | | 12 | % | | — | % |
| Entergy Mississippi | 63 | % | | — | % | | 26 | % | | 10 | % | | 1 | % | | — | % | | — | % |
| Entergy New Orleans | 48 | % | | 1 | % | | 45 | % | | 2 | % | | 3 | % | | 1 | % | | — | % |
| Entergy Texas | 44 | % | | 31 | % | | 15 | % | | 9 | % | | — | % | | 1 | % | | — | % |
| System Energy (a) | — | % | | — | % | | 100 | % | | — | % | | — | % | | — | % | | — | % |
| Utility | 44 | % | | 6 | % | | 36 | % | | 7 | % | | 2 | % | | 5 | % | | — | % |
(a)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.
(b)Represents natural gas sourced for Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.
(c)Includes generation from both owned and purchased power resources.
(d)Excludes MISO purchases and renewables purchased through purchased power agreements.
(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 2022 is not projected for 2023.
Some of the Utility’s gas-fired plants are also capable of using fuel oil, if necessary. Although based on current economics the Utility does not expect fuel oil use in 2023, it is possible that various operational events including weather or pipeline maintenance may require the use of fuel oil.
Natural Gas
The Utility operating companies have long-term firm and short-term interruptible gas contracts for both supply and transportation. Over 50% of the Utility operating companies’ power plants maintain some level of long-term firm transportation. Short-term contracts and spot-market purchases satisfy additional gas requirements.
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Entergy Texas owns a gas storage facility and Entergy Louisiana has a firm storage service agreement that provide reliable and flexible natural gas service to certain generating stations.
Many factors, including wellhead deliverability, storage, pipeline capacity, and demand requirements of end users, influence the availability and price of natural gas supplies for power plants. Demand is primarily tied to weather conditions as well as to the prices and availability of other energy sources. Pursuant to federal and state regulations, gas supplies to power plants may be interrupted during periods of shortage. To the extent natural gas supplies are disrupted or natural gas prices significantly increase, the Utility operating companies may in some instances use alternate fuels, such as oil when available, or rely to a larger extent on coal, nuclear generation, and purchased power.
Coal
Entergy Arkansas has committed to six two- to three-year contracts that will supply approximately 85% of the total coal supply needs in 2023. These contracts are staggered in term so that not all contracts have to be renewed the same year. If needed, additional Powder River Basin (PRB) coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. Based on the high cost of alternate sources, modes of transportation, and infrastructure improvements necessary for its delivery, no alternative coal consumption is expected at Entergy Arkansas during 2023. Coal will be transported to Arkansas via an existing Union Pacific transportation agreement that is expected to provide all of Entergy Arkansas’s rail transportation requirements for 2023.
Entergy Louisiana has committed to four two- to three-year contracts that will supply approximately 90% of Nelson Unit 6 coal needs in 2023. If needed, additional PRB coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. For the same reasons as the Entergy Arkansas plants, no alternative coal consumption is expected at Nelson Unit 6 during 2023. Coal will be transported to Nelson via an existing transportation agreement that is expected to provide all of Entergy Louisiana’s rail transportation requirements for 2023.
Coal transportation delivery rates to Entergy Arkansas- and Entergy Louisiana-operated coal-fired units became constrained and were unable to fully meet supply needs and obligations beginning in August 2021. Deliveries remained constrained through 2022 with modest improvement expected later in 2023. Both Entergy Arkansas and Entergy Louisiana control enough railcars to satisfy the rail transportation requirement.
The operator of Big Cajun 2 - Unit 3, Louisiana Generating, LLC, has advised Entergy Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2023, but is also currently experiencing delivery constraints. Entergy Louisiana’s and Entergy Texas’s coal nomination requests to Big Cajun 2 - Unit 3 are made on an annual basis.
Nuclear Fuel
The nuclear fuel cycle consists of the following:
•mining and milling of uranium ore to produce a concentrate;
•conversion of the concentrate to uranium hexafluoride gas;
•enrichment of the uranium hexafluoride gas;
•fabrication of nuclear fuel assemblies for use in fueling nuclear reactors; and
•disposal of spent fuel.
The Registrant Subsidiaries that own nuclear plants, Entergy Arkansas, Entergy Louisiana, and System Energy, are responsible through a shared regulated uranium pool for contracts to acquire nuclear material to be used in fueling Entergy’s Utility nuclear units. These companies own the materials and services in this shared regulated
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uranium pool on a pro rata fractional basis determined by the nuclear generation capability of each company. Any liabilities for obligations of the pooled contracts are on a several but not joint basis. The shared regulated uranium pool maintains inventories of nuclear materials during the various stages of processing. The Registrant Subsidiaries purchase enriched uranium hexafluoride for their nuclear plant reload requirements at the average inventory cost from the shared regulated uranium pool. Entergy Operations, Inc. contracts separately for the fabrication of nuclear fuel as agent on behalf of each of the Registrant Subsidiaries that owns a nuclear plant. All contracts for the disposal of spent nuclear fuel are between the DOE and the owner of a nuclear power plant.
Based upon currently planned fuel cycles, the Utility nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable or fixed prices through most of 2027. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners, including their ability to work through supply disruptions caused by global events, such as the COVID-19 pandemic, or national events, such as political disruption. There are a number of possible supply alternatives that may be accessed to mitigate any supplier performance failure, including potentially drawing upon Entergy’s inventory intended for later generation periods depending upon its risk management strategy at that time, although the pricing of any alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. In addition, some nuclear fuel contracts are on a non-fixed price basis subject to prevailing prices at the time of delivery.
The effects of market price changes may be reduced and deferred by risk management strategies, such as negotiation of floor and ceiling amounts for long-term contracts, buying for inventory or entering into forward physical contracts at fixed prices when Entergy believes it is appropriate and useful. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S.
Entergy’s ability to assure nuclear fuel supply also depends upon the performance reliability of conversion, enrichment, and fabrication services providers. There are fewer of these providers than for uranium. For conversion and enrichment services, like uranium, Entergy diversifies its supply by supplier and country and may take special measures as needed to ensure supply of enriched uranium for the reliable fabrication of nuclear fuel. For fabrication services, each plant is dependent upon the effective performance of the fabricator of that plant’s nuclear fuel, therefore, Entergy provides additional monitoring, inspection, and oversight for the fabrication process to assure reliability and quality.
Entergy Arkansas, Entergy Louisiana, and System Energy each have made arrangements to lease nuclear fuel and related equipment and services. The lessors, which are consolidated in the financial statements of Entergy and the applicable Registrant Subsidiary, finance the acquisition and ownership of nuclear fuel through credit agreements and the issuance of notes. These credit facilities are subject to periodic renewal, and the notes are issued periodically, typically for terms between three and seven years.
Natural Gas Purchased for Resale
Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with one interstate and three intrastate pipelines. Entergy New Orleans has a “no-notice” service gas purchase contract with Symmetry Energy Solutions which guarantees Entergy New Orleans gas delivery at specific delivery points and at any volume within the minimum and maximum set forth in the contract amounts. The Symmetry Energy Solutions gas supply is transported to Entergy New Orleans pursuant to a transportation service agreement with Gulf South Pipeline Co. This service is subject to FERC-approved rates. Entergy New Orleans also makes interruptible spot market purchases.
Entergy Louisiana purchased natural gas for resale in 2022 under a firm contract from Sequent Energy Management L.P. The gas is delivered through a combination of intrastate and interstate pipelines.
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As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy Louisiana’s or Entergy New Orleans’s suppliers failed to perform their obligations to deliver gas under their supply agreements. Gulf South Pipeline Co. could curtail transportation capacity only in the event of pipeline system constraints.
Federal Regulation of the Utility
State or local regulatory authorities, as described above, regulate the retail rates of the Utility operating companies. The FERC regulates wholesale sales of electricity rates and interstate transmission of electricity, including System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. See Note 2 to the financial statements for further discussion of federal regulation proceedings.
Transmission and MISO Markets
In December 2013 the Utility operating companies integrated into the MISO RTO. Although becoming a member of MISO did not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities, MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. MISO also exercises functional control of transmission planning and congestion management and provides schedules and pricing for the commitment and dispatch of generation that is offered into MISO’s markets, as well as pricing for load that bids into the markets. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their generating facilities into the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. Each Utility operating company has its own transmission pricing zone and a formula rate template (included as Attachment O to the MISO tariff) used to establish transmission rates within MISO. The terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets and the allocation of transmission upgrade costs, are subject to regulation by the FERC.
System Energy and Related Agreements
System Energy recovers costs related to its interest in Grand Gulf through rates charged to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans for capacity and energy under the Unit Power Sales Agreement (described below). In 1998 the FERC approved requests by Entergy Arkansas and Entergy Mississippi to accelerate a portion of their Grand Gulf purchased power obligations. Entergy Arkansas’s and Entergy Mississippi’s acceleration of Grand Gulf purchased power obligations ceased effective July 2001 and July 2003, respectively, as approved by the FERC. See Note 2 to the financial statements for discussion of proceedings at the FERC related to System Energy.
Unit Power Sales Agreement
The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System Energy’s ownership and leasehold interests in Grand Gulf to Entergy Arkansas (36%), Entergy Louisiana (14%), Entergy Mississippi (33%), and Entergy New Orleans (17%). Each of these companies is obligated to make payments to System Energy for its entitlement of capacity and energy on a full cost-of-service basis regardless of the quantity of energy delivered. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenue. The financial condition of System Energy depends upon the continued commercial operation of Grand Gulf and the receipt of such payments. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans generally recover payments made under the Unit Power Sales Agreement through rates charged to their customers.
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In the case of Entergy Arkansas and Entergy Louisiana, payments are also recovered through sales of electricity from their respective retained shares of Grand Gulf. Under a settlement agreement entered into with the APSC in 1985 and amended in 1988, Entergy Arkansas retains 22% of its 36% share of Grand Gulf-related costs and recovers the remaining 78% of its share in rates. In the event that Entergy Arkansas is not able to sell its retained share to third parties, it may sell such energy to its retail customers at a price equal to its avoided cost, which is currently less than Entergy Arkansas’s cost from its retained share. Entergy Arkansas has life-of-resources purchased power agreements with Entergy Louisiana and Entergy New Orleans that sell a portion of the output of Entergy Arkansas’s retained share of Grand Gulf to those companies, with the remainder of the retained share being sold to Entergy Mississippi through a separate life-of-resources purchased power agreement. In a series of LPSC orders, court decisions, and agreements from late 1985 to mid-1988, Entergy Louisiana was granted cost recovery with respect to costs associated with Entergy Louisiana’s share of capacity and energy from Grand Gulf, subject to certain terms and conditions. Entergy Louisiana retains and does not recover from retail ratepayers 18% of its 14% share of the costs of Grand Gulf capacity and energy and recovers the remaining 82% of its share in rates. Entergy Louisiana is allowed to recover through the fuel adjustment clause at 4.6 cents per kWh for the energy related to its retained portion of these costs. Alternatively, Entergy Louisiana may sell such energy to non-affiliated parties at prices above the fuel adjustment clause recovery amount, subject to the LPSC’s approval. Entergy Arkansas also has a life-of-resources purchased power agreement with Entergy Mississippi to sell a portion of the output of Entergy Arkansas’s non-retained share of Grand Gulf. Entergy Mississippi was granted cost recovery for those purchases by the MPSC through its annual unit power cost rate mechanism.
Availability Agreement
The Availability Agreement among System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans was entered into in 1974 in connection with the original financing by System Energy of Grand Gulf. The Availability Agreement provides that System Energy make available to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans all capacity and energy available from System Energy’s share of Grand Gulf.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans also agreed severally to pay System Energy monthly for the right to receive capacity and energy from Grand Gulf in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement) would at least equal System Energy’s total operating expenses for Grand Gulf (including depreciation at a specified rate and expenses incurred in a permanent shutdown of Grand Gulf) and interest charges.
The allocation percentages under the Availability Agreement are fixed as follows: Entergy Arkansas - 17.1%; Entergy Louisiana - 26.9%; Entergy Mississippi - 31.3%; and Entergy New Orleans - 24.7%. The allocation percentages under the Availability Agreement would remain in effect and would govern payments made under such agreement in the event of a shortfall of operating expense funds available to System Energy from other sources, including payments under the Unit Power Sales Agreement.
System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for all of its outstanding series of first mortgage bonds, as well as for its outstanding term loan and the pollution control revenue refunding bonds issued on its behalf. In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they were prohibited by governmental action from making payments under the Availability Agreement (for example, if the FERC reduced or disallowed such payments as constituting excessive rates), they would then make subordinated advances to System Energy in the same amounts and at the same times as the prohibited payments. System Energy would not be allowed to repay these subordinated advances so long as it remained in default under the related indebtedness or in other similar circumstances.
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Each of the assignment agreements relating to the Availability Agreement provides that Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans will make payments directly to System Energy. However, if there is an event of default, those payments must be made directly to the holders of indebtedness that are the beneficiaries of such assignment agreements. The payments must be made pro rata according to the amount of the respective obligations secured.
The obligations of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans to make payments under the Availability Agreement are subject to the receipt and continued effectiveness of all necessary regulatory approvals. Sales of capacity and energy under the Availability Agreement would require that the Availability Agreement be submitted to the FERC for approval with respect to the terms of such sale. No such filing with the FERC has been made because sales of capacity and energy from Grand Gulf are being made pursuant to the Unit Power Sales Agreement. If, for any reason, sales of capacity and energy are made in the future pursuant to the Availability Agreement, the jurisdictional portions of the Availability Agreement would be submitted to the FERC for approval.
Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement to System Energy have exceeded the amounts payable under the Availability Agreement and, therefore, 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 certain of 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 because their Availability Agreement obligations exceed their Unit Power Sales Agreement obligations.
The Availability Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, without further consent of any assignees or other creditors.
Service Companies
Entergy Services, a limited liability company wholly-owned by Entergy Corporation, provides management, administrative, accounting, legal, engineering, and other services primarily to the Utility operating companies, but also provides services to Entergy Wholesale Commodities. Entergy Operations is also wholly-owned by Entergy Corporation and provides nuclear management, operations and maintenance services under contract for ANO, River Bend, Waterford 3, and Grand Gulf, subject to the owner oversight of Entergy Arkansas, Entergy Louisiana, and System Energy, respectively. Entergy Services and Entergy Operations provide their services to the Utility operating companies and System Energy on an “at cost” basis, pursuant to cost allocation methodologies for these service agreements that were approved by the FERC.
Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas
Effective December 31, 2007, Entergy Gulf States, Inc. completed a jurisdictional separation into two vertically integrated utility companies, one operating under the sole retail jurisdiction of the PUCT, Entergy Texas, and the other operating under the sole retail jurisdiction of the LPSC, Entergy Gulf States Louisiana. Entergy Texas owns all Entergy Gulf States, Inc. distribution and transmission assets located in Texas, the gas-fired generating plants located in Texas, undivided 42.5% ownership shares of Entergy Gulf States, Inc.’s 70% ownership interest in Nelson Unit 6 and 42% ownership interest in Big Cajun 2, Unit 3, which are coal-fired generating plants located in Louisiana, and other assets and contract rights to the extent related to utility operations in Texas. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, owns all of the remaining assets that were owned by Entergy Gulf States, Inc. On a book value basis, approximately 58.1% of the Entergy Gulf States, Inc. assets were allocated to Entergy Gulf States Louisiana and approximately 41.9% were allocated to Entergy Texas.
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Entergy Texas purchases from Entergy Louisiana pursuant to a life-of-unit purchased power agreement a 42.5% share of capacity and energy from the 70% of River Bend subject to retail regulation. Entergy Texas was allocated a share of River Bend’s nuclear and environmental liabilities that is identical to the share of the plant’s output purchased by Entergy Texas under the purchased power agreement. In connection with the termination of the System Agreement effective August 31, 2016, the purchased power agreements that were put in place for certain legacy units at the time of the jurisdictional separation were also terminated at that time. See Note 2 to the financial statements for additional discussion of the purchased power agreements.
Entergy Louisiana and Entergy Gulf States Louisiana Business Combination
On October 1, 2015, the businesses formerly conducted by Entergy Louisiana (Old Entergy Louisiana) and Entergy Gulf States Louisiana (Old Entergy Gulf States Louisiana) were combined into a single public utility. In order to effect the business combination, under the Texas Business Organizations Code (TXBOC), Old Entergy Louisiana allocated substantially all of its assets to a new subsidiary, Entergy Louisiana Power, LLC, a Texas limited liability company (New Entergy Louisiana), and New Entergy Louisiana assumed the liabilities of Old Entergy Louisiana, in a transaction regarded as a merger under the TXBOC. Under the TXBOC, Old Entergy Gulf States Louisiana allocated substantially all of its assets to a new subsidiary (New Entergy Gulf States Louisiana) and New Entergy Gulf States Louisiana assumed the liabilities of Old Entergy Gulf States Louisiana, in a transaction regarded as a merger under the TXBOC. New Entergy Gulf States Louisiana then merged into New Entergy Louisiana with New Entergy Louisiana surviving the merger. Thereupon, Old Entergy Louisiana changed its name from “Entergy Louisiana, LLC” to “EL Investment Company, LLC” and New Entergy Louisiana changed its name from “Entergy Louisiana Power, LLC” to “Entergy Louisiana, LLC” (Entergy Louisiana). With the completion of the business combination, Entergy Louisiana holds substantially all of the assets, and has assumed the liabilities, of Old Entergy Louisiana and Old Entergy Gulf States Louisiana.
Entergy New Orleans Internal Restructuring
In November 2017, pursuant to the agreement in principle, Entergy New Orleans, Inc. undertook a multi-step restructuring, including the following:
•Entergy New Orleans, Inc. redeemed its outstanding preferred stock at a price of approximately $21 million, which included a call premium of approximately $819,000, plus any accumulated and unpaid dividends.
•Entergy New Orleans, Inc. converted from a Louisiana corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy New Orleans, Inc. allocated substantially all of its assets to a new subsidiary, Entergy New Orleans Power, LLC, a Texas limited liability company (Entergy New Orleans Power), and Entergy New Orleans Power assumed substantially all of the liabilities of Entergy New Orleans, Inc. in a transaction regarded as a merger under the TXBOC. Entergy New Orleans, Inc. remained in existence and held the membership interests in Entergy New Orleans Power.
•Entergy New Orleans, Inc. contributed the membership interests in Entergy New Orleans Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy New Orleans Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2017, Entergy New Orleans, Inc. changed its name to Entergy Utility Group, Inc., and Entergy New Orleans Power then changed its name to Entergy New Orleans, LLC. Entergy New Orleans, LLC holds substantially all of the assets, and has assumed substantially all of the liabilities, of Entergy New Orleans, Inc. The restructuring was accounted for as a transaction between entities under common control.
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Entergy Arkansas Internal Restructuring
In November 2018, Entergy Arkansas undertook a multi-step restructuring, including the following:
•Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.
•Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Arkansas Power, LLC, a Texas limited liability company (Entergy Arkansas Power), and Entergy Arkansas Power assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.
•Entergy Arkansas, Inc. contributed the membership interests in Entergy Arkansas Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Arkansas Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Arkansas, Inc. changed its name to Entergy Utility Property, Inc., and Entergy Arkansas Power then changed its name to Entergy Arkansas, LLC. Entergy Arkansas, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Arkansas, Inc. The transaction was accounted for as a transaction between entities under common control.
Entergy Mississippi Internal Restructuring
In November 2018, Entergy Mississippi undertook a multi-step restructuring, including the following:
•Entergy Mississippi, Inc. redeemed its outstanding preferred stock, at the aggregate redemption price of approximately $21.2 million.
•Entergy Mississippi, Inc. converted from a Mississippi corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Mississippi, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Mississippi Power and Light, LLC, a Texas limited liability company (Entergy Mississippi Power and Light), and Entergy Mississippi Power and Light assumed substantially all of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Mississippi, Inc. remained in existence and held the membership interests in Entergy Mississippi Power and Light.
•Entergy Mississippi, Inc. contributed the membership interests in Entergy Mississippi Power and Light to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Mississippi Power and Light is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Mississippi, Inc. changed its name to Entergy Utility Enterprises, Inc., and Entergy Mississippi Power and Light then changed its name to Entergy Mississippi, LLC. Entergy Mississippi, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Mississippi, Inc. The restructuring was accounted for as a transaction between entities under common control.
Entergy Wholesale Commodities
See “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the shutdown and sale of each of the Entergy Wholesale Commodities nuclear power plants. With the sale of Palisades in June 2022, Entergy completed its multi-year strategy to exit the merchant power business.
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Entergy Wholesale Commodities includes the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. Entergy Wholesale Commodities also provides decommissioning-related services to nuclear power plants owned by non-affiliated entities in the United States.
Property
Entergy Wholesale Commodities includes ownership in the following non-nuclear power plants:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Plant | | Location | | Ownership | | Net Owned Capacity (a) | | Type |
| Independence Unit 2; 842 MW | | Newark, AR | | 14% | | 121 MW(b) | | Coal |
| Nelson Unit 6; 550 MW | | Westlake, LA | | 11% | | 60 MW(b) | | Coal |
(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.
All of Entergy Wholesale Commodities’ owned generation falls under the authority of MISO. Entergy Wholesale Commodities’ customers for the sale of both energy and capacity from its owned generation and its contracted power purchases include retail power providers, utilities, electric power co-operatives, power trading organizations, and other power generation companies. The majority of Entergy Wholesale Commodities’ owned generation and contracted power purchases are sold under cost-based contract.
Other Business Activities
TLG Services, a subsidiary in the Entergy Wholesale Commodities segment, offers decommissioning, engineering, and related services to nuclear power plant owners.
Regulation of Entergy’s Business
Federal Power Act
The Federal Power Act provides the FERC the authority to regulate:
•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.
The Federal Power Act gives the FERC jurisdiction over the rates charged by System Energy for Grand Gulf capacity and energy provided to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans and over the rates charged by Entergy Arkansas and Entergy Louisiana to unaffiliated wholesale customers. The FERC also regulates wholesale power sales between the Utility operating companies. In addition, the FERC regulates the MISO RTO, an independent entity that maintains functional control over the combined transmission systems of its members and administers wholesale energy, capacity, and ancillary services markets for market participants in the MISO region, including the Utility operating companies. FERC regulation of the MISO RTO includes regulation of the design and implementation of the wholesale markets administered by the MISO RTO, as
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well as the rates, terms, and conditions of open access transmission service over the member systems and the allocation of costs associated with transmission upgrades.
Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 65 MW of capacity.
State Regulation
Utility
Entergy Arkansas is subject to regulation by the APSC as to the following:
•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 non-exempt 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.
Additionally, Entergy Arkansas serves a limited number of retail customers in Tennessee. Pursuant to legislation enacted in Tennessee, Entergy Arkansas is subject to complaints before the Tennessee Regulatory Authority only if it fails to treat its retail customers in Tennessee in the same manner as its retail customers in Arkansas. Additionally, Entergy Arkansas maintains limited facilities in Missouri but does not provide retail electric service to customers in Missouri. Although Entergy Arkansas obtained a certificate with respect to its Missouri facilities, Entergy Arkansas is not subject to retail ratemaking jurisdiction in Missouri.
Entergy Louisiana’s electric and gas business is subject to regulation by the LPSC as to the following:
•utility service;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment clause, environmental adjustment charge, 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 for purchase power contracts that exceed either 5 MW or one year in term;
•procurement process to acquire capacity over 50 MW;
•audits of the energy efficiency rider;
•avoided cost payment to non-exempt Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers and acquisitions and other changes of control.
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Entergy Mississippi is subject to regulation by the MPSC as to the following:
•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;
•certification of generating facilities and certain transmission projects;
•avoided cost payments to non-exempt Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers, acquisitions, and other changes of control.
Entergy Mississippi is also subject to regulation by the APSC as to the certificate of environmental compatibility and public need for the Independence Station, which is located in Arkansas.
Entergy New Orleans is subject to regulation by the City Council as to the following:
•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;
•avoided cost payments to non-exempt Qualifying Facilities;
•issuance and sale of certain securities; and
•utility mergers and acquisitions and other changes of control.
To the extent authorized by governing legislation, Entergy Texas is subject to the original jurisdiction of the municipal authorities of a number of incorporated cities in Texas with appellate jurisdiction over such matters residing in the PUCT. Entergy Texas is also subject to regulation by the PUCT as to the following:
•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 non-exempt Qualifying Facilities;
•net energy metering; 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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Regulation of the Nuclear Power Industry
Atomic Energy Act of 1954 and Energy Reorganization Act of 1974
Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose civil penalties or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, Entergy Louisiana, and System Energy, as owners of all or portions of ANO, River Bend and Waterford 3, and Grand Gulf, respectively, and Entergy Operations, as the licensee and operator of these units, are subject to the jurisdiction of the NRC.
Nuclear Waste Policy Act of 1982
Spent Nuclear Fuel
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 Arkansas is the only one of the Utility operating companies that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 2022 of $195.0 million for the one-time fee. The fees payable to the DOE may be adjusted in the future to assure full recovery. 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. Entergy’s total spent fuel fees to date, including the one-time fee liability of Entergy Arkansas, have surpassed $1.7 billion (exclusive of amounts relating to Entergy plants that were paid or are owed by prior owners of those plants).
The permanent spent fuel repository in the U.S. has been legislated to be Yucca Mountain, Nevada. The DOE is required by law to proceed with the licensing (the DOE filed the license application in June 2008) and, after the license is granted by the NRC, proceed with the repository construction and commencement of receipt of spent fuel. 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. The DOE continues to delay meeting its obligation. Specific steps were taken to discontinue the Yucca Mountain project, including a motion to the NRC to withdraw the license application with prejudice and the establishment of a commission to develop recommendations for alternative spent fuel storage solutions. In August 2013 the U.S. Court of Appeals for the D.C. Circuit ordered the NRC to continue with the Yucca Mountain license review, but only to the extent of funds previously appropriated by Congress for that purpose and not yet used. Although the NRC completed the safety evaluation report for the license review in 2015, the previously appropriated funds are not sufficient to complete the review, including required hearings. The government has taken no effective action to date related to the recommendations of the appointed spent fuel study commission. Accordingly, large uncertainty remains regarding the time frame under which the DOE will begin to accept spent fuel from Entergy’s facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at Entergy’s nuclear sites.
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 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
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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.
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. These subsidiaries have been, and continue to be, involved in litigation to recover the damages caused by the DOE’s delay in performance. See Note 8 to the financial statements for discussion of final judgments recorded by Entergy in 2020, 2021, and 2022 related to Entergy’s nuclear owner licensee subsidiaries’ litigation with the DOE. Through 2022, Entergy’s subsidiaries have won and collected on judgments against the government totaling approximately $1 billion.
Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are providing their own spent fuel storage. Storage capability additions using dry casks began operations at ANO in 1996, at River Bend in 2005, at Grand Gulf in 2006, and at Waterford 3 in 2011. These facilities will be expanded as needed.
Nuclear Plant Decommissioning
Entergy Arkansas, Entergy Louisiana, and System Energy are entitled to recover from customers through electric rates the estimated decommissioning costs for ANO, Waterford 3, and Grand Gulf, respectively. In addition, Entergy Louisiana and Entergy Texas are entitled to recover from customers through electric rates the estimated decommissioning costs for the portion of River Bend subject to retail rate regulation. The collections are deposited in trust funds that can only be used in accordance with NRC and other applicable regulatory requirements. Entergy periodically reviews and updates the estimated decommissioning costs to reflect inflation and changes in regulatory requirements and technology, and then makes applications to the regulatory authorities to reflect, in rates, the changes in projected decommissioning costs.
In December 2018 the APSC ordered collections in rates for decommissioning ANO 2 and found that ANO 1’s decommissioning was adequately funded without additional collections. In November 2021, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that both ANO 1 and 2 decommissioning trusts were adequately funded without further collections, and in December 2021 the APSC ordered zero collections for ANO 1 and 2 decommissioning. In November 2022, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that ANO 1’s decommissioning trust was adequately funded, but that ANO 2’s fund had a projected shortage as a result of a decline in decommissioning trust fund investment values over the past year. The filing proposes a reinstatement of decommissioning cost recovery for ANO 2. Management cannot predict the outcome of this filing.
In July 2010 the LPSC approved increased decommissioning collections for Waterford 3 and the Louisiana regulated share of River Bend to address previously identified funding shortfalls. This LPSC decision contemplated that the level of decommissioning collections could be revisited should the NRC grant license extensions for both Waterford 3 and River Bend. In July 2019, following the NRC approval of license extensions for Waterford 3 and River Bend, Entergy Louisiana made a filing with the LPSC seeking to adjust decommissioning and depreciation rates for those plants, including one proposed scenario that would adjust Louisiana-jurisdictional decommissioning collections to zero for both plants (including an offsetting increase in depreciation rates). Because of the ongoing public health emergency arising from the COVID-19 pandemic and accompanying economic uncertainty, Entergy Louisiana determined that the relief sought in the filing was no longer appropriate, and in November 2020, filed an unopposed motion to dismiss the proceeding. Following that filing, in a December 2020 order, the LPSC dismissed the proceeding without prejudice. In July 2021, Entergy Louisiana made a filing with the LPSC to adjust Waterford 3 and River Bend decommissioning collections based on the latest site-specific decommissioning cost estimates for those plants. The filing seeks to increase Waterford 3 decommissioning collections and decrease River Bend decommissioning collections. The procedural schedule in the case has been suspended pending settlement negotiations. Management cannot predict the outcome of this filing.
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In December 2010 the PUCT approved increased decommissioning collections for the Texas share of River Bend to address previously identified funding shortfalls. In December 2018 the PUCT approved a settlement that eliminated River Bend decommissioning collections for the Texas jurisdictional share of the plant based on a determination by Entergy Texas that the existing decommissioning fund was adequate following license renewal. In July 2022, Entergy Texas filed a rate case that proposed continuation of the cessation of River Bend decommissioning collections. In December 2022, Entergy Texas filed on behalf of the parties a motion to abate the hearing on the merits to give parties additional time to finalize a settlement, which was approved by the presiding ALJ along with an order for the parties to file monthly settlement status reports. Management cannot predict the outcome of this filing.
In December 2016 the NRC issued a 20-year operating license renewal for Grand Gulf. In a 2017 filing at the FERC, System Energy stated that with the renewed operating license, Grand Gulf’s decommissioning trust was sufficiently funded, and proposed, among other things, to cease decommissioning collections for Grand Gulf effective October 1, 2017. The FERC accepted a settlement including the proposed decommissioning revenue requirement by letter order in August 2018.
Entergy currently believes its decommissioning funding will be sufficient for its nuclear plants subject to retail rate regulation, although decommissioning cost inflation and trust fund performance will ultimately determine the adequacy of the funding amounts.
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. In March 2021 filings with the NRC were made reporting on decommissioning funding for all of Entergy’s subsidiaries’ nuclear plants. Those reports showed that decommissioning funding for each of the nuclear plants met the NRC’s financial assurance requirements.
Additional information with respect to Entergy’s decommissioning costs and decommissioning trust funds is found in Note 9 and Note 16 to the financial statements.
Price-Anderson Act
The Price-Anderson Act requires that reactor licensees purchase and maintain the maximum amount of nuclear liability insurance available and participate in an industry assessment program called Secondary Financial Protection in order to protect 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 limits the contingent liability for a single nuclear incident to a maximum assessment of approximately $137.6 million per reactor (with 96 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, Entergy Louisiana, or System Energy is liable, protection is afforded through a combination of private insurance and the Secondary Financial Protection program. In addition to this, insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units is also purchased. The Price-Anderson Act and insurance applicable to the nuclear programs of Entergy are discussed in more detail in Note 8 to the financial statements.
NRC Reactor Oversight Process
The NRC’s Reactor Oversight Process is a program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response. The NRC evaluates plant performance by analyzing two distinct inputs: inspection findings resulting from the NRC’s inspection program and performance indicators reported by the licensee. The evaluations result in the placement of
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each plant in one of the NRC’s Reactor Oversight Process Action Matrix columns: “licensee response column,” or Column 1, “regulatory response column,” or Column 2, “degraded cornerstone column,” or Column 3, and “multiple/repetitive degraded cornerstone column,” or Column 4, and “unacceptable performance,” or Column 5. Plants in Column 1 are subject to normal NRC inspection activities. Plants in Column 2, Column 3, or Column 4 are subject to progressively increasing levels of inspection by the NRC. Continued plant operation is not permitted for plants in Column 5. All of the nuclear generating plants owned and operated by Entergy’s Utility business are currently in Column 1, except Waterford 3, which is in Column 2.
In September 2022 the NRC placed Waterford 3 in Column 2 based on an error associated with a radiation monitor calibration. Entergy corrected the issue with the radiation monitor in February 2022; however, Waterford 3 is expected to remain in Column 2 until third quarter 2023 based on a subsequent radiation monitor calibration issue.
Environmental Regulation
Entergy’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy’s businesses are in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted below. Because environmental regulations are subject to change, future compliance requirements and costs cannot be precisely estimated. Except to the extent discussed below, at this time compliance with federal, state, and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of Entergy’s businesses and is not expected to have a material effect on their competitive position, results of operations, cash flows, or financial position.
Clean Air Act and Subsequent Amendments
The Clean Air Act and its amendments establish several programs that currently or in the future may affect Entergy’s fossil-fueled generation facilities and, to a lesser extent, certain operations at nuclear and other facilities. Individual states also operate similar independent state programs or delegated federal programs that may include requirements more stringent than federal regulatory requirements. These programs include:
•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.
National Ambient Air Quality Standards
The Clean Air Act requires the EPA to set National Ambient Air Quality Standards (NAAQS) for ozone, carbon monoxide, lead, nitrogen dioxide, particulate matter, and sulfur dioxide, and requires periodic review of those standards. When an area fails to meet an ambient standard, it is considered to be in nonattainment and is classified as “marginal,” “moderate,” “serious,” or “severe.” When an area fails to meet the ambient air standard, the EPA requires state regulatory authorities to prepare state implementation plans meant to cause progress toward bringing the area into attainment with applicable standards.
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Ozone Nonattainment
Entergy Texas operates two fossil-fueled generating facilities (Lewis Creek and Montgomery County Power Station) in a geographic area that is not in attainment with the applicable NAAQS for ozone. The ozone nonattainment area that affects Entergy Texas is the Houston-Galveston-Brazoria area. Both Lewis Creek and the Montgomery County Power Station hold all necessary permits for operation and comply with applicable air quality program regulations. Measures enacted to return the area to ozone attainment could make these program regulations more stringent. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and nonattainment with the ozone NAAQS.
Potential SO2Nonattainment
The EPA issued a final rule in June 2010 adopting an SO2 1-hour national ambient air quality standard of 75 parts per billion. In Entergy’s utility service territory, only St. Bernard Parish and Evangeline Parish in Louisiana are designated as nonattainment. In August 2017 the EPA issued a letter indicating that East Baton Rouge and St. Charles parishes would be designated by December 31, 2020, as monitors were installed to determine compliance. In March 2021 the EPA published a final rule designating East Baton Rouge, St. Charles, St. James, and West Baton Rouge parishes in Louisiana as attainment/unclassifiable, and, in Texas, Jefferson County as attainment/unclassifiable and Orange County as unclassifiable. No challenges to these final designations were filed within the 60 day deadline. Entergy continues to monitor this situation.
Hazardous Air Pollutants
The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011, which had a compliance date, with a widely granted one-year extension, of April 2016. The required controls have been installed and are operational at all affected Entergy units. In May 2020 the EPA finalized a rule that finds that it is not “appropriate and necessary” to regulate hazardous air pollutants from electric steam generating units under the provisions of section 112(n) of the Clean Air Act. This is a reversal of the EPA’s previous finding requiring such regulation. The final appropriate and necessary finding does not revise the underlying MATS rule. Several lawsuits have been filed challenging the appropriate and necessary finding. In February 2021 the D.C. Circuit granted the EPA’s motion to hold the litigation in abeyance pending the agency’s review of the appropriate and necessary rule. In February 2022 the EPA issued a proposed rule revoking the 2020 rule and determining, again, that it is “appropriate and necessary” to regulate hazardous air pollutants. The EPA is seeking additional information, which it could use to further tighten the standard. Entergy will continue to monitor this situation.
Cross-State Air Pollution
In March 2005 the EPA finalized the Clean Air Interstate Rule (CAIR), which was intended to reduce SO2 and NOx emissions from electric generation plants in order to improve air quality in twenty-nine eastern states. The rule required a combination of capital investment to install pollution control equipment and increased operating costs through the purchase of emission allowances. Entergy began implementation in 2007, including installation of controls at several facilities and the development of an emission allowance procurement strategy. Based on several court challenges, CAIR and its subsequent versions, now known as the Cross-State Air Pollution Rule (CSAPR), have been remanded to and modified by the EPA on multiple occasions.
In April 2022 the EPA published a rule to address interstate transport for the 2015 ozone NAAQS which will increase the stringency of the CSAPR program in all four of the states where the Utility operating companies operate. If finalized as proposed, the rule will significantly reduce emission allowances and would likely require the installation of post-combustion nitrogen oxides (NOx) emissions controls on any coal or large legacy gas units that will operate beyond 2026 and are not currently equipped with such controls. Fifteen Entergy-owned units, totaling approximately 9,370 MW of total unit capacity, are identified by the EPA for selective catalytic reduction retrofits.
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Based on the EPA estimates, Entergy’s share of the capital costs would be approximately $1.6 billion if all the identified units were in fact retrofitted. Additionally, the EPA is proposing controls on certain non-electric generating NOx sources. Since releasing the proposed rule, the price for Group 3 NOx sources allowances has increased significantly, peaking at over $45,000 per allowance in late August 2022 before stabilizing in the range of $15,000 to $18,000 per allowance since September 2022. Comments on the proposed rule were due in June 2022. MISO, other impacted regional transmission organizations, and various state public service commissions all filed comments expressing reliability concerns if the rule is finalized as proposed. Entergy filed individual comments which assert, in addition to other issues, that the EPA’s proposal represents over-control of the Entergy units in Arkansas and Mississippi; the EPA should consider an alternative approach or provide flexibility for units with a limited remaining useful life; the EPA should consult with regional transmission organizations to determine the reliability impacts of the proposed rule; and the EPA should consider and incorporate current economic trends, including inflation, into any benefit-costs analysis supporting the rule.
Regional Haze
In June 2005 the EPA issued its final Clean Air Visibility Rule (CAVR) regulations that potentially could result in a requirement to install SO2 and NOx pollution control technology as Best Available Retrofit Control Technology to continue operating certain of Entergy’s fossil generation units. The rule leaves certain CAVR determinations to the states. This rule establishes a series of 10-year planning periods, with states required to develop State Implementation Plans (SIPs) for each planning period, with each SIP including such air pollution control measures as may be necessary to achieve the ultimate goal of the CAVR by the year 2064. The various states are currently in the process of developing SIPs to implement the second planning period of the CAVR, which addresses the 2018-2028 planning period.
In January and February 2018, Entergy Arkansas, Entergy Mississippi, Entergy Power, and other co-owners received 60-day notice of intent to sue letters from the Sierra Club and the National Parks Conservation Association concerning allegations of violations of new source review and permitting provisions of the Clean Air Act at the Independence and White Bluff coal-burning units, respectively. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims and reducing the risk that Entergy Arkansas, as operator of Independence and White Bluff, might be compelled under the Clean Air Act’s regional haze program to install costly emissions control technologies. Consistent with the terms of the settlement, Entergy Arkansas, along with co-owners, agreed to begin using only low-sulfur coal at Independence and White Bluff by mid-2021; agreed to cease using coal at White Bluff and Independence by the end of 2028 and 2030, respectively; agreed to cease operation of the remaining gas unit at Lake Catherine by the end of 2027; reserved the option to develop new generating sources at each plant site; and committed to installing or proposing to regulators at least 800 MWs of renewable generation by the end of 2027, with at least half installed or proposed by the end of 2022 (which includes two existing Entergy Arkansas projects) and with all qualifying co-owner projects counting toward satisfaction of the obligation. Under the settlement, the Sierra Club and the National Parks Conservation Association also waived certain potential existing claims under federal and state environmental law with respect to specified generating plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the National Parks Conservation Association, was subject to approval by the U.S. District Court for the Eastern District of Arkansas. In November 2020 the court denied motions by the Arkansas Attorney General and the Arkansas Affordable Energy Coalition to intervene and to stay the proceedings. The proposed intervenors did not appeal the ruling. The District Court approved and entered the proposed settlement in March 2021. Entergy met the settlement deadline to use low-sulfur coal and is on target to meet the other requirements of the settlement. See “Remaining Useful Lives Review” in the “State and Local Rate Regulation and Fuel-Cost Recovery” section of Entergy Arkansas, LLC and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the APSC’s proceeding related to Entergy Arkansas’s utility generation units.
The second planning period (2018-2028) for the regional haze program requires states to examine sources for impacts on visibility and to prepare SIPs by July 31, 2021 to ensure reasonable progress is being made to attain
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visibility improvements. Entergy received information collection requests from the Arkansas and Louisiana Departments of Environmental Quality requesting an evaluation of technical and economic feasibility of various NOx and SO2 control technologies for Independence, Nelson 6, Nelson Industrial Steam Company (NISCO), and Ninemile. Responses to the information collection requests have been submitted to the respective state agencies. Louisiana has issued its draft SIP which, at this time, does not propose any additional air emissions controls for the affected Entergy units in Louisiana. Some public commenters, however, believe additional air controls are cost-effective. It is not yet clear how the Louisiana Department of Environmental Quality (LDEQ) will respond in its final SIP, and the agency, like many other state agencies, did not meet the July 31, 2021 deadline to submit a SIP to the EPA for review.
Similar to the LDEQ, the Arkansas Department of Energy and Environment, Division of Environmental Quality (ADEQ) did not meet the July 31, 2021 SIP submission deadline, but subsequently submitted it to the EPA for review. The ADEQ reviewed Entergy’s Independence plant, but determined that additional air emission controls would not be cost-effective considering the facility’s commitment to cease coal-fired combustion by December 31, 2030.
The Texas Commission on Environmental Quality has completed its second-planning period SIP and submitted it to the EPA for review. There were no Entergy sources selected for additional emission controls. The Mississippi Department of Environmental Quality continues to develop its SIP, but there are no Entergy sources that are expected to be impacted.
In August 2022 the EPA issued findings of failure to submit regional haze SIPs to 15 states, including Louisiana and Mississippi. These findings were effective September 2022 and start the two-year period for the EPA to either approve a SIP submitted by the state or issue a final federal plan.
Greenhouse Gas Emissions
In July 2019 the EPA released the Affordable Clean Energy Rule (ACE), which applies only to existing coal-fired electric generating units. The ACE determines that heat rate improvements are the best system of emission reductions and lists six candidate technologies for consideration by states at each coal unit. The rule and associated rulemakings by the EPA replace the Obama administration’s Clean Power Plan, which established national emissions performance rates for existing fossil-fuel fired steam electric generating units and combustion turbines. The ACE rule provides states discretion in determining how the best system for emission reductions applies to individual units, including through the consideration of technical feasibility and the remaining useful life of the facility. The ADEQ and the LDEQ have issued information collection requests to Entergy facilities to help the states collect the information needed to determine the best system of emission reductions for each facility. Entergy responded to the requests. In January 2021 the U.S. Court of Appeals for the D.C. Circuit vacated ACE. The court held that ACE relied on an incorrect interpretation of the Clean Air Act that the statute expressly forecloses emission reduction approaches, such as emissions trading and generating shifting, that cannot be applied at and to the individual source. The court remanded ACE to the EPA for further consideration and also vacated the repeal of the Clean Power Plan. In March 2021 the D.C. Circuit issued a partial mandate vacating the ACE rule, but withheld the mandate vacating the repeal of the Clean Power Plan pending the EPA’s new rulemaking to regulate greenhouse gas emissions. Thus, there currently is no regulation in place with respect to greenhouse gas emissions from existing electric generating units and states are not expected to take further action to develop and submit plans at this time. In October 2021 the United States Supreme Court agreed to hear a challenge to the already vacated ACE rule. In June 2022 the United States Supreme Court held that the EPA could not use generation shifting as the best system of emission reduction under Section 111(d) of the Clean Air Act. The EPA does still have the authority to regulate greenhouse gas emissions, but those emissions reductions must be technology based. The EPA has announced its intent to propose a rule for existing power plants pursuant to the Clean Air Act by March 2023. The ultimate impact of the United States Supreme Court's decision cannot be determined at this time.
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In April 2021, President Biden announced a target for the United States in connection with the United Nations’ “Paris Agreement” on climate change. The target consists of a 50-52 percent reduction in economy-wide net greenhouse gas emissions from 2005 levels by 2030. President Biden has also stated that a goal of his administration is for the electric power industry to decarbonize fully by 2035. The details surrounding implementation of these targets are not finalized, and the impacts to Entergy of any potential related legislation cannot be predicted.
Entergy continues to support national legislation that would most efficiently reduce economy-wide greenhouse gas emissions and increase planning certainty for electric utilities. By virtue of its proportionally large investment in low-emitting generation technologies, Entergy has a low overall carbon dioxide emission “intensity,” or rate of carbon dioxide emitted per megawatt-hour of electricity generated. In anticipation of the imposition of carbon dioxide emission limits on the electric industry, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included a formal program to stabilize owned power plant carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in reducing emissions below 2000 levels. In 2006, Entergy started including emissions from controllable power purchases in addition to its ownership share of generation and established a second formal voluntary program to stabilize power plant carbon dioxide emissions and emissions from controllable power purchases, cumulatively over the period, at 20% below 2000 levels through 2010. In 2011, Entergy extended this commitment through 2020, which it ultimately outperformed by approximately 8% both cumulatively and on an annual basis. In 2019, in connection with a climate scenario analysis following the recommendations of the Task Force on Climate-related Financial Disclosures describing climate-related governance, strategy, risk management, and metrics and targets, Entergy announced a 2030 carbon dioxide emission rate goal focused on a 50% reduction from Entergy’s base year - 2000. Entergy now anticipates achieving this reduction several years early. In September 2020, Entergy announced a commitment to achieve net-zero greenhouse gas emissions by 2050 inclusive of all businesses, all applicable gases, and all emission scopes. In 2022, Entergy enhanced its commitment to include an interim goal of 50% carbon-free energy generating capacity by 2030 and expanded its interim emission rate goal to include all purchased power. See “Risk Factors” in Part I Item 1A for discussion of the risks associated with achieving these climate goals. Entergy’s comprehensive, third-party verified greenhouse gas inventory and progress against its voluntary goals are published on its website.
Entergy participates in the M.J. Bradley & Associates’ Annual Benchmarking Air Emissions Report, an annual analysis of the 100 largest U.S. electric power producers. The report is available on the M.J. Bradley website. Entergy participates annually in the Dow Jones Sustainability Index and in 2022 was listed on the North American Index. Entergy has been listed on the World or North American Index, or both, for 21 consecutive years. Entergy also participated in the 2022 CDP Climate Change and CDP Water Security evaluations, receiving a ‘B’ for both responses.
Potential Legislative, Regulatory, and Judicial Developments
In addition to the specific instances described above, there are a number of legislative and regulatory initiatives that are under consideration at the federal, state, and local level. Because of the nature of Entergy’s business, the imposition of any of these initiatives could affect Entergy’s operations. Entergy continues to monitor these initiatives and activities in order to analyze their potential operational and cost implications. These initiatives include:
•reconsideration and revision of ambient air quality standards downward which could lead to additional areas of nonattainment;
•designation by the EPA and state environmental agencies of areas that are not in attainment with national ambient air quality standards;
•introduction of bills in Congress and development of regulations by the EPA proposing further limits on SO2, mercury, carbon dioxide, and other air emissions. New legislation or regulations applicable to
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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 cap and trade programs to limit carbon dioxide and other greenhouse gases;
•efforts on the local, 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 polychlorinated biphenyls (PCBs);
•efforts by certain external groups to encourage reporting and disclosure of environmental, social, and governance 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;
•the regulation of the management, disposal, and beneficial reuse of coal combustion residuals; and
•the regulation of the management and disposal and recycling of equipment associated with renewable and clean energy sources such as used solar panels, wind turbine blades, hydrogen usage, or battery storage.
Clean Water Act
The 1972 amendments to the Federal Water Pollution Control Act (known as the Clean Water Act) provide the statutory basis for the National Pollutant Discharge Elimination System permit program, section 402, and the basic structure for regulating the discharge of pollutants from point sources to waters of the United States. The Clean Water Act requires virtually all discharges of pollutants to waters of the United States to be permitted. Section 316(b) of the Clean Water Act regulates cooling water intake structures, section 401 of the Clean Water Act requires a water quality certification from the state in support of certain federal actions and approvals, and section 404 regulates the dredge and fill of waters of the United States, including jurisdictional wetlands.
Federal Jurisdiction of Waters of the United States
In June 2020 the EPA’s revised definition of waters of the United States in the Navigable Waters Protection Rule (NWPR) became effective, narrowing the scope of Clean Water Act jurisdiction, as compared to a 2015 definition which had been stayed by several federal courts. In August 2021 a federal district court vacated and remanded the NWPR for further consideration. The EPA and the U.S. Army Corps of Engineers (Corps) subsequently issued a statement that the agencies would revert to pre-2015 regulations pending a new rulemaking. In December 2022 the EPA and the Corps released a final definition of waters of the United States that replaces the NWPR with a definition that is consistent with the pre-2015 regulatory regime as interpreted by several United States Supreme Court decisions. Most notably, the exclusion for waste treatment systems is retained.
Comprehensive Environmental Response, Compensation, and Liability Act of 1980
The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), authorizes the EPA to mandate clean-up by, or to collect reimbursement of clean-up costs from, owners or operators of sites at which hazardous substances may be or have been released. Certain private parties also may use CERCLA to recover response costs. Parties that transported hazardous substances to these sites or arranged for the disposal of the substances are also deemed liable by CERCLA. CERCLA has been interpreted to impose strict, joint, and several liability on responsible parties. Many states have adopted programs similar to CERCLA. Entergy subsidiaries in the Utility and Entergy Wholesale Commodities businesses have sent waste materials to various
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disposal sites over the years, and releases have occurred at Entergy facilities including nuclear facilities that have been or will be sold to decommissioning companies. In addition, environmental laws now regulate certain of Entergy’s operating procedures and maintenance practices that historically were not subject to regulation. Some disposal sites used by Entergy subsidiaries have been the subject of governmental action under CERCLA or similar state programs, resulting in site clean-up activities. Entergy subsidiaries have participated to various degrees in accordance with their respective potential liabilities in such site clean-ups and have developed experience with clean-up costs. The affected Entergy subsidiaries have established provisions for the liabilities for such environmental clean-up and restoration activities. Details of potentially material CERCLA and similar state program liabilities are discussed in the “Other Environmental Matters” section below.
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. As of December 31, 2022, Entergy has recorded asset retirement obligations related to CCR management of $27 million.
Pursuant to the EPA Rule, Entergy operates groundwater monitoring systems surrounding its coal combustion residual landfills located at White Bluff, Independence, and Nelson. Monitoring to date has detected concentrations of certain listed constituents in the area, but has not indicated that these constituents originated at the active landfill cells. Reporting has occurred as required, and detection monitoring will continue as the rule requires. In late-2017, Entergy determined that certain in-ground wastewater treatment system recycle ponds at its White Bluff and Independence facilities require management under the new EPA regulations. Consequently, in order to move away from using the recycle ponds, White Bluff and Independence each have installed a new permanent bottom ash handling system that does not fall under the CCR rule. As of November 2020, both sites are operating the new system and no longer are sending waste to the recycle ponds. Each site has commenced closure of its two recycle ponds (four ponds total), prior to the April 11, 2021 deadline under the finalized CCR rule for unlined recycle ponds. Any potential requirements for corrective action or operational changes under the new CCR rule continue to be assessed. Notably, ongoing litigation has resulted in the EPA’s continuing review of the rule. Consequently, the nature and cost of additional corrective action requirements may depend, in part, on the outcome of the EPA’s review.
Other Environmental Matters
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas
The EPA notified Entergy that the EPA believes Entergy is a PRP concerning PCB contamination at the F.J. Doyle Salvage facility in Leonard, Texas. The facility operated as a scrap salvage business during the 1970s to the 1990s. In May 2018 the EPA investigated the site surface and sub-surface soils and, in November 2018 the EPA conducted a removal action, including disposal of PCB contaminated soils. Entergy responded to the EPA’s information requests in May and July 2019. In November 2020 the EPA sent Entergy and other PRPs a demand letter seeking reimbursement for response costs totaling $4 million expended at the site. Liability and PRP
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allocation of response costs are yet to be determined. In December 2020, Entergy responded to the demand letter, without admitting liability or waiving any rights, indicating that it would engage in good faith negotiations with the EPA with respect to the demand. An initial meeting between the EPA and the PRPs took place in June 2021. Negotiations between the PRPs and the EPA are ongoing.
Litigation
Entergy uses legal and appropriate means to contest litigation threatened or filed against it, but certain states in which Entergy operates have proven to be unusually litigious environments. Judges and juries in Louisiana, Mississippi, and Texas have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. The litigation environment in these states poses a significant business risk to Entergy.
Asbestos Litigation(Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas)
See Note 8 to the financial statements for a discussion of this litigation.
Employment and Labor-related Proceedings (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
See Note 8 to the financial statements for a discussion of these proceedings.
Human Capital
Employees
Employees are an integral part of Entergy’s commitment to serving customers. As of December 31, 2022, Entergy Texas)subsidiaries employed 11,707 people.
| | | | | |
| Utility: | |
| Entergy Arkansas | 1,227 | |
| Entergy Louisiana | 1,597 | |
| Entergy Mississippi | 716 | |
| Entergy New Orleans | 296 | |
| Entergy Texas | 648 | |
| System Energy | — | |
| Entergy Operations | 3,317 | |
| Entergy Services | 3,870 | |
| Entergy Nuclear Operations | 13 | |
| Other subsidiaries | 23 | |
| Total Entergy | 11,707 | |
Approximately 3,084 employees are represented by the International Brotherhood of Electrical Workers, the United Government Security Officers of America, and the International Union, Security, Police, and Fire Professionals of America.
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Below is the breakdown of Entergy’s employees by gender and race/ethnicity:
| | | | | | | | | | | |
| Gender (%) | 2022 | | 2021 |
| Female | 22.2 | | 21.4 |
| Male | 77.8 | | 78.6 |
| | | | | | | | | | | |
| Race/Ethnicity (%) | 2022 | | 2021 |
| White | 74.8 | | 76.4 |
| Black/African American | 17.3 | | 16.4 |
| Hispanic/Latino | 3.0 | | 2.7 |
| Asian | 2.3 | | 2.0 |
| Other | 2.6 | | 2.5 |
Entergy’s Approach to Human Resources
Entergy’s people and culture enable its success; that is why acquiring, retaining, and developing talent are important components of Entergy’s human resources strategy. Entergy focuses on accessan approach that includes, among other things, governance and oversight; safety; organizational health, including diversity, inclusion, and belonging; and talent management.
Governance and Oversight
Ensuring that workplace processes support the desired culture and strategy begins with the Board of Directors and the Office of the Chief Executive. The Talent and Compensation Committee (formerly Personnel Committee) establishes priorities and each quarter reviews strategies and results on a range of topics covering the workforce, the workplace, and the marketplace. It oversees Entergy’s incentive plan design and administers its executive compensation plans to incentivize the behaviors and outcomes that support achievement of Entergy’s corporate objectives. Annually, it reviews executive performance, development, succession plans, and talent pipeline to align a high performing executive team with Entergy’s priorities. The Talent and Compensation Committee also oversees Entergy’s performance through regular briefings on a wide variety of human resources topics including Entergy’s safety culture and performance; organizational health; and diversity, inclusion, and belonging initiatives and performance.
The Talent and Compensation Committee’s Charter was revised in 2021 to acknowledge the committee’s responsibility for overseeing and monitoring the effectiveness of Entergy’s human capital strategies, including its workforce diversity, inclusion, and organizational health and safety strategies, programs, and initiatives. In recognition of the importance that organizational health and diversity, inclusion, and belonging play in enabling Entergy to achieve its business strategies, the committee receives periodic reports on Entergy’s organization health and diversity, inclusion, and belonging programs, strategies, and performance, including briefings at each of its regular meetings. The committee also receives updates on Entergy’s performance to date on key workforce, workplace, and marketplace measures, including progress in the representation of women and underrepresented minorities, both in the total workforce and in director level and above placements, progress in key diversity, inclusion, and belonging initiatives and diverse supplier spend.
Other committees of the Board oversee other key aspects of Entergy’s culture. For example, the Audit Committee reviews reports on enterprise risks, ethics, and compliance training and performance, as well as regular reports on calls made to Entergy’s ethics line and related investigations. To maximize the sharing of information and facilitate the participation of all Board members in these discussions, the Board schedules its regular committee meetings in a manner such that all directors can attend.
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The Office of the Chief Executive, which includes the Senior Vice President and Chief Human Resources Officer, ensures annual business plans are designed to support Entergy’s talent objectives, reviews workforce-related metrics, and regularly discusses the development, succession planning, and performance of their direct reports and other company officers.
Safety
Entergy’s safety objective is: Everyone Safe. All Day. Every Day. The continuation of the COVID-19 pandemic and another historic hurricane season presented significant challenges. Entergy employees achieved a total recordable incident rate of 0.51 in 2022, compared to 0.46 in 2021, and 0.40 in 2020. The results of 2021 unfortunately included an employee fatality. Entergy has enhanced dramatically leadership efforts and field presence to further its objective of zero fatalities, which it achieved in 2022. Also in 2022, there was a significant decrease in the number of serious injuries. The recordable incident rate equals the number of recordable incidents per 100 full-time equivalents. Recordable incidents include fatalities, lost-time accidents, restricted-duty accidents, and medical attentions and is not inclusive of potential work-related COVID-19 cases.
Organizational Health, including Diversity, Inclusion and Belonging (DIB)
Entergy believes that organizational health fosters an engaged and productive culture that positions Entergy to deliver sustainable value to its stakeholders. Entergy measures its progress through an organizational health survey coordinated by an external third party. Since initially administering the survey in 2014, Entergy improved from an initial score of 49 (fourth quartile) to a score in 2020 of 72 (second quartile), in 2021 of 63 (third quartile), and in 2022 of 61 (third quartile). Although the score declined slightly in 2022 as compared to 2021, it improved from the 2014 baseline. Management uses the results of the annual survey to design and implement strategies to positively influence organizational health. Initial employee participation of 66 percent in 2014 rose to and remains at approximately 90 percent in 2019-2022.
Entergy believes that creating a culture of diversity, inclusion, and belonging drives foundational engagement. Entergy is committed to developing and retaining a workforce that reflects the rich diversity of the communities it serves. In 2019, Entergy embarked on a three-year phased approach to enhance inclusion for individuals and teams. In 2022, Entergy continued to focus its actions to engage a diverse workforce, infusing DIB into hiring policies, practices and procedures, aligning Employee Resource Group goals to DIB goals, growing its DIB Champion network, integrating DIB into Entergy’s leadership development programs, and facilitating training from the executive leadership ranks down to the capital marketsfrontline. Through these efforts, Entergy aspires to create greater understanding and at times, may face potential liquidity constraints, which could make it more difficultaccountability regarding the behaviors and outcomes that are indicative of a premier utility.
Talent Management
Entergy’s focus on talent management is organized in three areas: developing and attracting a diverse pool of talent, equipping its leaders to handle future contingencies such as natural disasters or substantial increases in gasdevelop the organization, and fuel prices. Disruptionsbuilding premier utility capability through employee performance management and succession programs. Entergy believes that developing a diverse pool of local talent equipped with the skills needed, today and in the capitalfuture, and credit markets may adversely affectreflecting the communities Entergy serves will give it a long-term competitive advantage. The focus of Entergy’s leadership development programs is to equip managers with the skills needed to effectively develop their teams and improve the leader-employee relationship. Entergy’s talent development infrastructure, which includes a combination of business function-specific and enterprise-wide learning and development programs, is designed to ensure Entergy has qualified staff with the skills, experiences, and behaviors needed to perform today and prepare for the future. Entergy strives to achieve its subsidiaries’ ability to meet liquidity needs, access capitalstrategic priorities by aligning and operateenhancing team and grow their businesses,individual performance with business objectives, effectively deploying talent through succession planning, and the cost of capital.managing workforce transitions.
Entergy’s business is capital intensive and dependent upon its ability to access capital at reasonable rates and
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Availability of SEC filings and other information on Entergy’s website
Entergy electronically files reports with the SEC, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxies, and amendments to such reports. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding registrants that file electronically with the SEC at http://www.sec.gov. Copies of the reports that Entergy files with the SEC can be obtained at the SEC’s website.
Entergy uses its website, http://www.entergy.com, as a routine channel for distribution of important information, including news releases, analyst presentations and financial information. Filings made with the SEC are posted and available without charge on Entergy’s website as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. These filings include annual and quarterly reports on Forms 10-K and 10-Q and current reports on Form 8-K (including related filings in XBRL format); proxy statements; and any amendments to those reports or statements. All such postings and filings are available on Entergy’s Investor Relations website free of charge. Entergy is providing the address to its internet site solely for the information of investors and does not intend the address to be an active link. The contents of the website are not incorporated into this report.
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other terms. At times there are also spikes
See “RISK FACTORS SUMMARY” in the pricePart I Item 1 for natural gas and other commodities that increase the liquidity requirementsa summary of the Utility operating companies and Entergy Wholesale Commodities. In addition, Entergy’s and the Utility operating companies’ liquidity needs could significantly increase inRegistrant Subsidiaries’ risk factors.
Investors should review carefully the event of a hurricane or other weather-related or unforeseen disaster similar to that experienced in Entergy’s service territory with Hurricane Katrina and Hurricane Rita in 2005, Hurricane Gustav and Hurricane Ike in 2008, and Hurricane Isaac in 2012. The occurrence of one or more contingencies, including a delay in regulatory recovery of fuel or purchased power costs or storm restoration costs, an acceleration of payments or decreased credit lines, less cash flow from operations than expected, changes in regulation or governmental policy (including tax and trade policy), or other unknown events, could cause the financing needs of Entergy and its subsidiaries to increase. In addition, accessing the debt capital markets more frequently in these situations may result in an increase in leverage. Material leverage increases could negatively affect the credit ratings of Entergyfollowing risk factors and the Utility operating companies, whichother information in turn could negatively affect accessthis Form 10-K. The risks that Entergy faces are not limited to the capital markets.
The inabilitythose in this section. There may be additional risks and uncertainties (either currently unknown or not currently believed to raise capital on favorable terms, particularly during times of high interest rates, and uncertainty or reduced liquidity in the capital markets, could negatively affect Entergy and its subsidiaries’ ability to maintain and to expand their businesses. Access to capital markets could be restricted and/or borrowing costs could be increased due to certain sources of debt and equity capital being unwilling to invest in companies that experience extreme weather events, that rely on fossil fuels or offerings to fund fossil fuel projects, or due to risks related to climate change. Events beyond Entergy’s control may create uncertaintymaterial) that could increase its costadversely affect Entergy’s financial condition, results of capital or impair its ability to access the capital markets, including the ability to draw on its bank credit facilities. Entergyoperations, and its subsidiaries are unable to predict the degree of success they will have in renewing or replacing their credit facilities as they come up for renewal. Moreover, the size, terms, and covenants of any new credit facilities may not be comparable to, and may be more restrictive than, existing facilities. If Entergy and its subsidiaries are unable to access the credit and capital markets on terms that are reasonable, they may have to delay raising capital, issue shorter-term securities and/or bear an unfavorable cost of capital, which, in turn, could impact their ability to grow their businesses, decrease earnings, significantly reduce financial flexibility and/or limit Entergy Corporation’s ability to sustain its current common stock dividend level.liquidity. See “FORWARD-LOOKING INFORMATION.”
Utility Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
A downgrade in Entergy Corporation’s or its subsidiaries’ credit ratings could negatively affect Entergy Corporation’s and its subsidiaries’ ability to access capital and/or could require Entergy Corporation or its subsidiaries to post collateral, accelerate certain payments, or repay certain indebtedness.
There are a numberThe terms and conditions of factors that rating agencies evaluate to arrive at credit ratings for each of Entergy Corporationservice, including electric and the Registrant Subsidiaries, including each Registrant’s regulatory framework, ability to recover costs and earn returns, diversification and financial strength and liquidity. If one or more rating agencies downgrade Entergy Corporation’s, anygas rates, of the Utility operating companies’, orcompanies and System Energy’s ratings, particularly below investment grade, borrowingEnergy are determined through regulatory approval proceedings that can be lengthy and subject to appeal, potentially resulting in delays in effecting rate changes, lengthy litigation, the risk of disallowance of recovery of certain costs, would increase, the potential pooland uncertainty as to ultimate results.
The Utility operating companies are regulated on a cost-of-service and rate of investorsreturn basis and funding sources would likely decrease,are subject to statutes and cash or letter of credit collateral demands may be triggered by the terms of a number of commodity contracts, leases,regulatory commission rules and other agreements.
Most of Entergy Corporation’s and its subsidiaries’ suppliers and counterparties require sufficient creditworthiness to enter into transactions. If Entergy Corporation’s or its subsidiaries’ ratings decline, particularly below investment grade, or if certain counterparties believe Entergy Corporation orprocedures. The rates that the Utility operating companies and System Energy charge reflect their capital expenditures, operations and maintenance costs, allowed rates of return, financing costs, and related costs of service. These rates significantly influence the financial condition, results of operations, and liquidity of Entergy and each of the Utility operating companies and System Energy. These rates are losing creditworthinessdetermined in regulatory proceedings and demand adequate assurance under fuel, gas,are subject to periodic regulatory review and purchased power contracts,adjustment, including adjustment upon the counterpartiesinitiative of a regulator or, in some cases, affected stakeholders. Regulators in a future rate proceeding may require postingalter the timing or amount of collateralcertain costs for which recovery is allowed or modify the current authorized rate of return. Rate refunds may also be required, subject to applicable law.
In addition, regulators have initiated and may initiate additional proceedings to investigate the prudence of costs in cashthe Utility operating companies’ and System Energy’s base rates and examine, among other things, the reasonableness or lettersprudence of credit, prepayment for fuel, gasthe companies’ operation and maintenance practices, level of expenditures (including storm costs and costs associated with capital projects), allowed rates of return and rate base, proposed resource acquisitions, and previously incurred capital expenditures that the operating companies seek to place in rates. The regulators may disallow costs subject to their jurisdiction found not to have been prudently incurred or purchased powerfound not to have been incurred in compliance with applicable tariffs, creating some risk to the ultimate recovery of those costs. Regulatory proceedings relating to rates and other matters typically involve multiple parties seeking to limit or accelerated payment, or counterparties may decline business with Entergy Corporation or its subsidiaries. At December 31, 2019,reduce rates. Traditional base rate proceedings, as opposed to formula rate plans, generally have long timelines, are primarily based on power prices athistorical costs, and may or may not be limited in scope or duration by statute. The length of these base rate proceedings can cause the Utility operating companies and System Energy to experience regulatory lag in recovering costs through rates, such that the Utility operating companies may not fully recover all costs during the rate effective period and may, therefore, earn less than their allowed returns. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with rate case proceedings. For a discussion of such appeals and related litigation for both the Utility operating companies and System Energy, see Note 2 to the financial statements.
The Utility operating companies have large customer and stakeholder bases and, as a result, could be the subject of public criticism or adverse publicity focused on issues including the operation and maintenance of their assets and infrastructure, their preparedness for major storms or other extreme weather events and/or the time Entergy had liquidity exposureit takes to restore service after such events, or the quality of $78 million undertheir service or the guarantees in place supporting Entergy Wholesale Commodities transactions and $19 millionreasonableness of posted cash collateral. In the eventcost of a decrease in Entergy Corporation’s credit rating to below investment grade, based on power prices as
Part I Item 1A &and 1B
Entergy Corporation, Utility operating companies, and System Energy
service. Criticism or adverse publicity of December 31, 2019, Entergy would have been requiredthis nature could render legislatures and other governing bodies, public service commissions and other regulatory authorities, and government officials less likely to provide approximately $30 million of additional cashview the applicable operating company in a favorable light and could potentially negatively affect legislative or letters of credit under some of the agreements. As of December 31, 2019, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $90 million for a $1 per MMBtu increase in gas prices in both the short- and long-term markets.
Recent U.S. tax legislation may materially adversely affect Entergy’s financial condition, results of operations, and cash flows.
The Tax Cuts and Jobs Act of 2017 significantly changed the U.S. Internal Revenue Code, including taxation of U.S. corporations, by, among other things, reducing the federal corporate income tax rate, limiting interest deductions, and altering the expensing of capital expenditures. The legislation and interpretive guidance from the IRS are unclear in certain respects and will require further interpretations and implementing regulations by the IRS,regulatory processes or outcomes, as well as state tax authorities,lead to increased regulatory oversight or more stringent legislative or regulatory requirements or other legislation or regulatory actions that adversely affect the Utility operating companies.
The Utility operating companies and System Energy, and the legislationenergy industry as a whole, have experienced a period of rising costs and investments and an upward trend in spending, especially with respect to infrastructure investments, which is likely to continue in the foreseeable future and could be subject to potential amendmentsresult in more frequent rate cases and technical corrections, anyrequests for, and the continuation of, cost recovery mechanisms, all of which could lessenface resistance from customers and other stakeholders especially in a rising cost environment, whether due to inflation or high fuel prices or otherwise, and/or in periods of economic decline or hardship. Significant increases in costs could increase certain impactsfinancing needs and otherwise adversely affect Entergy, the Utility operating companies, and System Energy’s business, financial position, results of the legislation.
As further described in Note 3operation, or cash flows. For information regarding rate case proceedings and formula rate plans applicable to the financial statements, as a result of amortization of accumulated deferred income taxes and payment of such amounts to customers in 2019, Entergy’s net regulatory liability for income taxes balance is $1.7 billion as of December 31, 2019. Depending on the outcome of IRS examinations or tax positions and elections that Entergy may make, Entergy and the Registrant Subsidiaries may be required to record additional charges or credits to income tax expense. Further, there may be other material effects resulting from the legislation that have not been identified.
For further information regarding the effects of the Act,Utility operating companies, see the “Income Tax Legislation” section of Management’s Financial Discussion and Analysis for Entergy. Also, Note 3 to the financial statements contains additional discussion of the effect of the Act on 2017, 2018 and 2019 results of operations and financial position, the provisions of the Act, and the uncertainties associated with accounting for the Act, and Note 2 to the financial statements discusses the regulatory proceedings that have considered the effects of the Act.statements.
Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisionsto state or federal legislation or regulation affecting electric generation, electric and natural gas transmission, distribution, and related activities could negatively impact Entergy’s,adversely affect Entergy and the Utility operating companies’, financial position, results of operations, or cash flows and System Energy’stheir utility businesses.
If legislative and regulatory structures evolve in a manner that erodes the Utility operating companies’ exclusive rights to serve their regulated customers, they could lose customers and sales and their results of operations, financial conditionposition, or cash flows could be materially affected. Additionally, technological advances in energy efficiency and liquidity.
Entergydistributed energy resources are reducing the costs of these technologies and, its subsidiaries make judgments regardingtogether with ongoing state and federal subsidies, the potential tax effectsincreasing penetration of various transactions and results of operations to estimate their obligations to taxing authorities. These tax obligations include income, franchise, real estate,these technologies could result in reduced sales and use, and employment-related taxes. These judgments include provisions for potential adverse outcomes regarding tax positions that have been taken. Entergy and its subsidiaries also estimate their ability to utilize tax benefits, including those in the form of carryforwards for which the benefits have already been reflected in the financial statements. Changes in federal, state, or local tax laws, adverse tax audit results or adverse tax rulings on positions taken by Entergy and its subsidiaries could negatively affect Entergy’s, the Utility operating companies’,companies. Such loss of sales, due to the methodology used to determine cost of service rates or otherwise, could put upward pressure on rates, possibly resulting in adverse regulatory actions to mitigate such effects on rates. Further, the failure of regulatory structures to evolve to accommodate the changing needs and System Energy’sdesires of customers with respect to the sourcing and use of electricity also could diminish sales by the operating companies. Entergy and the Utility operating companies cannot predict if or when they may be subject to changes in legislation or regulation, or the extent and timing of reductions of the cost of distributed energy resources, nor can they predict the impact of these changes on their results of operations, financial condition,position, or cash flows.
The Utility operating companies recover fuel, purchased power, and liquidity. For further information regarding Entergy’s income taxes, see Note 3 to the financial statements.
Entergy and its subsidiaries’ ability to successfully execute on their business strategies, including their ability to complete strategic transactions, is subject to significant risks, and, as a result, they may be unable to achieve some or all of the anticipated results of such strategies, which could materially affect their future prospects, results of operations and benefitsassociated costs through rate mechanisms that they anticipate from such transactions.
Entergy and its subsidiaries’ future prospects and results of operations significantly depend on their ability to successfully implement their business strategies, which are subject to business,risks of delay or disallowance in regulatory economicproceedings, and sudden or prolonged increases in fuel and purchased power costs could lead to increased customer arrearages or bad debt expenses.
The Utility operating companies recover their fuel, purchased power, and associated costs from their customers through rate mechanisms subject to periodic regulatory review and adjustment. Because regulatory review can result in the disallowance of incurred costs found not to have been prudently incurred or not reflected in rates as permitted by approved rate schedules and accounting rules, including the cost of replacement power purchased when generators experience outages or when planned outages are extended, with the possibility of refunds to ratepayers, there exists some risk to the ultimate recovery of those costs, particularly when there are substantial or sudden increases in such costs. Regulators also may initiate proceedings to investigate the continued usage or the adequacy and operation of the fuel and purchased power recovery clauses of the Utility operating companies and, therefore, there can be no assurance that existing recovery mechanisms will remain unchanged or in effect at all.
The Utility operating companies’ cash flows can be negatively affected by the time delays between when gas, power, or other riskscommodities are purchased and uncertainties, manythe ultimate recovery from customers of which are beyond their control. As a result, Entergythe costs in rates. On occasion, when the level of incurred costs for fuel and its subsidiaries may be unable to fully achieve the anticipated results of such strategies.
Part I Item 1A &and 1B
Entergy Corporation, Utility operating companies, and System Energy
Additionally, Entergy and its subsidiaries have pursued and may continue to pursue strategic transactions including merger, acquisition, divestiture, joint venture, restructuring or other strategic transactions. For example, Entergy has entered into an agreement to sell its equity interests in the subsidiary that owns the Palisades Nuclear Plant and the decommissioned Big Rock Point Nuclear Power Plant and an agreement to sell the equity interests of Indian Point 1, Indian Point 2, and Indian Point 3, in each case after each of the plants has been shut down and defueled. Also, a significant portion of Entergy’s utility business over the next several years includes the construction and /or purchase of a variety of generating units. These transactions and plans are or may become subject to regulatory approval and other material conditions or contingencies. The failure to complete these transactions or plans or any future strategic transaction successfully or on a timely basis could have an adverse effect on Entergy’s or its subsidiaries’ financial condition or results of operations and the market’s perception of Entergy’s ability to execute its strategy. Further, these transactions, and any completed or future strategic transactions, involve substantial risks, including the following:
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.
Entergy and its subsidiaries may not be successful in managing these or any other significant risks that they may encounter in acquiring or divesting a business, or engaging in other strategic transactions, which could have a material effect on their business, financial condition or results of operations.
The completion of capital projects, including the construction of power generation facilities, and other capital improvements involve substantial risks. Should such efforts be unsuccessful, the financial condition, results of operations, or liquidity of Entergy and the Utility operating companies may agree to defer recovery of a portion of that period’s fuel and purchased power costs for recovery at a later date, which could increase the near-term working capital and borrowing requirements of those companies. The Utility operating companies also may experience, and in some instances have experienced, an increase in customer bill arrearages and bad debt expenses due to, among other reasons, increases in fuel and purchased power costs, especially in periods of economic decline or hardship. For a description of fuel and purchased power recovery mechanisms and information regarding the regulatory proceedings for fuel and purchased power cost recovery, see Note 2 to the financial statements.
The Utility operating companies are subject to economic risks associated with participation in the MISO markets and the allocation of transmission upgrade costs. The operation of the Utility operating companies’ transmission system pursuant to the MISO RTO tariff and their participation in the MISO RTO’s wholesale markets may be materially affected.adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
Entergy’sOn December 19, 2013, the Utility operating companies integrated into the MISO RTO. MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their owned and controlled generating facilities into the MISO resource adequacy construct (the annual Planning Resource Auction, discussed below), as well as the day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. The Utility operating companies are subject to economic risks associated with participation in the MISO markets and resource adequacy construct. MISO tariff rules and system conditions, including transmission congestion, could affect the Utility operating companies’ ability to complete capitalsell capacity, energy, and/or ancillary services in certain regions and/or the economic value of such sales, or the cost of serving the Utility operating companies’ respective loads. MISO market rules may change or be interpreted in ways that cause additional cost and risk, including compliance risk.
The Utility operating companies participate in the MISO regional transmission planning process and are subject to risks associated with planning decisions that MISO makes in the exercise of control over the planning of the Utility operating companies’ transmission assets that are under MISO’s functional control. The Utility operating companies pay transmission rates that reflect the cost of transmission projects that the Utility operating companies do not own, which could increase cash or financing needs. Further, FERC policies and regulation addressing cost responsibility for transmission projects, including the construction of powertransmission projects to interconnect new generation facilities, or make other capital improvements,may potentially give rise to cash and financing-related risks as well as result in a timely manner and within budget is contingent upon many variables and subject to substantial risks. These variables include, but are not limited to, project management expertise, escalating costs for materials, labor, and environmental compliance, and relianceupward pressure on suppliers for timely and satisfactory performance. Delays in obtaining permits, shortages in materials and qualified labor, levels of public support or opposition, suppliers and contractors not performing as expected or required under their contracts and/or experiencing financial problems that inhibit their ability to fulfill their obligations under contracts, changes in the scope and timing of projects, poor quality initial cost estimates from contractors, the inability to raise capital on favorable terms, changes in commodity prices affecting revenue, fuel costs, or materials costs, downward changes in the economy, changes in law or regulation, including environmental compliance requirements, and other events beyond the controlretail rates of the Utility operating companies, orwhich, in turn, may result in adverse actions by the Entergy Wholesale Commodities business may occur that may materially affectUtility operating companies’ retail regulators. In addition to the schedule,cash and financing-related risks arising from the potential additional cost and performance of these projects. If these projects or other capital improvements are significantly delayed or become subjectallocation to cost overruns or cancellation, Entergy and the Utility operating companies from transmission projects of others or changes in FERC policies or regulation related to cost responsibility for transmission projects, there is a risk that the Utility operating companies’ business and financial position could incur additional costsbe harmed as a result of lost investment opportunities and termination payments, or faceother effects that flow from an increased risknumber of potential write-offcompetitive projects being approved and constructed that are interconnected with their transmission systems.
Further, the terms and conditions of the investmentMISO tariff, including provisions related to the design and implementation of wholesale markets, the allocation of transmission upgrade costs, the MISO-wide allowed base rate of return on equity, and any required MISO-related charges and credits are subject to regulation by the FERC. The operation of the Utility operating companies’ transmission system pursuant to the MISO tariff and their participation in the project. In addition,MISO wholesale markets, and the resulting costs, may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
Moreover, the resource adequacy construct provided under the MISO tariff confers certain rights and imposes certain obligations upon load-serving entities, including the Utility operating companies, could be exposed to higher costs and market volatility, which could affect cash flow and cost recovery, should their respective regulators decline to approve the construction of the project or new generation needed to meet the reliability needs of customers at the lowest reasonable cost.
Part I Item 1A &and 1B
Entergy Corporation, Utility operating companies, and System Energy
For further information regarding capital expenditure plans and other uses of capital in connection with capital projects,from the transmission systems subject to MISO’s functional control, including the potential constructiontransmission facilities of the Utility operating companies. The MISO tariff provisions governing these rights and obligations are subject to change and have recently undergone significant changes, some of which are the subject of pending litigation and/or purchase ofappeals. Due to their magnitude and the speed with which they have been implemented, these changes carry risk, including compliance risk, and may result in material additional generation supply sources withincosts being passed through to the Utility operating companies’ service territory, and ascustomers in retail rates, including but not limited to additional capacity costs incurred in the Entergy Wholesale Commodities business, see the “Capital Expenditure Plans and Other Uses of Capital” section of Management’s Financial Discussion and Analysis for Entergy and eachannual MISO Planning Resource Auction. Also, by virtue of the Registrant Subsidiaries.
Failure to attract, retain and manage an appropriately qualified workforce could negatively affect Entergy or its subsidiaries’ results of operations.
We rely on a large and changing workforce of team members, including employees, contractors and temporary staffing. Certain events, such as an aging workforce, mismatching of skill sets, failing to appropriately anticipate future workforce needs, or the unavailability of contract resources may lead toUtility operating challenges and increased costs. The challenges include lack of resources, loss of knowledge basecompanies’ participation in MISO and the time required for skill development. In this case, costs, including costs for contractorsdesign and terms of the MISO resource adequacy construct, other load-serving entities served by the Utility operating companies’ transmission assets, which are under MISO’s functional control, may be able to replace employees, productivity costscircumvent reasonable resource planning obligations and safety costs, may increase. Failure to hire and adequately train replacement employees,avoid, in whole or in part, the future availability andfull cost of contract labor may adversely affectprocuring the abilityresources reasonably needed to managereliably supply their respective loads. In particular, the design of the current MISO resource adequacy construct and operate the business, especially consideringabsence of a minimum capacity obligation in MISO create a risk of other load-serving entities engaging in “free ridership” through their strategy for participation in the workforce needs associated with nuclear generation facilitiesMISO resource adequacy construct and new skillsenergy and ancillary services markets – specifically, by using energy and ancillary services available from the Utility operating companies’ owned and controlled generating units without paying a reasonable share of the cost of the capacity required to operateprovide such energy and ancillary services. As a modernized, technology-enabled power grid. If Entergy and its subsidiariesresult, there are unablea variety of risks to successfully attract, retain and manage an appropriately qualified workforce, their results of operations, financial position and cash flows could be negatively affected.
The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business may incur substantial costs to fulfill their obligations related to environmental and other matters.
The businesses in which the Utility operating companies System Energy,and their customers, including the risk of bearing additional costs for resources needed to ensure reliable service, the risk of reduced reliability and the Entergy Wholesale Commodities business operate are subject to extensive environmental regulation by local, state,enhanced risk of outages and federal authorities. These laws and regulations affectlost sales which, because of the manner in whichmethodology for establishing cost of service rates, presents the risk of upward pressure on the Utility operating companies’ rates.
In addition, orders from each of the Utility operating companies’ respective retail regulators generally require that the Utility operating companies System Energy,make periodic filings, or generally allow the retail regulator to direct the making of such filings, setting forth the results of analysis of the costs and benefits realized from MISO membership as well as the Entergy Wholesale Commodities business conductprojected costs and benefits of continued membership in MISO and/or requesting approval of their operations and make capital expenditures.continued membership in MISO. These laws and regulations also affect howfilings have been submitted periodically by each of the Utility operating companies System Energy,as required by their respective retail regulators, and the Entergy Wholesale Commoditiesoutcome of the resulting proceedings may affect the Utility operating companies’ continued membership in MISO.
The continued impacts of the COVID-19 pandemic and responsive measures taken on Entergy’s and its Utility operating companies’ business, manage air emissions, dischargesresults of operations, and financial condition are highly uncertain and cannot be predicted.
The global 2019 novel coronavirus pandemic continues to water, wetlands impacts, solidbe an evolving situation and hazardous waste storage and disposal, cooling and service water intake, the protection of threatened and endangered species, certain migratory birds and eagles, hazardous materials transportation, and similar matters. Federal, state, and local authorities continually revise these laws and regulations, and the laws and regulations are subject to judicial interpretation and to the permitting and enforcement discretion vested in the implementing agencies. Developing and implementing plans for facility compliance with these requirements cancould lead to capital, personnel,further disruption of the general economy, impacts on the customers of Entergy’s Utility operating companies, and operationdisruption of the operations of Entergy’s subsidiaries, whether due to, among other things, the emergence or spread of new variants of COVID-19, precautionary or reactionary measures, market reactions or impacts, or supply chain constraints.
Entergy and maintenance expenditures. Violationsits Utility operating companies experienced an increase in arrearages and bad debt expense due to non-payment by customers. The arrearages due to COVID-19 have begun to decline, although management cannot predict the timing of these requirements can subjectthe completion of collections of such arrearages. While the Utility operating companies System Energy,are working with regulators to ensure ultimate recovery for those and other COVID-19 related costs, the amount, method, and timing of such recovery is subject to approval by the retail regulators.
Entergy Wholesale Commodities business to enforcement actions,and its Registrant Subsidiaries also could experience, and in some cases have experienced, among other challenges that originated during or have been exacerbated by the COVID-19 pandemic: supply chain, vendor, and contractor disruptions, including shortages or delays in the availability of key components, parts, and supplies such as electronic components and solar panels; delays in completion of capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, remediationother construction projects, maintenance, and clean-up costs, civil penalties,other operations activities, including prolonged or delayed refueling and exposure to third parties’ claims for allegedmaintenance outages; delays in regulatory proceedings; workforce availability challenges, including from COVID-19 infections, health, or property damages or for violationssafety issues; increased storm recovery costs; increased cybersecurity risks as a result of applicable permits or standards. In addition, the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business potentially are subject to liability under these laws for the costs of remediation of environmental contamination of property now or formerly owned or operated by the Utility operating companies, System Energy, and Entergy Wholesale Commodities and of property contaminated by hazardous substances they generate. The Utility operating companies are currently involved in proceedings relating to sites where hazardous substances have been released and may be subject to additional proceedings in the future. The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business have incurred and expect to incur significant costs related to environmental compliance.
Emissions of nitrogen and sulfur oxides, mercury, particulates, greenhouse gases, and other regulated air emissions from generating plants are potentially subject to increased regulation, controls and mitigation expenses. In addition, existing air regulations and programs promulgated by the EPA often are challenged legally, or are revised or withdrawn by the EPA, sometimes resulting in large-scale changes to anticipated regulatory regimes and the resulting need to shift course, both operationally and economically, depending on the nature of the changes. Risks relating to
Part I Item 1A &and 1B
Entergy Corporation, Utility operating companies, and System Energy
global climate change, initiativestelecommuting; volatility in the credit or capital markets (and any related increased cost of capital or any inability to compel greenhouse gas emission reductions,access the capital markets or draw on available credit facilities); or other adverse impacts on their ability to execute on business strategies and water availability issues are discussed below.
Entergy
Although the economy has been recovering, another economic decline could adversely impact Entergy’s and its subsidiaries may not be able to obtainthe Utility operating companies’ liquidity and cash flows, including through declining sales, reduced revenues, delays in receipts of customer payments, or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals, or if Entergy and its subsidiaries fail to obtain, maintain, or comply with any such approval, the operation of its facilities could be stopped or become subject to additional costs. For further information regarding environmental regulation and environmental matters, see the “Regulation of Entergy’s Business– Environmental Regulation” section of Part I, Item 1.
increased bad debt expense. The Utility operating companies System Energy,also may experience regulatory outcomes that require them to postpone planned investment and otherwise reduce costs due to the Entergy Wholesale Commodities business may incur substantial costsimpact of the COVID-19 pandemic on their customers, especially in an environment of higher inflation. In addition, if the COVID-19 pandemic or related to reliability standards.
Entergy’s business is subject to extensive and mandatory reliability standards. Such standards, which are established by the NERC, the SERC, and other regional enforcement entities, are approved by the FERC and frequently are reviewed, amended, and supplemented. Failure to comply with such standards could resultimpacts create additional disruptions or turmoil in the impositioncredit or financial markets, or adversely impact Entergy’s credit metrics or ratings, such developments could adversely affect its ability to access capital on favorable terms and continue to meet its liquidity needs or cause a decrease in the value of fines or civil penalties, and potential exposure to third party claims for alleged violations of such standards. The standards,its defined benefit pension trust funds, as well as the lawsits nuclear decommissioning trust funds, all of which are highly uncertain and regulations that govern them, are subject to judicial interpretation and to the enforcement discretion vested in the implementing agencies. In addition to exposure to civil penalties and fines, the Utility operating companies have incurred and expect to incur significant costs related to compliance with new and existing reliability standards, including costs associated with the Utility operating companies’ transmission system and generation assets. In addition, the retail regulators of the Utility operating companies possess the jurisdiction, and in some cases have exercised such jurisdiction, to impose standards governing the reliable operation of the Utility operating companies’ distribution systems, including penalties if these standards are not met. The changes to the reliability standards applicable to the electric power industry are ongoing, and cannot be predicted.
Entergy cannot predict the extent or duration of the ongoing COVID-19 pandemic, the impact of new or existing variants of COVID-19, the effectiveness of mitigation efforts, further governmental responsive measures, or the extent of the effects or ultimate effect thatimpacts on the reliability standards will have onglobal, national or local economy, the capital markets, or its Utility and Entergy Wholesale Commodities businesses.customers, suppliers, operations, financial condition, results of operations, or cash flows.
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather, the impact on customer bills of permitted storm cost recovery, or the inability to securitize future storm restoration costs could have material effects on Entergy and its Utility operating companies.
Entergy’s and its Utility operating companies’ results of operations, liquidity, and financial condition can be materially affected by the destructive effects of severe weather. Severe weather can also result in significant outages for the customers of the Utility operating companies and, therefore, reduced revenues for the Utility operating companies during the period of the outages. A delay or failure in recovering amounts for storm restoration costs incurred, inability to securitize future storm restoration costs, or loss of revenues as a result of severe weather could have a material effect on Entergy and those Utility operating companies affected by severe weather, including lower credit ratings and, thus, higher costs for future debt issuances. The inability to recover losses either excluded by insurance or in excess of the insurance limits that can be secured economically also could have a material effect on Entergy and its Utility operating companies. In addition, the recovery of major storm restoration costs from customers could effectively limit our ability to make planned capital or other investments due to the impact of such storm cost recovery on customer bills, especially in a rising cost environment.
In August 2021, Hurricane Ida caused extensive damage to the Entergy distribution and, to a lesser extent, transmission systems across Louisiana, resulting in storm costs of $2.5 billion. Entergy Louisiana began recovering a portion of these costs through securitization financings in 2022. In January 2023 the LPSC issued orders finding prudent the costs incurred by Entergy Louisiana in responding to Hurricane Ida and allowing Entergy Louisiana to securitize the remaining $1.491 billion in such costs. Because such orders are not yet final and non-appealable (due to the forty-five day appeal period) and, further, because the bond rating and marketing process has yet to occur, there is an element of risk, and Entergy Louisiana is unable to predict with certainty the ultimate success of its recovery initiatives or the timing of such recovery.
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
Weather, economic conditions, technological developments, and other factors may have a material impact on electricity and gas usagesales and otherwise materially affect the Utility operating companies’ results of operations.operations and system reliability.
Temperatures above normal levels in the summer tend to increase electric cooling demand and revenues, and temperatures below normal levels in the winter tend to increase electric and gas heating demand and revenues. As a corollary, mild temperatures in either season tend to decrease energy usage and resulting revenues. Higher consumption levels coupled with seasonal pricing differentials typically cause the Utility operating companies to report higher revenues in the third quarter of the fiscal year than in the other quarters. ExtremeChanging weather patterns and extreme weather conditions, including hurricanes or tropical storms, flooding events, or ice storms, the frequency or intensity of which may be exacerbated by climate change, may stress the Utility operating companies’ generation facilities and transmission and distribution systems, resulting in increased maintenance and capital costs (and potential increased financing needs), limits on their ability to meet peak customer demand, increased regulatory oversight, criticism or adverse publicity, and reduced customer satisfaction. These extreme conditions could have a material effect on the Utility operating companies’ financial condition, results of operations, and liquidity.
Entergy’s electricity sales volumes are affected by a number of factors including weather and economic conditions, trends in energy efficiency, new technologies, and self-generation alternatives, including the willingness and ability of large industrial customers to develop co-generation facilities that greatly reduce their grid demand. In addition, changes to regulatory policies, such as those that allow customers to directly access the market to procure wholesale energy or those that incentivize development and utilization of new, developing, or alternative sources of generation, could, and in some instances, have reduced sales, and other non-traditional procurements, such as virtual purchase power agreements, could, and in some instances have limited growth opportunities or reduced sales at the Utility operating companies. Some of these factors are inherently cyclical or temporary in nature, such as the weather or economic conditions, and rarely have a long-lasting effect on Entergy’s operating results. Others, such as the organic turnover of appliances and lighting and their replacement with more efficient ones and adoption of newer technologies, including smart thermostats, new building codes, distributed energy resources, energy storage, demand side management, and rooftop solar, are having a more permanent effect by reducing sales growth rates from historical norms. As a result of these emerging efficiencies and technologies, the Utility operating companies may lose customers or experience lower average use per customer in the residential and commercial classes, and continuing advances have the potential to further limit sales or sales growth in the future. The
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The Utility operating companies also may face competition from other companies offering products and services to Entergy’s customers. Electricity sales to industrial customers, in particular, benefit from steady economic growth and favorable commodity markets; however, industrial sales are sensitive to changes in conditions in the markets in which its customers operate. Negative changes in any of these or other factors, particularly sustained economic downturns or sluggishness, have the potential to result in slower sales growth or sales declines and increased bad debt expense, which could materially affect Entergy’s and the Utility operating companies’ results of operations, financial condition, and liquidity.
The effects of climate change andUtility operating companies also may not realize anticipated or expected growth in industrial sales from electrification opportunities to help such customers achieve their environmental and sustainability goals. This could occur because of changes in customers’ goals or business priorities, competition from other companies, or decisions by such customers to seek to achieve such goals through methods not offered by Entergy.
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
Nuclear Operating, Shutdown, and Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)
Certain of the Utility operating companies and System Energy are expected to consistently operate their nuclear power plants at high capacity factors in order to be successful, and lower capacity factors could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Nuclear capacity factors significantly affect the results of operations of certain Utility operating companies and System Energy. Nuclear plant operations involve substantial fixed operating costs. Consequently, there is pressure on plant owners to operate nuclear power plants at higher capacity factors, though such operations always must be consistent with safety, reliability, and nuclear regulatory requirements. For the Utility operating companies that own nuclear plants, lower nuclear plant capacity factors can increase production costs by requiring the affected companies to generate additional energy, sometimes at higher costs, from their owned or contractually controlled facilities or purchase additional energy in the spot or forward markets in order to satisfy their supply needs.
Certain of the Utility operating companies and System Energy periodically shut down their nuclear power plants to replenish fuel. Plant maintenance and upgrades are often scheduled during such refueling outages. If refueling outages last longer than anticipated or if unplanned outages arise, Entergy’s and their results of operations, financial condition, and liquidity could be materially affected.
Outages at nuclear power plants to replenish fuel require the plant to be “turned off.” Refueling outages generally are planned to occur once every 18 to 24 months. Plant maintenance and upgrades are often scheduled during such planned outages, which may extend the planned outage duration beyond that required for only refueling activities. When refueling outages last longer than anticipated or a plant experiences unplanned outages, capacity factors decrease, and maintenance costs may increase.
Certain of the Utility operating companies and System Energy face risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication). These risks could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Based upon currently planned fuel cycles, Entergy’s nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable prices through most of 2027. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners. While there are a number of possible alternate suppliers that may be accessed to mitigate any supplier performance failure, the pricing of any such alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S. Market prices for nuclear fuel have been extremely volatile from time to time in the past and may be subject to increased volatility due to the imposition of tariffs, domestic purchase requirements or limitations on importation of uranium or uranium products from foreign countries, geopolitical conditions, or shifting trade arrangements between countries. Although Entergy’s nuclear fuel contract portfolio provides a degree of hedging against market risks for several years, costs for nuclear fuel in the future cannot be predicted with certainty due to normal inherent market uncertainties, and price changes could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.
Entergy’s ability to assure nuclear fuel supply also depends upon the performance and reliability of conversion, enrichment, and fabrication services providers. These service providers are fewer in number than uranium suppliers. For conversion and enrichment services, Entergy diversifies its supply by supplier and country and may take special measures to ensure a reliable supply of enriched uranium for fabrication into nuclear fuel. For fabrication services, each plant is dependent upon the performance of the fabricator of that plant’s nuclear fuel;
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
therefore, Entergy relies upon additional monitoring, inspection, and oversight of the fabrication process to assure reliability and quality of its nuclear fuel. Certain of the suppliers and service providers are located in or dependent upon foreign countries, such as Russia, and international sanctions or tariffs impacting trade with such countries could further restrict the ability of such suppliers or service providers to continue to supply fuel or provide such services at acceptable prices or at all. The inability of such suppliers or service providers to perform such obligations intended to compel greenhouse gas emission reductionscould materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.
Certain of the Utility operating companies and System Energy face the risk that the NRC will change or modify its regulations, suspend or revoke their licenses, or increase cleanoversight of their nuclear plants, which could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Under the Atomic Energy Act and Energy Reorganization Act, the NRC regulates the operation of nuclear power plants. The NRC may modify, suspend, or renewable energy requirementsrevoke licenses, shut down a nuclear facility and impose civil penalties for failure to comply with the Atomic Energy Act, related regulations, or the terms of the licenses for nuclear facilities. Interested parties may also intervene which could result in prolonged proceedings. A change in the Atomic Energy Act, other applicable statutes, or the applicable regulations or licenses, or the NRC’s interpretation thereof, may require a substantial increase in capital expenditures or may result in increased operating or decommissioning costs and could materially affect the results of operations, liquidity, or financial condition of Entergy, certain of the Utility operating companies, or System Energy. A change in the classification of a plant owned by one of these companies under the NRC’s Reactor Oversight Process, which is the NRC’s program to placecollect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response, also could cause the owner of the plant to incur material additional costs as a price on greenhouse gas emissionsresult of the increased oversight activity and potential response costs associated with the change in classification. For additional information concerning the current classification of the plants owned by Entergy Arkansas, Entergy Louisiana, and System Energy, see “Regulation of Entergy’s Business- Regulation of the Nuclear Power Industry - NRC Reactor Oversight Process” in Part I, Item 1.
Events at nuclear plants owned by one of these companies, as well as those owned by others, may lead to a change in laws or regulations or the terms of the applicable licenses, or the NRC’s interpretation thereof, or may cause the NRC to increase oversight activity or initiate actions to modify, suspend, or revoke licenses, shut down a nuclear facility, or impose civil penalties. As a result, if an incident were to occur at any nuclear generating unit, whether an Entergy nuclear generating unit or not, it could materially affect the financial condition, results of operations, and liquidity of Entergy, certain of the Utility operating companies, or System Energy, and the Entergy Wholesale Commodities business.
In an effort to address climate change concerns, some federal, state, and local authorities are calling for additional laws and regulations aimed at known or suspected causes of climate change. For example, in response to the United States Supreme Court’s 2007 decision holding that the EPA has authority to regulate emissions of CO2 and other “greenhouse gases” under the Clean Air Act, the EPA, various environmental interest groups, and other organizations focused considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. In 2010, the EPA promulgated its first regulations controlling greenhouse gas emissions from certain vehicles and from new and significantly modified stationary sources of emissions, including electric generating units. During 2012 and 2014, the EPA proposed CO2 emission standards for new and existing sources. The EPA finalized these standards in 2015; however, in June 2019, the EPA repealed and replaced certain aspects of those regulations. As examples of state action, in the Northeast, the Regional Greenhouse Gas Initiative establishes a cap on CO2 emissions from electric power plants and requires generators to purchase emission permits to cover their CO2 emissions, and a similar program has been developed in California. The impact that continued changes in the governmental response to climate change risk will have on existing and pending environmental laws and regulations related to greenhouse gas emissions is currently unclear.
Developing and implementing plans for compliance with greenhouse gas emissions reduction or clean/renewable energy requirements can lead to additional capital, personnel, and operation and maintenance expenditures and could significantly affect the economic positionCertain of existing facilities and proposed projects. The operations of low or non-emitting generating units (such as nuclear units) at lower than expected capacity factors could require increased generation from higher emitting units, thus increasing the company’s greenhouse gas emission rate. Moreover, long-term planning to meet environmental requirements can be negatively impacted and costs may increase to the extent laws and regulations change prior to full implementation. These requirements could, in turn, lead to changes in the planning or operations of balancing authorities or organized markets in areas where the Utility operating companies and System Energy or Entergy Wholesale Commodities do business. Violationsare exposed to risks and costs related to operating and maintaining their nuclear power plants, and their failure to maintain operational efficiency at their nuclear power plants could materially affect Entergy’s and their results of such requirements may subject Entergy Wholesale Commoditiesoperations, financial condition, and liquidity.
The nuclear generating units owned by certain of the Utility operating companies to enforcement actions,and System Energy began commercial operations in the 1970s-1980s. Older equipment may require more capital expenditures to bring existing facilities into compliance, additionalkeep each of these nuclear power plants operating safely and efficiently. This equipment is also likely to require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages, or any unanticipated capital expenditures, could result in increased costs, orsome of which costs may not be fully recoverable by these Utility operating restrictions to achieve compliance, civil penalties,companies and exposure to third parties’ claims for alleged health or property damages or for violationsSystem Energy in regulatory proceedings should there be a determination of applicable permits or standards. To the extent Entergy believesimprudence. Operations at any of these costs are recoverable in rates, however, additional material rate increases for customers could be resistedthe nuclear generating units owned and operated by Entergy’s regulatorssubsidiaries could degrade to the point where the affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and in extreme cases, Entergy’s regulators might denycorrecting the causes may require significant time and expense. A decision may be made to close a unit rather than incur the expense of restarting it or defer timely recovery ofreturning the unit to full capacity. For these costs. Future changes in environmental regulation governing the emission of CO2Utility operating companies and other greenhouse gases or mix of generation sourcesSystem Energy, this could (i) result in significant additionalcertain costs to Entergy’s utility operating companies, their suppliers or customers, (ii) make some of Entergy’s electric generating units uneconomical to maintain or operate, (iii) result in the early retirement of generation facilities andbeing stranded costs if Entergy’s utility operating companies are unable to fully recover the costs and investment in generation and (iv) could increase the difficulty that Entergy and its utility operating companies have with obtaining or maintaining required environmental regulatory approvals, each of which could materially affect the financial condition, results of operations and liquidity of Entergy and its subsidiaries. In addition, lawsuits have occurred or are reasonably expected against emitters of greenhouse gases alleging that these companies are liable for personal injuries and property damage caused by climate change. These lawsuits may seek injunctive relief, monetary compensation, and punitive damages.
Part I Item 1A &and 1B
Entergy Corporation, Utility operating companies, and System Energy
and potentially not fully recoverable in regulatory proceedings. In addition, the operation and maintenance of Entergy’s nuclear facilities require the commitment of substantial human resources that can result in increased costs.
Moreover, Entergy is becoming more dependent on fewer suppliers for key parts of Entergy’s nuclear power plants that may need to the regulatorybe replaced or refurbished, and financial risks associated with climate change discussed above, potential physical risks from climate change includein some cases, parts are no longer available and have to be reverse-engineered for replacement. In addition, certain major parts have long lead-times to manufacture if an increase in sea level, windunplanned replacement is needed. This dependence on a reduced number of suppliers and storm surge damages, wildfires, wetland and barrier island erosion, risks of flooding and changes in weather conditions, (such as increases in precipitation, drought, or changes in average temperatures), and potential increased impacts of extreme weather conditions or storms. Entergy subsidiaries own assets in, and serve, communities that are at risk from sea level rise, changes in weather conditions, storms, and loss of the protection offered by coastal wetlands. A significant portion of the nation’s oil and gas infrastructure is located in these areas and susceptible to storm damage that could be aggravated by the physical impacts of climate change, which could give rise to fuel supply interruptions and price spikes. Entergy and its subsidiaries also face the risk that climate change could impact the availability and quality of water supply necessarylong lead-times on certain major parts for operations.
These and other physical changesunplanned replacements could result in changesdelays in customer demand, increased costs associated with repairingobtaining qualified replacement parts and, maintaining generation facilities and transmission and distribution systems resulting in increased maintenance and capital costs (and potential increased financing needs), limits on thetherefore, greater expense for Entergy, System’s ability to meet peak customer demand, more frequent and longer lasting outages, increased regulatory oversight, and lower customer satisfaction. Also, to the extent that climate change adversely impacts the economic health of a region or results in energy conservation or demand side management programs, it may adversely impact customer demand and revenues. Such physical or operational risks could have a material effect on Entergy’s, Entergy Wholesale Commodities’, System Energy’s, and the Utility operating companies’ financial condition, results of operations, and liquidity.
Continued and future availability and quality of water for cooling, process, and sanitary uses could materially affect the financial condition, results of operations, and liquidity of the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business.
Water is a vital natural resource that is also critical to the Utility operating companies’, System Energy’s, and Entergy Wholesale Commodities’ business operations. Entergy’s facilities use water for cooling, boiler make-up, sanitary uses, potable supply, and many other uses. Entergy’s Utility operating companies also own and/or operate hydroelectric facilities. Accordingly, water availability and quality are critical to Entergy’s business operations. Impacts to water availability or quality could negatively impact both operations and revenues.
Entergy secures water through various mechanisms (ground water wells, surface waters intakes, municipal supply, etc.) and operates under the provisions and conditions set forth by the provider and/or regulatory authorities. Entergy also obtains and operates in substantial compliance with water discharge permits issued under various provisions of the Clean Water Act and/or state water pollution control provisions. Regulations and authorizations for both water intake and use and for waste discharge can become more stringent in times of water shortages, low flows in rivers, low lake levels, low groundwater aquifer volumes, and similar conditions. The increased use of water by industry, agriculture, and the population at large, population growth, and the potential impacts of climate change on water resources may cause water use restrictions that affect Entergy and its subsidiaries.
Entergy and its subsidiaries may not be adequately hedged against changes in commodity prices, which could materially affect Entergy’s and its subsidiaries’ results of operations, financial condition, and liquidity.
To manage near-term financial exposure related to commodity price fluctuations, Entergy and its subsidiaries, including the Utility operating companies and the Entergy Wholesale Commodities business, may enter into contracts to hedge portions of their purchase and sale commitments, fuel requirements, and inventories of natural gas, uranium and its conversion and enrichment, coal, refined products, and other commodities, within established risk management guidelines. As part of this strategy, Entergy and its subsidiaries may utilize fixed- and variable-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. However, Entergy and its subsidiaries normally cover only a portion of the exposure of their assets and positions to market price volatility, and the coverage will vary over time. In addition, Entergy also elects to leave certain volumes during certain years unhedged. To the extent Entergy and its subsidiaries have unhedged positions,
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
fluctuating commodity prices can materially affect Entergy’s and its subsidiaries’ results of operations and financial position.
Although Entergy and its subsidiaries devote a considerable effort to these risk management strategies, they cannot eliminate all the risks associated with these activities. As a result of these and other factors, Entergy and its subsidiaries cannot predict with precision the impact that risk management decisions may have on their business, results of operations, or financial position.
Entergy’s over-the-counter financial derivatives are subject to rules implementing the Dodd-Frank Wall Street Reform and Consumer Protection Act that are designed to promote transparency, mitigate systemic risk and protect against market abuse. Entergy cannot predict the impact any proposed or not fully-implemented final rules will have on its ability to hedge its commodity price risk or on over-the-counter derivatives markets as a whole, but such rules and regulations could have a material effect on Entergy's risk exposure, as well as reduce market liquidity and further increase the cost of hedging activities.
Entergy has guaranteed or indemnified the performance of a portion of the obligations relating to hedging and risk management activities. Reductions in Entergy’s or its subsidiaries’ credit quality or changes in the market prices of energy commodities could increase the cash or letter of credit collateral required to be posted in connection with hedging and risk management activities, which could materially affect Entergy’s or its subsidiaries’ liquidity and financial position.
The Utility operating companies and the Entergy Wholesale Commodities business are exposed to the risk that counterparties may not meet their obligations, which may materially affect the Utility operating companies and Entergy Wholesale Commodities.
The hedging and risk management practices of the Utility operating companies, and System Energy.
The costs associated with the storage of the spent nuclear fuel of certain of the Utility operating companies and System Energy, as well as the costs of and their ability to fully decommission their nuclear power plants, could be significantly affected by the timing of the opening of a spent nuclear fuel disposal facility, as well as interim storage and transportation requirements.
Certain of the Utility operating companies and System Energy incur costs for the on-site storage of spent nuclear fuel. The approval of a license for a national repository for the disposal of spent nuclear fuel, such as the one proposed for Yucca Mountain, Nevada, or any interim storage facility, and the timing of such facility opening, will significantly affect the costs associated with on-site storage of spent nuclear fuel. For example, while the DOE is required by law to proceed with the licensing of Yucca Mountain and, after the license is granted by the NRC, to construct the repository and commence the receipt of spent fuel, the NRC licensing of the Yucca Mountain repository is effectively at a standstill. These actions are prolonging the time before spent fuel is removed from Entergy’s plant sites. Because the DOE has not accomplished its objectives, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts, and Entergy Wholesale Commodities businesshas sued the DOE for such breach. Furthermore, Entergy is uncertain as to when the DOE will commence acceptance of spent fuel from its facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at the companies’ nuclear sites and maintenance costs on existing storage facilities, including aging management of fuel storage casks, may increase. The costs of on-site storage are exposed to the risk that counterparties that owe Entergy and its subsidiaries money, energy, or other commodities will not perform their obligations. Currently, some hedging agreements contain provisions that require the counterparties to provide credit support to secure all or part of their obligations to Entergy or its subsidiaries. If the counterparties to these arrangements fail to perform, Entergy or its subsidiaries may enforce and recover the proceeds from the credit support provided and acquire alternative hedging arrangements, which credit support may not always be adequate to cover the related obligations. Inalso affected by regulatory requirements for such event, Entergy and its subsidiaries might incur losses in addition to amounts, if any, already paid to the counterparties.storage. In addition, the credit commitmentsavailability of Entergy’s lenders under its bank facilitiesa repository or other off-site storage facility for spent nuclear fuel may not be honored for a variety of reasons, including unexpected periods of financial distress affecting such lenders, which could materially affect the adequacy of its liquidity sources.
Market performanceability to fully decommission the nuclear units and other changes may decrease the value of benefit plan assets, which then could require additional funding and result in increased benefit plan costs.
The performance of the capital markets affects the values of the assets held in trust under Entergy’s pension and postretirement benefit plans. A decline in the market value of the assets may increase the funding requirementscosts relating to Entergy’s benefit plan liabilities and also result in higher benefit costs. As the value of the assets decreases, the “expected return on assets” component of benefit costs decreases, resulting in higher benefits costs. Additionally, asset losses are incorporated into benefit costs over time, thus increasing benefits costs. Volatility in the capital markets has affected the market value of these assets, which may affect Entergy’s planned levels of contributions in the future. Additionally, changes in interest rates affect the liabilities under Entergy’s pension and postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding and recognition of higher liability carrying costs. The funding requirements of the obligations related to the pension benefit plans can also increase as a result of changes in, among other factors, retirement rates, life expectancy assumptions, or Federal regulations.decommissioning. For further information regarding Entergy’s pension and other postretirement benefit plans, refer tospent fuel storage, see the “Critical Accounting Estimates – Nuclear Decommissioning Costs– Qualified Pension and Other Postretirement BenefitsSpent Fuel Disposal” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and each of its Registrant SubsidiariesSystem Energy and Note 118 to the financial statements.
Certain of the Utility operating companies and System Energy may be required to pay substantial retrospective premiums imposed under the Price-Anderson Act and/or by Nuclear Electric Insurance Limited (NEIL) in the event of a nuclear incident, and losses not covered by insurance could have a material effect on Entergy’s and their results of operations, financial condition, or liquidity.
Accidents and other unforeseen problems at nuclear power plants have occurred both in the United States and elsewhere. As required by the Price-Anderson Act, the Utility operating companies and System Energy carry the maximum available amount of primary nuclear off-site liability insurance with American Nuclear Insurers, which is $450 million for each operating site. Claims for any nuclear incident exceeding that amount are covered under Secondary Financial Protection. The Price-Anderson Act limits each reactor owner’s public liability (off-site) for a single nuclear incident to the payment of retrospective premiums into a secondary insurance pool, which is referred to as Secondary Financial Protection, up to approximately $137.6 million per reactor. With 96 reactors currently participating, this translates to a total public liability cap of approximately $13 billion per incident. The limit is subject to change to account for the effects of inflation, a change in the primary limit of insurance coverage, and changes in the number of licensed reactors. As a result, in the event of a nuclear incident that causes damages (off-site) in excess of the primary insurance coverage, each owner of a nuclear plant reactor, including Entergy’s Utility operating companies and System Energy, regardless of fault or proximity to the incident, will be required to
Part I Item 1A &and 1B
Entergy Corporation, Utility operating companies, and System Energy
The litigation environment in the states in which certain Entergy subsidiaries operate posesNEIL is a significant risk to those businesses.
Entergy andutility industry mutual insurance company, owned by its subsidiaries are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, asbestos, hazardous material and ratepayer matters, and injuries and damages issues, among other matters. The states in whichmembers, including the Utility operating companies operate, in particular Louisiana, Mississippi, and Texas, have proven to be unusually litigious environments. JudgesSystem Energy. NEIL provides onsite property and juries in these states have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. Entergy and its subsidiaries use legal and appropriate means to contest litigation threatened or filed against them, but the litigation environment in these states poses a significant business risk.
Terrorist attacks, cyber attacks, system failures or data breaches of Entergy’s and its subsidiaries’ or our suppliers’ technology systems may adversely affect Entergy’s results of operations.
Entergy and its subsidiaries operate in a business that requires evolving information technology systems that include sophisticated data collection, processing systems, software, network infrastructure and other technologies that are becoming more complex and maydecontamination coverage. All member plants could be subject to mandatoryan annual assessment (retrospective premium of up to 10 times current annual premium for all policies) should the NEIL surplus (reserve) be significantly depleted due toinsured losses. As of January 1, 2023, the maximum annual assessment amounts total approximately $70 million for the Utility plants. Retrospective premium insurance available through NEIL’s reinsurance treaty can cover the potential assessments.
As mentioned above, as an owner of nuclear power plants, Entergy participates in industry self-insurance programs and prescriptive reliabilitycould be liable to fund claims should a plant owned by a different company experience a major event. Any resulting liability from a nuclear accident may exceed the applicable primary insurance coverage and security standards. The functionalityrequire contribution of Entergy’s technology systems depends on its own and its suppliers’ and their contractors’ technology. Suppliers’ and their contractors’ technology systems to which Entergy is connected directly or indirectly support a variety of business processes and activities to store sensitive data, including (i) intellectual property, (ii) proprietary business information, (iii) personally identifiable information of customers and employees, and (iv) data with respect to invoicing andadditional funds through the collection of payments, accounting, procurement, and supply chain activities. Any significant failure or malfunction of such information technology systemsindustry-wide program that could result in loss of data or disruptions of operations.
There have been attacks and threats of attacks on energy infrastructure by cyber actors, including those associated with foreign governments. As an operator of critical infrastructure, Entergy and its subsidiaries face heightened risk of an act or threat of terrorism, cyber attacks, and data breaches, whether as a direct or indirect act against one of Entergy’s generation, transmission or distribution facilities, operations centers, infrastructure, or information technology systems used to manage, monitor, and transport power to customers and perform day-to-day business functions. An actual act couldsignificantly affect Entergy’s ability to operate, including its ability to operate the information technology systems and network infrastructure on which it relies to conduct business.
Given the rapid technological advancements of existing and emerging threats, Entergy’s technology systems remain inherently vulnerable despite implementations and enhancements of the multiple layers of security and controls. If Entergy’s or its subsidiaries’ technology systems were compromised and unable to detect or recover in a timely fashion to a normal stateresults of operations, financial condition, or liquidity of Entergy, or its subsidiaries could be unable to perform critical business functions that are essential to the company’s well-being and could result in a losscertain of its confidential, sensitive, and proprietary information, including personal information of its customers, employees, suppliers, and others in Entergy’s care. Although malware was discovered on Entergy’s business network in 2018, it was remediated on a timely basis and did not affect Entergy’s operational systems, generation plants (including nuclear), or transmission and distribution networks, nor did it have a material effect on Entergy’s business operations.
Any such attacks, failures or data breaches could have a material effect on Entergy’s and the Utility operating companies’ business, financial condition, resultscompanies, or System Energy.
The decommissioning trust fund assets for the nuclear power plants owned by certain of operations or reputation. Insurancethe Utility operating companies and System Energy may not be adequate to covermeet decommissioning obligations if market performance and other changes decrease the value of assets in the decommissioning trusts, if one or more of Entergy’s nuclear power plants is retired earlier than the anticipated shutdown date, if the plants cost more to decommission than estimated, or if current regulatory requirements change, which then could require significant additional funding.
Owners of nuclear generating plants have an obligation to decommission those plants. Certain of the Utility operating companies and System Energy maintain decommissioning trust funds for this purpose. Certain of the Utility operating companies and System Energy collect funds from their customers, which are deposited into the trusts covering the units operated for or on behalf of those companies. Those rate collections, as adjusted from time to time by rate regulators, are generally based upon operating license lives and trust fund balances as well as estimated trust fund earnings and decommissioning costs. Assets in these trust funds are subject to market fluctuations, will yield uncertain returns that may fall below projected return rates, and may result in losses resulting from the recognition of impairments of the value of certain securities held in these trust funds.
Under NRC regulations, nuclear plant owners are permitted to project the NRC-required decommissioning amount, based on an NRC formula or a site-specific estimate, and the amount that might arisewill be available in connectioneach nuclear power plant’s decommissioning trusts combined with any other decommissioning financial assurances in place. The projections are made based on the operating license expiration date and the mid-point of the subsequent decommissioning process, or the anticipated actual completion of decommissioning if a site-specific estimate is used. If the projected amount of each individual plant’s decommissioning trusts exceeds the NRC-required decommissioning amount, then its NRC license termination decommissioning obligations are considered to be funded in accordance with NRC regulations. If the projected costs do not sufficiently reflect the actual costs required to decommission these events. Such eventsnuclear power plants, or funding is otherwise inadequate, or if the formula, formula inputs, or site-specific estimate is changed to require increased funding, additional resources or commitments would be required. Furthermore, depending upon the level of funding available in the trust funds, the NRC may not permit the trust funds to be used to pay for related costs such as the management of spent nuclear fuel that are not included in the NRC’s formula. The NRC may also expose Entergy to an increased riskrequire a plan for the provision of litigation (and associated damages and fines).separate funding for spent fuel management costs.
Part I Item 1A &and 1B
Entergy Corporation, Utility operating companies, and System Energy
(Entergy New Orleans)
The effectFurther, federal or state regulatory changes, including mandated increases in decommissioning funding or changes in the methods or standards for decommissioning operations, may also increase the funding requirements of, higher purchased gas cost charges to customers taking gas service may adversely affect Entergy New Orleans’s resultsor accelerate the timing for funding of, operations and liquidity.
Gas rates charged to retail gas customers are comprised primarily of purchased gas cost charges, which provide no return or profit to Entergy New Orleans, and distribution charges, which provide a return or profitthe obligations related to the utility. Distribution charges recover fixed costs on a volumetric basis and, thus, are affected bydecommissioning of the amount of gas sold to customers. When purchased gas cost charges increase due to higher gas procurement costs, customer usage may decrease, especially in weaker economic times, resulting in lower distribution charges for Entergy New Orleans, which could adversely affect results of operations. Purchased gas cost charges, which comprise most of a customer’s bill and may be adjusted monthly, represent gas commodity costs that Entergy New Orleans recovers from its customers. Entergy New Orleans’s cash flows can be affected by differences between the time period when gas is purchased and the time when ultimate recovery from customers occurs.
(System Energy)
System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on affiliated companies for allplant owned by certain of its revenues.
System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf. Charges under the Unit Power Sales Agreement are paid by the Utility operating companies as considerationor System Energy or may restrict the decommissioning-related costs that can be paid from the decommissioning trusts. Such changes also could result in the need for their respective entitlementsadditional contributions to receive capacitydecommissioning trusts, or the posting of parent guarantees, letters of credit, or other surety mechanisms. As a result, under any of these circumstances, the results of operations, liquidity, and energy. The useful economic life of Grand Gulf is finite and is limited by the terms of its operating license, which expires in November 2044. System Energy’s financial condition depends both on the receipt of payments fromEntergy, certain of the Utility operating companies, underor System Energy could be materially affected.
An early plant shutdown (either generally or relative to current expectations), poor investment results, or higher than anticipated decommissioning costs (including as a result of changing regulatory requirements) could cause trust fund assets to be insufficient to meet the Unit Power Sales Agreement and ondecommissioning obligations, with the continued commercial operationresult that certain of Grand Gulf. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC, including a challengeUtility operating companies or System Energy may be required to provide significant additional funds or credit support to satisfy regulatory requirements for decommissioning, which, with respect to System Energy’s authorized return on equity and capital structure and a request in separate proceeding for FERC to initiate a broader investigation of rates under the Unit Power Sales Agreement. See Note 2 to the financial statements for further discussion of the proceedings. Thethese Utility operating companies have agreed to implement certain protocols for providing retail regulators withor System Energy, may not be recoverable from customers in a timely fashion or at all.
For further information regarding rates billed undernuclear decommissioning costs, management’s decision to exit the Unit Power Sales Agreement.
For information regarding the Unit Power Sales Agreement, the sale and leaseback transactions and certain other agreements relating to the Entergy System companies’ support of System Energy, see Notes 8 and 10 to the financial statementsmerchant power business, and the impairment charges that resulted from such decision, see the “UtilityCritical Accounting Estimates - System Energy and Related AgreementsNuclear Decommissioning Costs” section of Part I, Item 1.
(Entergy Corporation)
As a holding company, Entergy Corporation depends on cash distributions from its subsidiaries to meet its debt service and other financial obligations and to pay dividends on its common stock.
Entergy Corporation is a holding company with no material revenue generating operations of its own or material assets other than the stock of its subsidiaries. Accordingly, all of its operations are conducted by its subsidiaries. Entergy Corporation’s ability to satisfy its financial obligations, including the payment of interest and principal on its outstanding debt, and to pay dividends on its common stock depends on the payment to it of dividends or distributions by its subsidiaries. The subsidiaries of Entergy Corporation are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any dividends or make distributions to Entergy Corporation. The ability of such subsidiaries to make payments of dividends or distributions to Entergy Corporation depends on their results of operations and cash flows and other items affecting retained earnings, and on any applicable legal, regulatory, or contractual limitations on subsidiaries’ ability to pay such dividends or distributions. Prior to providing funds to Entergy Corporation, such subsidiaries have financial and regulatory obligations that must be satisfied, including among others, debt service and, in the case of Entergy Utility Holding Company and Entergy Texas, dividends and distributions on preferred securities. Any distributions from the Registrant Subsidiaries other than Entergy Texas and System Energy
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
are paid directly to Entergy Utility Holding Company and are therefore subject to prior payment of distributions on its preferred securities.
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
2019 Compared to 2018
Net Income
Net income increased $10.3 million primarily due to higher retail electric price and lower nuclear refueling outage expenses, partially offset by lower volume/weather, higher interest expense, and higher depreciation and amortization expenses.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 2019 to 2018:
|
| | | |
| Amount |
| (In Millions) |
2018 operating revenues |
| $2,060.6 |
|
Fuel, rider, and other revenues that do not significantly affect net income | (74.9 | ) |
Return of unprotected excess accumulated deferred income taxes to customers | 241.4 |
|
Retail electric price | 66.7 |
|
Volume/weather | (34.2 | ) |
2019 operating revenues |
| $2,259.6 |
|
Entergy Arkansas’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.
The return of unprotected excess accumulated deferred income taxes to customers resulted from the return of unprotected excess accumulated deferred income taxes through a tax adjustment rider beginning in April 2018. In 2019, $126.3 million was returned to customers as compared to $367.7 million in 2018. There was no effect on net income as the reduction in operating revenues in each period was offset by a reduction in income tax expense. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act.
The retail electric price variance is primarily due to an increase in formula rate plan rates effective with the first billing cycle of January 2019, as approved by the APSC. See Note 2 to the financial statements for further discussion of the formula rate plan filing.
The volume/weather variance is primarily due to a decrease of 707 GWh, or 3%, in billed electricity usage, including the effect of less favorable weather on residential and commercial sales and a decrease in industrial usage. The decrease in industrial usage is primarily due to a decrease in small industrial sales.
Other Income Statement Variances
Nuclear refueling outage expenses decreased primarily due to the amortization of lower costs associated with the most recent outages as compared to previous outages.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Other operation and maintenance expenses decreased primarily due to:
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;
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.
|
The decrease was partially offset by:
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.
Taxes other than income taxes increased primarily due to increases in local franchise taxes and ad valorem taxes. The increase in local franchise taxes is primarily due to higher electric retail revenues. The increase in ad valorem taxes is primarily due to higher assessments and millage rates.
Depreciation and amortization expenses increased primarily due to additions to plant in service and an increase in the ANO 1 and ANO 2 asset retirement cost assets. See Note 9 to the financial statements for discussion of the increase in the asset retirement cost assets.
Interest expense increased primarily due to the issuance of $350 million of 4.20% Series mortgage bonds in March 2019 and the issuance of $250 million of 4.00% Series mortgage bonds in May 2018.
The effective income tax rates were (21.6%) for 2019 and 669.7% for 2018. The differences in the effective income tax rates versus the federal statutory rate of 21% for 2019 and 2018 were primarily due to the amortization of excess accumulated deferred income taxes. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates.
2018 Compared to 2017
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Entergy Arkansas’s Annual Report on Form 10-K for the year ended December 31, 2018 for discussion of results of operations for 2018 compared to 2017.
Income Tax Legislation
See the “Income Tax Legislation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussionEntergy, Entergy Arkansas, Entergy Louisiana, and System Energy, the “Entergy Wholesale Commodities Exit from the Merchant Power Business” section of the Tax CutsManagement’s Financial Discussion and Jobs Act, the federal income tax legislation enacted in December 2017. Note 3Analysis for Entergy Corporation and Subsidiaries, and Notes 9, 14, and 16 to the financial statements containsstatements.
New or existing safety concerns regarding operating nuclear power plants and nuclear fuel could lead to restrictions upon the operation and decommissioning of Entergy’s nuclear power plants.
New and existing concerns are being expressed in public forums about the safety of nuclear generating units and nuclear fuel. These concerns have led to, and may continue to lead to, various proposals to federal regulators and governing bodies in some localities where Entergy’s subsidiaries own nuclear generating units for legislative and regulatory changes that might lead to the shutdown of nuclear units, additional discussionrequirements or restrictions related to spent nuclear fuel on-site storage and eventual disposal, or other adverse effects on owning, operating, and decommissioning nuclear generating units. Entergy vigorously responds to these concerns and proposals. If any of the existing proposals, or any proposals that may arise in the future with respect to legislative and regulatory changes, become effective, they could have a material effect of the Act on 2017, 2018, and 2019Entergy’s results of operations and financial position, the provisions of the Act, and the uncertainties associated with accounting for the Act, and Note 2 to the financial statements discusses the regulatory proceedings that have considered the effects of the Act.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2019, 2018, and 2017 were as follows:
|
| | | | | | | | | | | |
| | 2019 | | 2018 | | 2017 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $119 |
| |
| $6,216 |
| |
| $20,509 |
|
| | | | | | |
| Net cash provided by (used in): | | | | | |
|
| Operating activities | 677,766 |
| | 211,825 |
| | 555,556 |
|
| Investing activities | (676,293 | ) | | (688,727 | ) | | (829,312 | ) |
| Financing activities | 1,927 |
| | 470,805 |
| | 259,463 |
|
| Net increase (decrease) in cash and cash equivalents | 3,400 |
| | (6,097 | ) | | (14,293 | ) |
| | | | | | |
| Cash and cash equivalents at end of period |
| $3,519 |
| |
| $119 |
| |
| $6,216 |
|
2019 Compared to 2018
Operating Activities
Net cash flow provided by operating activities increased $465.9 million in 2019 primarily due to:
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;
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.
The increase was partially offset by the timing of collection of receivables from customers and an increase of $11.8 million in pension contributions in 2019. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Investing Activities
Net cash flow used in investing activities decreased $12.4 million in 2019 primarily due to:
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.
The decrease was partially offset by an increase of $35.6 million in distribution construction expenditures primarily due to investment in the reliability and infrastructure of Entergy Arkansas’s distribution system, including increased spending on advanced metering infrastructure, and an increase of $15.6 million in storm spending.
Financing Activities
Entergy Arkansas’s cash provided by financing activities decreased $468.9 million in 2019 primarily due to:
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 decrease was partially offset by:
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.
Decreases in Entergy Arkansas’s payable to the money pool are a use of cash flow, and Entergy Arkansas’s payable to the money pool decreased by $161.1 million in 2019 compared to increasing by $16.6 million in 2018. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
See Note 5 to the financial statements for further details of long-term debt.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2018 Compared to 2017
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Entergy Arkansas’s Annual Report on Form 10-K for the year ended December 31, 2018 for discussion of operating, investing, and financing cash flow activities for 2018 compared to 2017.
Capital Structure
Entergy Arkansas’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio is primarily due to the issuance of long-term debt in 2019.
|
| | | |
| | December 31,
2019 | | December 31,
2018 |
| Debt to capital | 53.0% | | 52.0% |
| Effect of excluding the securitization bonds | —% | | (0.2%) |
| Debt to capital, excluding securitization bonds (a) | 53.0% | | 51.8% |
| Effect of subtracting cash | —% | | —% |
| Net debt to net capital, excluding securitization bonds (a) | 53.0% | | 51.8% |
| |
(a) | Calculation excludes the securitization bonds, which are non-recourse to Entergy Arkansas. |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. Entergy Arkansas uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition because the securitization bonds are non-recourse to Entergy Arkansas, as more fully described in Note 5 to the financial statements. Entergy Arkansas also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition because net debt indicates Entergy Arkansas’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Arkansas seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a distribution, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Arkansas may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as large transactions that would materially alter the capital structure if financed entirely with debt and reducing distributions, Entergy Arkansas may receive equity contributions to maintain its capital structure.
Uses of Capital
Entergy Arkansas requires capital resources for:
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.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy Arkansas’s planned construction and other capital investments.
|
| | | | | | | | | | | |
| | 2020 | | 2021 | | 2022 |
| | (In Millions) |
| Planned construction and capital investment: | | | |
| | |
|
| Generation |
| $250 |
| |
| $445 |
| |
| $595 |
|
| Transmission | 110 |
| | 50 |
| | 65 |
|
| Distribution | 190 |
| | 125 |
| | 125 |
|
| Utility Support | 185 |
| | 165 |
| | 240 |
|
| Total |
| $735 |
| |
| $785 |
| |
| $1,025 |
|
Following are the amounts of Entergy Arkansas’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
|
| | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2021-2022 | | 2023-2024 | | After 2024 | | Total |
| | (In Millions) |
| Long-term debt (a) |
| $142 |
| |
| $737 |
| |
| $877 |
| |
| $4,377 |
| |
| $6,133 |
|
| Operating leases (b) |
| $13 |
| |
| $20 |
| |
| $13 |
| |
| $12 |
| |
| $58 |
|
| Finance leases (b) |
| $3 |
| |
| $4 |
| |
| $3 |
| |
| $2 |
| |
| $12 |
|
| Purchase obligations (c) |
| $553 |
| |
| $939 |
| |
| $561 |
| |
| $4,485 |
| |
| $6,538 |
|
| |
(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. |
In addition to the contractual obligations given above, Entergy Arkansas currently expects to contribute approximately $32.5 million to its qualified pension plans and approximately $509 thousand to its other postretirement health care and life insurance plans in 2020, although 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. See “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Also in addition to the contractual obligations, Entergy Arkansas has $207.1 million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Arkansas includes specific investments, such as transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including advanced meters and related investments; resource planning, including potential generation projects; system improvements; investments in ANO 1 and 2; software and security; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital. Management provides more information on long-term debt maturities in Note 5 to the financial statements.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Arkansas pays distributions from its earnings at a percentage determined monthly.
Searcy Solar Facility
In March 2019, Entergy Arkansas announced that it 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. The purchase is contingent upon, among other things, obtaining necessary approvals from applicable federal and state regulatory and permitting agencies. The project will be constructed by a subsidiary of NextEra Energy Resources. Entergy Arkansas will purchase the facility upon mechanical completion and after the other purchase contingencies have been met. Closing is expected to occur by the end of 2021. In May 2019, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. In September 2019 other parties filed testimony largely supporting the resource acquisition but disputing Entergy Arkansas’s proposed method of cost recovery. Entergy Arkansas filed its rebuttal testimony in October 2019. In February 2020, Entergy Arkansas, the Attorney General, and the APSC general staff filed a partial settlement agreement asking the APSC to approve, based on the record in the proceeding, all issues except certain issues that are submitted to the APSC for determination.
Sources of Capital
Entergy Arkansas’s sources to meet its capital requirements include:
internally generated funds;
cash on hand;
debt or preferred membership interest issuances;
capital contributions; and
bank financing under new or existing facilities.
Entergy Arkansas may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest rates are favorable.
All debt and common and preferred membership interest issuances by Entergy Arkansas require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in Entergy Arkansas’s bond indentures and other agreements. Entergy Arkansas has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy Arkansas’s payables to the money pool were as follows as of December 31 for each of the following years.
|
| | | | | | |
| 2019 | | 2018 | | 2017 | | 2016 |
| (In Thousands) |
| $21,634 | | $182,738 | | $166,137 | | $51,232 |
See Note 4 to the financial statements for a description of the money pool.
Entergy Arkansas has a credit facility in the amount of $150 million scheduled to expire in September 2024. Entergy Arkansas also has a $20 million credit facility scheduled to expire in April 2020. The $150 million credit facility includes fronting commitments for the issuance of letters of credit against $5 million of the borrowing capacity of the facility. As of December 31, 2019, there were no cash borrowings and no letters of credit outstanding under the credit facilities. In addition, Entergy Arkansas is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2019, a $1 million letter of credit was outstanding under Entergy Arkansas’s uncommitted letter of credit facility. See Note 4 to the financial statements for further discussion of the credit facilities.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
The Entergy Arkansas nuclear fuel company variable interest entity has a credit facility in the amount of $80 million scheduled to expire in September 2021. As of December 31, 2019, $15.1 million in loans were outstanding under the Entergy Arkansas nuclear fuel company variable interest entity credit facility. See Note 4 to the financial statements for further discussion of the nuclear fuel company variable interest entity credit facility.
Entergy Arkansas obtained authorization from the FERC through November 2020 for short-term borrowings not to exceed an aggregate amount of $250 million at any time outstanding and borrowings by its nuclear fuel company variable interest entity. See Note 4 to the financial statements for further discussion of Entergy Arkansas’s short-term borrowing limits. The long-term securities issuances of Entergy Arkansas are limited to amounts authorized by the FERC. The APSC has concurrent jurisdiction over Entergy Arkansas’s first mortgage bond/secured issuances. Entergy Arkansas has obtained long-term financing authorization from the FERC that extends through November 2020. Entergy Arkansas has obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2020.
State and Local Rate Regulation and Fuel-Cost Recovery
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 includes the first netting adjustment under the current formula rate plan for the historical test year 2017, reflecting the change in formula rate plan revenues associated with actual 2017 results when compared to the allowed rate of return on equity. The filing includes a projected $73.4 millionrevenue deficiency for 2019 and a $95.6 million revenue deficiency for the 2017 historical test year, for a total revenue requirement of $169 million for this filing. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeds the constraint, the resulting increase is limited to four percent of total revenue, which originally was $65.4 million but was increased to $66.7 million based upon the APSC staff’s updated calculation of 2018 revenue. In October 2018, Entergy Arkansas and the parties to the proceeding filed joint motions to approve a partial settlement agreement as to certain factual issues and agreed to brief contested legal issues. In November 2018 the APSC held a hearing and was briefed on a certain contested legal issue. In December 2018 the APSC issued a decision related to the initial legal brief, approved the
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
partial settlement agreement and $66.7 million revenue requirement increase, as well as Entergy Arkansas’s formula rate plan, with updated rates going into effect for the first billing cycle of January 2019.
2019 Formula Rate Plan Filing
In July 2019, Entergy Arkansas filed with the APSC its 2019 formula rate plan filing to set its formula rate for the 2020 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2020 and a netting adjustment for the historical year 2018. The total proposed formula rate plan rider revenue change designed to produce a target rate of return on common equity of 9.75% is $15.3 million, which is based upon a deficiency of approximately $61.9 million for the 2020 projected year, netted with a credit of approximately $46.6 million in the 2018 historical year netting adjustment. During 2018 Entergy Arkansas experienced higher-than expected sales volume, and actual costs were lower than forecasted. These changes, coupled with a reduced income tax rate resulting from the Tax Cuts and Jobs Act, resulted in the credit for the historical year netting adjustment. In the fourth quarter 2018 Entergy Arkansas recorded a provision of $35.1 million that reflected the estimate of the historical year netting adjustment that was expected to be included in the 2019 filing. In 2019, Entergy Arkansas recorded additional provisions totaling $11.5 million to reflect the updated estimate of the historical year netting adjustment included in the 2019 filing. In October 2019 other parties in the proceeding filed their errors and objections requesting certain adjustments to Entergy Arkansas’s filing that would reduce or eliminate Entergy Arkansas’s proposed revenue change. Entergy Arkansas filed its response addressing the requested adjustments in October 2019. In its response, Entergy Arkansas accepted certain of the adjustments recommended by the General Staff of the APSC that would reduce the proposed formula rate plan rider revenue change to $14 million. Entergy Arkansas disputed the remaining adjustments proposed by the parties. In October 2019, Entergy Arkansas filed a unanimous settlement agreement with the other parties in the proceeding seeking APSC approval of a revised total formula rate plan rider revenue change of $10.1 million. In its July 2019 formula rate plan filing, Entergy Arkansas proposed to recover an $11.2 million regulatory asset, amortized over five years, associated with specific costs related to the potential construction of scrubbers at the White Bluff plant. Although Entergy Arkansas does not concede that the regulatory asset lacks merit, for purposes of reaching a settlement on the total formula rate plan rider amount, Entergy Arkansas agreed not to include the White Bluff scrubber regulatory asset cost in the 2019 formula rate plan filing or future filings. Entergy Arkansas recorded a write-off in 2019 of the $11.2 million White Bluff scrubber regulatory asset. In December 2019, the APSC approved the settlement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2020.
Internal Restructuring
In November 2017, Entergy Arkansas filed an application with the APSC seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy Arkansas to a new entity, which would ultimately be owned by an existing Entergy subsidiary holding company. In July 2018, Entergy Arkansas filed a settlement, reached by all parties in the APSC proceeding, resolving all issues. The APSC approved the settlement agreement and restructuring in August 2018. Pursuant to the settlement agreement, Entergy Arkansas will credit retail customers $39.6 million over six years, beginning in 2019. Entergy Arkansas also received the required FERC and NRC approvals.
In November 2018, Entergy Arkansas undertook a multi-step restructuring, including the following:
Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.
Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.
Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Arkansas Power, LLC, a Texas limited liability company (Entergy Arkansas Power), and Entergy Arkansas Power assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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.
Advanced Metering Infrastructure (AMI)
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 recover the undepreciated balance of its existing meters through a regulatory asset to be amortized over 15 years, as approved by the APSC.
Production Cost Allocation Rider
The APSC approved aEntergy Arkansas has in place an APSC-approved 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.
Entergy Louisiana
Formula Rate Plan
Entergy Louisiana historically sets electric base rates annually through a formula rate plan using a historic test year. The form of the formula rate plan, on a combined basis, was approved in connection with the business combination of Entergy Louisiana and Entergy Gulf States Louisiana and largely followed the formula rate plans that were approved by the LPSC in connection with the full electric base rate cases filed by those companies in February 2013. The formula rate plan was most recently extended through the test year 2022; certain modifications were made in that extension, including a decrease to the allowed return on equity, narrowing of the earnings “dead band” around the mid-point allowed return on equity, elimination of sharing above and below the earnings “dead band,” and the addition of a distribution cost recovery mechanism. The formula rate plan continues to include exceptions from the rate cap and sharing requirements for certain large capital investment projects, including acquisition or construction of generating facilities and purchase power agreements approved by the LPSC, certain transmission investments, and most recently, certain distribution investments, among other items. In the event that the electric formula rate plan is not renewed or extended or otherwise replaced, Entergy Louisiana would revert to the more traditional rate case environment with a rate case filing occurring as soon as mid-2023.
Fuel Recovery
Entergy Louisiana’s rate schedules include a fuel adjustment clause designed to recover the cost of fuel and purchased power costs. The fuel adjustment clause contains a surcharge or credit for deferred fuel expense and related carrying charges arising from the monthly reconciliation of actual fuel costs incurred with fuel cost revenues billed to customers, including carrying charges. See Note 2 to the financial statements for a discussion of proceedings related to audits of Entergy Louisiana’s fuel adjustment clause filings.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
To help stabilize electricity costs, Entergy Louisiana received approval from the LPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Louisiana historically hedged approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity was reviewed on an annual basis. In January 2018, Entergy Louisiana filed an application with the LPSC to suspend these seasonal hedging programs and implement financial hedges with terms up to five years for a portion of its natural gas exposure, which was approved in November 2018.
Entergy Louisiana’s gas rates include a purchased gas adjustment clause based on estimated gas costs 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.
Retail Rates - Gas
In accordance with the settlement of Entergy Gulf States Louisiana’s gas rate stabilization plan for the test year ended September 30, 2012, in August 2014, Entergy Gulf States Louisiana submitted for consideration a proposal for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment and relocation projects mandated by local governments. After review by the LPSC staff and inclusion of certain customer safeguards required by the LPSC staff, in December 2014, Entergy Gulf States Louisiana and the LPSC staff submitted a joint settlement for implementation of an accelerated gas pipe replacement program providing for the replacement of approximately 100 miles of pipe over the next ten years, as well as relocation of certain existing pipe resulting from local government-related infrastructure projects, and for a rider to recover the investment associated with these projects. The rider allows for recovery of approximately $65 million over ten years. The rider recovery will be adjusted on a quarterly basis to include actual investment incurred for the prior quarter and is subject to the following conditions, among others: a ten-year term; application of any earnings in excess of the upper end of the earnings band as an offset to the revenue requirement of the infrastructure rider; adherence to a specified spending plan, within plus or minus 20% annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding 10%; and an annual true-up. The joint settlement was approved by the LPSC in January 2015. Implementation of the infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2015. In April 2022 Entergy Louisiana submitted for consideration a proposal to extend the infrastructure rider to address replacement of an additional 187 miles of pipe. In December 2022 Entergy Louisiana and the LPSC staff submitted an uncontested settlement that extends the rider for an additional ten years beginning after the end of the current term of the rider in 2025. The extension is subject to the same customer safeguards and conditions as the original term of the rider. The extension allows for recovery of approximately $95 million over ten years. In February 2023, the uncontested settlement was approved by the LPSC.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Louisiana’s filings to recover storm-related costs.
Other
In March 2016 the LPSC opened two dockets to examine, on a generic basis, issues that it identified in connection with its review of Cleco Corporation’s acquisition by third party investors. The first docket is captioned “In re: Investigation of double leveraging issues for all LPSC-jurisdictional utilities,” and the second is captioned “In re: Investigation of tax structure issues for all LPSC-jurisdictional utilities.” In April 2016 the LPSC clarified that the concerns giving rise to the two dockets arose as a result of its review of the structure of the Cleco-Macquarie transaction and that the specific intent of the directives is to seek more information regarding intra-corporate debt financing of a utility’s capital structure as well as the use of investment tax credits to mitigate the tax
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obligation at the parent level of a consolidated entity. No schedule has been set for either docket, and limited discovery has occurred.
In December 2019 an LPSC commissioner issued an unopposed directive to staff to research customer-centered options for all customer classes, as well as other regulatory environments, and recommend a plan for how to ensure customers are the focus. There was no opposition to the directive from other commissioners but several remarked that the intent of the directive was not initiated to pursue retail open access. In furtherance of the directive, the LPSC issued a notice of the opening of a docket to conduct a rulemaking to research and evaluate customer-centered options for all electric customer classes as well as other regulatory environments in January 2020. To date, the LPSC staff has requested multiple rounds of comments from stakeholders and conducted one technical conference. Topics on which comments have been filed include full and limited retail access, demand response, sleeved power purchase agreements, and energy efficiency. Neither the LPSC or the LPSC staff have made recommendations or adopted any rules.
Entergy Mississippi
Formula Rate Plan
Since the conclusion in 2015 of Entergy Mississippi’s most recent base rate case, Entergy Mississippi has set electric base rates annually through a formula rate plan. Between base rate cases, Entergy Mississippi is able to adjust base rates annually, subject to certain caps, through formula rate plans that utilize forward-looking features. In addition, Entergy Mississippi is subject to an annual “look-back” evaluation. Entergy Mississippi is allowed a maximum rate increase of 4% of each test year’s retail revenue. Any increase above 4% requires a base rate case. If Entergy Mississippi’s formula rate plan were terminated without replacement, it would revert to the more traditional rate case environment or seek approval of a new formula rate plan.
In August 2012 the MPSC opened inquiries to review whether the then current formulaic methodology used to calculate the return on common equity in both Entergy Mississippi’s formula rate plan and Mississippi Power Company’s annual formula rate plan was still appropriate or could be improved to better serve the public interest. The intent of this inquiry and review was for informational purposes only; the evaluation of any recommendations for changes to the existing methodology would take place in a general rate case or in the existing formula rate plan proceeding. In March 2013 the Mississippi Public Utilities Staff filed its consultant’s report which noted the return on common equity estimation methods used by Entergy Mississippi and Mississippi Power Company are commonly used throughout the electric utility industry. The report suggested ways in which the methods used by Entergy Mississippi and Mississippi Power Company might be improved, but did not recommend specific changes in the return on common equity formulas or calculations at that time. In June 2014 the MPSC expanded the scope of the August 2012 inquiry to study the merits of adopting a uniform formula rate plan that could be applied, where possible in whole or in part, to both Entergy Mississippi and Mississippi Power Company in order to achieve greater consistency in the plans. The MPSC directed the Mississippi Public Utilities Staff to investigate and review Entergy Mississippi’s formula rate plan rider schedule and Mississippi Power Company’s Performance Evaluation Plan by considering the merits and deficiencies and possibilities for improvement of each and then to propose a uniform formula rate plan that, where possible, could be applicable to both companies. No procedural schedule has been set. In October 2014 the Mississippi Public Utilities Staff conducted a public technical conference to discuss performance benchmarking and its potential application to the electric utilities’ formula rate plans. The docket remains open.
In December 2019 the MPSC approved Entergy Mississippi’s proposed revisions to its formula rate plan to 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 as well as to allow similar cost recovery treatment for other capacity acquisitions that are approved by the MPSC. 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
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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.
Fuel Recovery
Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased power costs. The energy cost rate for each calendar year is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy costs as of the 12-month period ended September 30. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC. The energy cost recovery riders allow interim rate adjustments depending on the level of over- or under-recovery of fuel and purchased energy costs.
To help stabilize electricity costs, Entergy Mississippi received approval from the MPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Mississippi hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of recovery of Entergy Mississippi’s storm-related costs.
Entergy New Orleans
Formula Rate Plan
As part of its determination of rates in the base rate case filed by Entergy New Orleans in 2018, in November 2019, the City Council issued a resolution resolving the rate case, with rates to become effective retroactive to August 2019. The resolution allows Entergy New Orleans to implement a three-year formula rate plan, beginning with the 2019 test year as adjusted for forward-looking known and measurable changes, with the filing for the first test year to be made in 2020. As part of a settlement of Entergy New Orleans’ appeal of the Council’s decision in its 2018 base rate case, Entergy New Orleans agreed to postpone the filing of its first test year formula rate plan to 2021 and, in return, to be provided an additional test year for the three-year cycle. Accordingly, Entergy New Orleans will submit its final formula rate plan filing of the three-year cycle in April 2023 unless the formula rate plan is extended or renewed. See Note 2 to the financial statements for further discussion.
Fuel Recovery
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.
To help stabilize gas costs, Entergy New Orleans seeks approval annually from the City Council to continue implementation of its natural gas hedging program consistent with the City Council’s stated policy objectives. The program uses financial instruments to hedge exposure to volatility in the wholesale price of natural gas purchased to
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serve Entergy New Orleans gas customers. Entergy New Orleans hedges up to 25% of actual gas sales made during the winter months.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy New Orleans’s filings to recover storm-related costs.
Entergy Texas
Base Rates
The base rates of Entergy Texas are established largely in traditional base rate case proceedings. Between base rate proceedings, Entergy Texas has available rate riders to recover the revenue requirements associated with certain incremental costs. Entergy Texas is required to file full base rate case proceedings every four years and within eighteen months of utilizing its generation cost recovery rider for investments above $200 million.
Fuel Recovery
Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, that are not included 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 every three years, at a minimum. In the course of this reconciliation, the PUCT determines whether eligible fuel and fuel-related expenses and revenues are necessary and reasonable and makes a prudence finding for each of the fuel-related contracts entered into during the reconciliation period. The PUCT fuel cost proceedings are discussed in the “System Agreement Cost Equalization Proceedings” section in Note 2 to the financial statements.
At the PUCT’s April 2013 open meeting, the PUCT Commissioners discussed their view that a purchased power capacity rider was good public policy. The PUCT issued an order in May 2013 adopting the rule allowing for a purchased power capacity rider, subject to an offsetting adjustment for load growth. The rule, as adopted, also includes a process for obtaining pre-approval by the PUCT of purchased power agreements. No Texas utility, including Entergy Texas, has exercised the option to recover capacity costs under the new rider mechanism, but Entergy Texas will continue to evaluate the benefits of utilizing the rider to recover future capacity costs.
Other Cost Recovery
As discussed above, Entergy Texas has available rate riders to recover the revenue requirements associated with certain incremental costs. These riders include a transmission cost recovery factor rider mechanism for the recovery of transmission-related capital investments, a distribution cost recovery factor rider mechanism for the recovery of distribution-related capital investment, and a generation cost recovery rider mechanism for the recovery of generation-related capital investments.
In June 2009 a law was enacted in Texas containing provisions that allow Entergy Texas to take advantage of a cost recovery mechanism that permits annual filings for the recovery of reasonable and necessary expenditures for transmission infrastructure improvement and changes in wholesale transmission charges. This mechanism was previously available to other non-ERCOT Texas utility companies, but not to Entergy Texas.
In September 2011 the PUCT adopted a proposed rule implementing a distribution cost recovery factor to recover capital and capital-related costs related to distribution infrastructure. The distribution cost recovery factor permits utilities once per year to implement an increase or decrease in rates above or below amounts reflected in base rates to reflect distribution-related depreciation expense, federal income tax and other taxes, and return on
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investment. The distribution cost recovery factor rider may be changed a maximum of four times between base rate cases.
In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery rider rule, implementing legislation passed in the 2019 Texas legislative session intended to allow electric utilities to recover generation investments between base rate proceedings. The PUCT approved the final rule in July 2020.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Texas’s filings to recover storm-related costs.
Electric Industry Restructuring
In June 2009 a law was enacted in Texas that required Entergy Texas to cease all activities relating to Entergy Texas’s transition to competition. The law allows Entergy Texas to remain a part of the SERC Reliability Corporation (SERC) Region, although it does not prevent Entergy Texas from joining another power region. The law provides that proceedings to certify a power region that Entergy Texas belongs to as a qualified power region can be initiated by the PUCT, or on motion by another party, when the conditions supporting such a proceeding exist. Under the law, the PUCT may not approve a transition to competition plan for Entergy Texas until the expiration of four years from the PUCT’s certification of a qualified power region for Entergy Texas.
The law further amended already existing law that had required Entergy Texas to propose for PUCT approval a tariff to allow eligible customers the ability to contract for competitive generation. The amending language in the law provides, among other things, that: 1) the tariff shall not be implemented in a manner that harms the sustainability or competitiveness of manufacturers who choose not to participate in the tariff; 2) Entergy Texas shall “purchase competitive generation service, selected by the customer, and provide the generation at retail to the customer;” and 3) Entergy Texas shall provide and price transmission service and ancillary services under that tariff at a rate that is unbundled from its cost of service. The law directs that the PUCT may not issue an order on the tariff that is contrary to an applicable decision, rule, or policy statement of a federal regulatory agency having jurisdiction. The PUCT determined that unrecovered costs that may be recovered through the rider consist only of those costs necessary to implement and administer the competitive generation program and do not include lost revenues or embedded generation costs. The amount of customer load that may be included in the competitive generation service program is limited to 115 MW.
System Energy
Cost of Service
The rates of System Energy are established by the FERC, and the costs allowed to be charged pursuant to these rates are, in turn, passed through to the participating Utility operating companies through the Unit Power Sales Agreement, which has monthly billings that reflect the current operating costs of, and investment in, Grand Gulf. Retail regulators and other parties may seek to initiate proceedings at FERC to investigate the prudence of costs included in the rates charged under the Unit Power Sales Agreement and examine, among other things, the reasonableness or prudence of the operation and maintenance practices, level of expenditures, allowed rates of return and rate base, and previously incurred capital expenditures. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC, including a challenge with respect to System Energy’s uncertain tax positions, sale leaseback arrangement, authorized return on equity and capital structure, and a separate proceeding for a broader investigation of rates under the Unit Power Sales Agreement. In addition, certain of the Utility operating companies’ retail regulators have filed a complaint at FERC challenging the 2012 extended power uprate of Grand Gulf and the operation and management of the plant, particularly during the time period 2016 - 2020. Beginning in 2021, System Energy implemented billing protocols to provide retail regulators with
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information regarding rates billed under the Unit Power Sales Agreement. Entergy cannot predict the outcome of any of these proceedings, and an adverse outcome in any of them could have a material adverse effect on Entergy’s or System Energy’s results of operations, financial condition, or liquidity. See Note 2 to the financial statements for further discussion of the proceedings.
Franchises
Entergy Arkansas holds exclusive franchises to provide electric service in approximately 308 incorporated cities and towns in Arkansas. These franchises generally are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas, franchises are considered to be contracts and, therefore, are governed pursuant to the terms of the franchise agreement and applicable statutes.
Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 175 incorporated municipalities and in the unincorporated areas of approximately 59 parishes of Louisiana. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and in East Baton Rouge Parish. Municipal franchise agreement terms range from 25 to 60 years while parish franchise terms range from 25 to 99 years.
Entergy Mississippi has received from the MPSC certificates of public convenience and necessity to provide electric service to areas within 45 counties, including a number of municipalities, in western Mississippi. Under Mississippi statutory law, such certificates are exclusive. Entergy Mississippi may continue to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence.
Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city ordinances. These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans’s electric and gas utility properties.
Entergy Texas holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 27 counties in eastern Texas and holds non-exclusive franchises to provide electric service in approximately 70 incorporated municipalities. Entergy Texas typically obtains 25-year franchise agreements as existing agreements expire. Entergy Texas’s electric franchises expire over the period 2023-2058.
The business of System Energy is limited to wholesale power sales. It has no distribution franchises.
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Property and Other Generation Resources
Owned Generating Stations
The total capability of the generating stations owned and leased by the Utility operating companies and System Energy as of December 31, 2022 is indicated below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Owned and Leased Capability MW(a) |
| Company | | Total | | CT / CCGT (b) | | Legacy Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
| Entergy Arkansas | | 5,276 | | | 1,567 | | | 522 | | | 1,822 | | | 1,192 | | | 73 | | | 100 | |
| Entergy Louisiana | | 10,829 | | | 5,595 | | | 2,766 | | | 2,129 | | | 339 | | | — | | | — | |
| Entergy Mississippi | | 2,857 | | | 1,738 | | | 707 | | | — | | | 310 | | | — | | | 102 | |
| Entergy New Orleans | | 663 | | | 636 | | | — | | | — | | | — | | | — | | | 27 | |
| Entergy Texas | | 3,190 | | | 980 | | | 1,960 | | | — | | | 250 | | | — | | | — | |
| System Energy | | 1,260 | | | — | | | — | | | 1,260 | | | — | | | — | | | — | |
| Total | | 24,075 | | | 10,516 | | | 5,955 | | | 5,211 | | | 2,091 | | | 73 | | | 229 | |
(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.
(b)Represents Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.
Summer peak load for the Utility has averaged 21,602 MW over the previous decade.
The Utility operating companies’ load and capacity projections are reviewed periodically to assess the need and timing for additional generating capacity and interconnections. These reviews consider existing and projected demand, the availability and price of power, the location of new load, the economy, Entergy’s clean energy and other public policy goals, environmental regulations, and the age and condition of Entergy’s existing infrastructure.
The Utility operating companies’ long-term resource strategy (Portfolio Transformation Strategy) calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Over the past decade, the Portfolio Transformation Strategy has resulted in the addition of about 8,975 MW of new long-term resources and the deactivation of about 4,881 MW of legacy generation. As MISO market participants, the Utility operating companies also participate in MISO’s Day Ahead and Real Time Energy and Ancillary Services markets to economically dispatch generation and purchase energy to serve customers reliably and at the lowest reasonable cost.
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Other Generation Resources
RFP Procurements
The Utility operating companies from time to time issue requests for proposals (RFP) to procure supply-side resources from sources other than the spot market to meet the unique regional needs of the Utility operating companies. The RFPs issued by the Utility operating companies have sought resources needed to meet near-term MISO reliability requirements as well as long-term requirements through a broad range of wholesale power products, including long-term contractual products and asset acquisitions. The RFP process has resulted in selections or acquisitions, including, among other things:
•Entergy Louisiana’s construction of the 980 MW, combined-cycle, gas turbine J. Wayne Leonard Power Station (previously referred to as the St. Charles generating facility) at its existing Little Gypsy electric generating station. The facility began commercial operation in May 2019;
•Entergy Louisiana’s construction of the 994 MW, combined-cycle, gas turbine Lake Charles generating facility at its existing Nelson electric generating station site. The facility began commercial operation in March 2020;
•Entergy Texas’s construction of the 993 MW, combined-cycle, gas turbine Montgomery County Power Station at its existing Lewis Creek electric generating station. The facility began commercial operation in January 2021;
•Entergy New Orleans’s construction of the 20 MW solar photovoltaic facility, New Orleans Solar Station, located at the NASA Michoud Facility. The facility began commercial operation in December 2020;
•In December 2020, Entergy Texas selected the self-build alternative, Orange County Advanced Power Station, out of the 2020 Entergy Texas combined-cycle, gas turbine RFP. Regulatory approval was received in November 2022 and construction has commenced. The facility is expected to be in service by mid-2026;
•In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Searcy Solar facility, sited on approximately 800 acres in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the APSC in April 2020, and closed on the acquisition, through use of a tax equity partnership, in December 2021. The Searcy Solar facility was placed in service in January 2022;
•In November 2018, Entergy Mississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Sunflower Solar facility, sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and the Sunflower Solar facility began commercial operation in September 2022;
•In June 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Walnut Bend Solar facility, that will be sited on approximately 1,000 acres in Lee County, Arkansas. In July 2021 the APSC issued an order approving the acquisition of the Walnut Bend Solar facility. The counter-party notified Entergy Arkansas that it was terminating the project, though it was willing to consider an alternative for the site. Entergy Arkansas disputed the right of termination. Negotiations are ongoing, including with respect to cost and schedule and to updates arising as a result of the Inflation Reduction Act of 2022, and the updates would require additional APSC approval. At this time the project, if approved, is expected to achieve commercial operation in 2024;
•In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility, West Memphis Solar facility, that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In October 2021 the APSC issued an order approving the acquisition of the West Memphis Solar facility. The counter-party notified Entergy Arkansas that it was seeking changes to certain terms of the build-own-transfer agreement, including both cost and schedule. In January 2023, Entergy Arkansas made a supplemental filing with the APSC. Following APSC supplemental approval, full notice to proceed will be issued with closing expected to occur in 2024;
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•In November 2021, Entergy Louisiana signed an agreement for the purchase of an approximately 150 MW to-be-constructed solar photovoltaic energy facility, St. Jacques facility, that will be sited in St. James Parish near Vacherie, Louisiana. In September 2022 the LPSC voted to approve the order including the St. Jacques facility; however, project details could be adjusted pending a final St. James Parish ruling on land use permit requirements. Closing is expected to occur in 2025 dependent upon the final St. James Parish ruling; and
•In August 2022, Entergy Arkansas signed an agreement for the purchase of an approximately 250 MW to-be-constructed solar photovoltaic energy facility, Driver Solar facility, that will be sited near Osceola, Arkansas. Also in August 2022, Entergy Arkansas received necessary approvals for the Driver Solar facility, and Entergy Arkansas has issued the counter-party full notice to proceed to begin construction. The parties are evaluating the effects of certain matters related to the Inflation Reduction Act of 2022, including the viability of a tax equity partnership. Closing is expected to occur by the end of 2024.
The RFP process has also resulted in the selection, or confirmation of the economic merits of, long-term purchased power agreements (PPAs), including, among others:
•River Bend’s 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’s 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 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. In November 2019, LS Power sold and transferred the Carville Energy Center and facility to Argo Infrastructure Partners, which included the power purchase agreement;
•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 to-be-constructed solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and the PPA began in November 2020;
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•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 to-be-constructed solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the PPA began in October 2020;
•In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in the first half of 2023;
•In August 2018, Entergy Louisiana and South Alexander Development I, LLC executed a 5-year agreement for 5 MW from a solar photovoltaic electric generating facility located in Livingston Parish, Louisiana. The PPA began in December 2020 and received regulatory approval in January 2021;
•In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and achieved commercial operation in November 2022;
•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in Polk County, Texas. The PPA is expected to start when the facility reaches commercial operation in December 2023;
•In June 2021, Entergy Louisiana and Sunlight Road Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. In September 2022 the LPSC voted to approve the order including this project. The facility is expected to reach commercial operation in December 2024;
•In June 2021, Entergy Louisiana and Vacherie Solar Energy Center, LLC executed a 20-year PPA for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. In September 2022 the LPSC voted to approve the order including this project; however, project details could be adjusted pending a final St. James Parish ruling on land use permit requirements. The facility is expected to reach commercial operation in 2025;
•In November 2021, Entergy Louisiana signed a PPA for approximately 125 MW from a to-be-constructed solar photovoltaic energy facility located in Allen, Louisiana. In September 2022 the LPSC voted to approve the order including this project. The facility is expected to reach commercial operation in February 2024;
•In December 2022, Entergy Mississippi signed a PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Hinds County, Mississippi. Following execution of the agreement, Entergy Mississippi filed a petition with the MPSC requesting all necessary approvals. The facility is expected to reach commercial operation in June 2026;
•In October 2022, Entergy Mississippi signed a PPA for approximately 100 MW from a to-be-constructed solar photovoltaic energy facility located in Tallahatchie County, Mississippi. Following execution of the agreement, Entergy Mississippi filed a petition with the MPSC requesting all necessary approvals. The facility is expected to reach commercial operation as early as May 2026;
•In October 2022, Entergy Mississippi signed a PPA for approximately 170 MW from a to-be-constructed solar photovoltaic energy facility located in Washington County, Mississippi. Following execution of the agreement, Entergy Mississippi filed a petition with the MPSC requesting all necessary approvals. The facility is expected to reach commercial operation as early as May 2026;
•In October 2022, Entergy Arkansas signed a PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in St. Francis County, Arkansas. Following execution of the agreement, Entergy Arkansas filed a petition with the APSC requesting all necessary approvals. The facility is expected to reach commercial operation as early as May 2025;
•In October 2022, Entergy Arkansas signed a PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in Mississippi County, Arkansas. Following execution of the agreement, Entergy Arkansas filed a petition with the APSC requesting all necessary approvals. The facility is expected to reach commercial operation as early as May 2025; and
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•In January 2023, Entergy Texas signed a PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Walker County, Texas. The facility is expected to reach commercial operation as early as June 2026.
In March 2021, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic resources. Entergy Louisiana selected a combination of PPA and build-own-transfer resources by March 2022, some of which have been executed and are noted above and the remainder are in progress working through definitive agreements.
In July 2021, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar generation resources. Entergy Texas selected a combination of PPA and build-own-transfer resources in March 2022. One PPA was executed in January 2023 as noted above, and definitive agreements for the remaining resources are in progress.
In August 2021, Entergy Services, on behalf of Entergy Arkansas, issued an RFP for solar photovoltaic and wind resources. Entergy Arkansas selected a combination of PPA and build-own-transfer resources in February 2022, some of which have been executed and are noted above and the remainder are in progress working through definitive agreements.
In January 2022, Entergy Services, on behalf of Entergy Mississippi, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 500 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Mississippi customers.
In June 2022, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 1500 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Louisiana customers.
In April 2022, Entergy Services, on behalf of Entergy Arkansas, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 1000 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Arkansas customers.
In October 2022, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 2000 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Texas customers.
In November 2022, Entergy Services, on behalf of Entergy Mississippi, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 500 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Mississippi customers.
Other Procurements From Third Parties
The Utility operating companies have also made resource acquisitions outside of the RFP process, including Entergy Arkansas’s (Power Block 2), Entergy Louisiana’s (Power Blocks 3 and 4), and Entergy New Orleans’s (Power Block 1) March 2016 acquisitions of the 1,980 MW (summer rating), natural gas-fired, combined-cycle gas turbine Union Power Station power blocks, each rated at 495 MW (summer rating); and Entergy Mississippi’s October 2019 acquisition of the 810 MW, combined-cycle, natural gas-fired Choctaw Generating Station. The
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Utility operating companies have also entered into various limited- and long-term contracts in recent years as a result of bilateral negotiations.
The Washington Parish Energy Center is a 361 MW natural gas-fired peaking power plant approximately 60 miles north of New Orleans on a site Entergy Louisiana purchased from Calpine in 2019. In May 2018, Entergy Louisiana received LPSC approval of its certification application for this simple-cycle power plant to be developed pursuant to an agreement between Calpine and Entergy Louisiana. Calpine began construction on the plant in early 2019 and Entergy Louisiana purchased the plant upon completion in November 2020.
The Hardin County Peaking Facility, an existing 147 MW simple-cycle gas-fired peaking power plant in Kountze, Texas, previously owned by East Texas Electric Cooperative, was acquired by Entergy Texas in June 2021. The facility has been in operation since January 2010.
Power Through Programs
In December 2020, Entergy Texas filed an application with the PUCT to amend its certificate of convenience and necessity to own and operate up to 75 MW of natural gas-fired distributed generation to be installed at commercial and industrial customer premises. Under this proposal, Entergy Texas would own and operate a fleet of generators ranging from 100 kW to 10 MW that would supply a portion of Entergy Texas’s long-term resource needs and enhance the resiliency of Entergy Texas’s electric grid. This fleet of generators would also be available to customers during outages to supply backup electric service as part of a program known as “Power Through.” In its 2021 session, the Texas legislature modified the Texas Utilities Code to exempt generators under 10 megawatts from the requirement to obtain a certificate of convenience and necessity. In addition, the PUCT announced an intent to conduct a broad rulemaking related to distributed generation and recommended that utilities with pending applications addressing distributed generation withdraw them. Accordingly, Entergy Texas withdrew its application for a certificate of convenience and necessity and associated tariff from the PUCT without prejudice to refiling. Entergy Texas continues to deploy certain customer-sited distributed generators under an existing PUCT-approved tariff. In August 2022, Entergy Texas filed an application for PUCT approval of voluntary Rate Schedule Utility Owned Distributed Generation (UODG) through which it would charge host customers for back-up service from customer-sited Power Through generators. Based on the exemption enacted by the Texas legislature in 2021, Entergy Texas’s application was not required to, and did not, seek an amendment to its certificate of convenience and necessity in order to continue deploying Power Through generators. In October 2022 two intervenors filed requests for a hearing on Entergy Texas’s application. In October 2022 the PUCT staff filed a request that the proceeding be referred to the State Office of Administrative Hearings. In January 2023 the PUCT announced an intent to develop certain broadly applicable reliability metrics against which to measure distributed generation resources and directed Entergy Texas to withdraw its application. However, the PUCT did allow Entergy Texas to continue its pilot program for Power Through generators. Entergy Texas has withdrawn its application and is considering next steps.
In August 2021, Entergy Arkansas filed with the APSC an application for authority to deploy natural gas-fired distributed generation. The application was supported by a number of letters of interest from Entergy Arkansas customers. In December 2021 the APSC general staff requested briefing, which Entergy Arkansas opposed. In January 2022, Entergy Arkansas filed to support the establishment of a procedural schedule with a hearing in April 2022. Also in January 2022, the APSC granted the general staff’s request for briefing but on an expedited schedule; briefing concluded in February 2022. Based on testimony filed to date the APSC general staff, Arkansas Electric Energy Consumers, Sierra Club, and Audubon oppose Entergy Arkansas’s proposed “Power Through” offering, which has been demonstrated to be in high demand by interested customers, some of which directly have filed public comments encouraging the APSC to approve the application. A paper hearing was held in August and September 2022 with Entergy Arkansas responding to several written commissioner questions. The parties are awaiting a decision from the APSC.
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In July 2021, Entergy Louisiana filed with the LPSC an application for authority to deploy natural gas-fired distributed generation. The application was supported by a number of letters of interest from Entergy Louisiana customers. In October 2021, a procedural schedule was established with a hearing in April 2022. Staff and certain intervenors filed direct testimony in December 2021, and cross-answering testimony was filed in January 2022. Entergy Louisiana filed rebuttal testimony in February 2022. The parties reached an uncontested settlement which, among other things, recommended approval of 120 MW of natural gas fired distributed generation and an additional 30 MW of solar and battery distributed generation, for a total distributed generation program of 150 MW. Pursuant to the terms of the settlement agreement, Entergy Louisiana may seek to expand the distributed generation program following the earlier of two years after issuance of an order approving the settlement or the installation of 60 MW of distributed generation pursuant to this program. The settlement was approved by the LPSC in November 2022.
Interconnections
The Utility operating companies’ generating units are interconnected to a transmission system operating at various voltages up to 500 kV. These generating units consist of steam-turbine generators fueled by natural gas and coal, combustion-turbine generators, and reciprocating internal combustion engine generators that are fueled by natural gas, generators powered by pressurized and boiling water nuclear reactors and inverter-based resources interconnecting both solar photovoltaic systems and energy storage devices that operate in the MISO wholesale electric market. Additionally, some of the Utility operating companies also offer customer services and products that include resources interconnected to both the distribution and transmission systems that also participate in the wholesale market. Entergy’s Utility operating companies are MISO market participants and the companies’ transmission systems are interconnected with those of many neighboring utilities. MISO is an essential link in the safe, cost-effective delivery of electric power across all or parts of 15 U.S. states and the Canadian province of Manitoba. In addition, the Utility operating companies are members of SERC Reliability Corporation (SERC), the Regional Entity with delegated authority from the North American Electric Reliability Corporation (NERC) for the purpose of proposing and enforcing Bulk Electric System reliability standards within 16 central and southeastern states.
Gas Property
As of December 31, 2022, Entergy New Orleans distributed and transported natural gas for distribution within New Orleans, Louisiana, through approximately 2,600 miles of gas pipeline. As of December 31, 2022, the gas properties of Entergy Louisiana, which are located in and around Baton Rouge, Louisiana, were not material to Entergy Louisiana’s financial position.
Title
The Utility operating companies’ generating stations are generally located on properties owned in fee simple. Most of the substations and transmission and distribution lines are constructed on private property or public rights-of-way pursuant to easements, servitudes, or appropriate franchises. Some substation properties are owned in fee simple. The Utility operating companies generally have the right of eminent domain, whereby they may perfect title to, or secure easements or servitudes on, private property for their utility operations.
Substantially all of the physical properties and assets owned by Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are subject to the liens of mortgages securing bonds issued by those companies. The Lewis Creek generating station of Entergy Texas was acquired by merger with a subsidiary of Entergy Texas and is currently not subject to the lien of the Entergy Texas indenture.
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Fuel Supply
The average fuel cost per kWh for the Utility operating companies and System Energy for the years 2020-2022 were:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year | | Natural Gas | | Nuclear | | Coal | | Renewables (a) | | Purchased Power | | MISO Purchases (b) |
| 2022 | | (Cents Per kWh) |
| Entergy Arkansas | | 4.98 | | | 0.52 | | | 2.93 | | | 2.11 | | | 10.90 | | | (2.65) | |
| Entergy Louisiana | | 5.50 | | | 0.57 | | | 2.84 | | | 10.70 | | | 6.95 | | | 6.45 | |
| Entergy Mississippi | | 4.38 | | | — | | | 2.85 | | | 0.04 | | | 6.53 | | | 6.68 | |
| Entergy New Orleans (c) | | 5.10 | | | — | | | — | | | (5.16) | | | — | | | 7.21 | |
| Entergy Texas | | 5.77 | | | — | | | 2.83 | | | 6.26 | | | 5.61 | | | 6.68 | |
| System Energy | | — | | | 0.65 | | | — | | | — | | | — | | | — | |
| Utility | | 5.27 | | | 0.57 | | | 2.89 | | | 7.00 | | | 6.54 | | | 5.95 | |
| | | | | | | | | | | | |
| 2021 | | | | | | | | | | | | |
| Entergy Arkansas | | 4.11 | | | 0.56 | | | 2.43 | | | 2.85 | | | 2.53 | | | 3.87 | |
| Entergy Louisiana | | 3.77 | | | 0.56 | | | 2.62 | | | 10.87 | | | 5.52 | | | 4.04 | |
| Entergy Mississippi | | 2.71 | | | — | | | 2.53 | | | 1.22 | | | 2.70 | | | 4.16 | |
| Entergy New Orleans (c) | | 3.47 | | | — | | | — | | | (2.82) | | | — | | | 4.50 | |
| Entergy Texas | | 4.65 | | | — | | | 2.60 | | | 3.97 | | | 4.53 | | | 4.10 | |
| System Energy | | — | | | 0.55 | | | — | | | — | | | — | | | — | |
| Utility | | 3.75 | | | 0.56 | | | 2.48 | | | 9.07 | | | 4.76 | | | 4.08 | |
| | | | | | | | | | | | |
| 2020 | | | | | | | | | | | | |
| Entergy Arkansas | | 1.78 | | | 0.62 | | | 2.35 | | | 2.28 | | | 7.39 | | | 0.63 | |
| Entergy Louisiana | | 1.98 | | | 0.58 | | | 3.27 | | | 9.99 | | | 3.48 | | | 2.65 | |
| Entergy Mississippi | | 1.73 | | | — | | | 2.52 | | | 0.25 | | | 3.23 | | | 2.26 | |
| Entergy New Orleans | | 1.56 | | | — | | | — | | | 0.02 | | | — | | | 2.99 | |
| Entergy Texas | | 2.23 | | | — | | | 3.17 | | | 3.61 | | | 3.29 | | | 2.71 | |
| System Energy | | — | | | 0.39 | | | — | | | — | | | — | | | — | |
| Utility | | 1.92 | | | 0.57 | | | 2.54 | | | 8.28 | | | 3.35 | | | 2.48 | |
(a)Includes average fuel costs from both owned and purchased power resources.
(b)Includes activity from financial transmission rights. See Note 15 to the financial statements for discussion of financial transmission rights.
(c)Entergy New Orleans’s renewables include liquidated damage payments of $2.9 million in 2022 and $1 million in 2021 due to the delay of in-service dates related to purchased power agreements.
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Actual 2022 and projected 2023 sources of generation for the Utility operating companies and System Energy, including certain power purchases from affiliates under life of unit power purchase agreements, including the Unit Power Sales Agreement, are:
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| 2022 |
| | CT / CCGT (b) | | Legacy Gas | | Nuclear | | Coal | | Renewables (c) | | Purchased Power (d) | | MISO Purchases (e) |
| Entergy Arkansas | 30 | % | | 1 | % | | 50 | % | | 12 | % | | 3 | % | | — | % | | 4 | % |
| Entergy Louisiana | 44 | % | | 9 | % | | 23 | % | | 3 | % | | 2 | % | | 8 | % | | 11 | % |
| Entergy Mississippi | 59 | % | | 6 | % | | 18 | % | | 7 | % | | 1 | % | | — | % | | 9 | % |
| Entergy New Orleans | 54 | % | | 1 | % | | 35 | % | | 1 | % | | 1 | % | | 1 | % | | 7 | % |
| Entergy Texas | 31 | % | | 20 | % | | 11 | % | | 5 | % | | — | % | | 9 | % | | 24 | % |
| System Energy (a) | — | % | | — | % | | 100 | % | | — | % | | — | % | | — | % | | — | % |
| Utility | 42 | % | | 8 | % | | 27 | % | | 5 | % | | 2 | % | | 5 | % | | 11 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2023 |
| | CT / CCGT (b) | | Legacy Gas | | Nuclear | | Coal | | Renewables (c) | | Purchased Power (d) | | MISO Purchases (e) |
| Entergy Arkansas | 26 | % | | — | % | | 58 | % | | 13 | % | | 3 | % | | — | % | | — | % |
| Entergy Louisiana | 47 | % | | 5 | % | | 30 | % | | 3 | % | | 3 | % | | 12 | % | | — | % |
| Entergy Mississippi | 63 | % | | — | % | | 26 | % | | 10 | % | | 1 | % | | — | % | | — | % |
| Entergy New Orleans | 48 | % | | 1 | % | | 45 | % | | 2 | % | | 3 | % | | 1 | % | | — | % |
| Entergy Texas | 44 | % | | 31 | % | | 15 | % | | 9 | % | | — | % | | 1 | % | | — | % |
| System Energy (a) | — | % | | — | % | | 100 | % | | — | % | | — | % | | — | % | | — | % |
| Utility | 44 | % | | 6 | % | | 36 | % | | 7 | % | | 2 | % | | 5 | % | | — | % |
(a)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.
(b)Represents natural gas sourced for Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.
(c)Includes generation from both owned and purchased power resources.
(d)Excludes MISO purchases and renewables purchased through purchased power agreements.
(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 2022 is not projected for 2023.
Some of the Utility’s gas-fired plants are also capable of using fuel oil, if necessary. Although based on current economics the Utility does not expect fuel oil use in 2023, it is possible that various operational events including weather or pipeline maintenance may require the use of fuel oil.
Natural Gas
The Utility operating companies have long-term firm and short-term interruptible gas contracts for both supply and transportation. Over 50% of the Utility operating companies’ power plants maintain some level of long-term firm transportation. Short-term contracts and spot-market purchases satisfy additional gas requirements.
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Entergy Texas owns a gas storage facility and Entergy Louisiana has a firm storage service agreement that provide reliable and flexible natural gas service to certain generating stations.
Many factors, including wellhead deliverability, storage, pipeline capacity, and demand requirements of end users, influence the availability and price of natural gas supplies for power plants. Demand is primarily tied to weather conditions as well as to the prices and availability of other energy sources. Pursuant to federal and state regulations, gas supplies to power plants may be interrupted during periods of shortage. To the extent natural gas supplies are disrupted or natural gas prices significantly increase, the Utility operating companies may in some instances use alternate fuels, such as oil when available, or rely to a larger extent on coal, nuclear generation, and purchased power.
Coal
Entergy Arkansas has committed to six two- to three-year contracts that will supply approximately 85% of the total coal supply needs in 2023. These contracts are staggered in term so that not all contracts have to be renewed the same year. If needed, additional Powder River Basin (PRB) coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. Based on the high cost of alternate sources, modes of transportation, and infrastructure improvements necessary for its delivery, no alternative coal consumption is expected at Entergy Arkansas during 2023. Coal will be transported to Arkansas via an existing Union Pacific transportation agreement that is expected to provide all of Entergy Arkansas’s rail transportation requirements for 2023.
Entergy Louisiana has committed to four two- to three-year contracts that will supply approximately 90% of Nelson Unit 6 coal needs in 2023. If needed, additional PRB coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. For the same reasons as the Entergy Arkansas plants, no alternative coal consumption is expected at Nelson Unit 6 during 2023. Coal will be transported to Nelson via an existing transportation agreement that is expected to provide all of Entergy Louisiana’s rail transportation requirements for 2023.
Coal transportation delivery rates to Entergy Arkansas- and Entergy Louisiana-operated coal-fired units became constrained and were unable to fully meet supply needs and obligations beginning in August 2021. Deliveries remained constrained through 2022 with modest improvement expected later in 2023. Both Entergy Arkansas and Entergy Louisiana control enough railcars to satisfy the rail transportation requirement.
The operator of Big Cajun 2 - Unit 3, Louisiana Generating, LLC, has advised Entergy Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2023, but is also currently experiencing delivery constraints. Entergy Louisiana’s and Entergy Texas’s coal nomination requests to Big Cajun 2 - Unit 3 are made on an annual basis.
Nuclear Fuel
The nuclear fuel cycle consists of the following:
•mining and milling of uranium ore to produce a concentrate;
•conversion of the concentrate to uranium hexafluoride gas;
•enrichment of the uranium hexafluoride gas;
•fabrication of nuclear fuel assemblies for use in fueling nuclear reactors; and
•disposal of spent fuel.
The Registrant Subsidiaries that own nuclear plants, Entergy Arkansas, Entergy Louisiana, and System Energy, are responsible through a shared regulated uranium pool for contracts to acquire nuclear material to be used in fueling Entergy’s Utility nuclear units. These companies own the materials and services in this shared regulated
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uranium pool on a pro rata fractional basis determined by the nuclear generation capability of each company. Any liabilities for obligations of the pooled contracts are on a several but not joint basis. The shared regulated uranium pool maintains inventories of nuclear materials during the various stages of processing. The Registrant Subsidiaries purchase enriched uranium hexafluoride for their nuclear plant reload requirements at the average inventory cost from the shared regulated uranium pool. Entergy Operations, Inc. contracts separately for the fabrication of nuclear fuel as agent on behalf of each of the Registrant Subsidiaries that owns a nuclear plant. All contracts for the disposal of spent nuclear fuel are between the DOE and the owner of a nuclear power plant.
Based upon currently planned fuel cycles, the Utility nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable or fixed prices through most of 2027. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners, including their ability to work through supply disruptions caused by global events, such as the COVID-19 pandemic, or national events, such as political disruption. There are a number of possible supply alternatives that may be accessed to mitigate any supplier performance failure, including potentially drawing upon Entergy’s inventory intended for later generation periods depending upon its risk management strategy at that time, although the pricing of any alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. In addition, some nuclear fuel contracts are on a non-fixed price basis subject to prevailing prices at the time of delivery.
The effects of market price changes may be reduced and deferred by risk management strategies, such as negotiation of floor and ceiling amounts for long-term contracts, buying for inventory or entering into forward physical contracts at fixed prices when Entergy believes it is appropriate and useful. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S.
Entergy’s ability to assure nuclear fuel supply also depends upon the performance reliability of conversion, enrichment, and fabrication services providers. There are fewer of these providers than for uranium. For conversion and enrichment services, like uranium, Entergy diversifies its supply by supplier and country and may take special measures as needed to ensure supply of enriched uranium for the reliable fabrication of nuclear fuel. For fabrication services, each plant is dependent upon the effective performance of the fabricator of that plant’s nuclear fuel, therefore, Entergy provides additional monitoring, inspection, and oversight for the fabrication process to assure reliability and quality.
Entergy Arkansas, Entergy Louisiana, and System Energy each have made arrangements to lease nuclear fuel and related equipment and services. The lessors, which are consolidated in the financial statements of Entergy and the applicable Registrant Subsidiary, finance the acquisition and ownership of nuclear fuel through credit agreements and the issuance of notes. These credit facilities are subject to periodic renewal, and the notes are issued periodically, typically for terms between three and seven years.
Natural Gas Purchased for Resale
Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with one interstate and three intrastate pipelines. Entergy New Orleans has a “no-notice” service gas purchase contract with Symmetry Energy Solutions which guarantees Entergy New Orleans gas delivery at specific delivery points and at any volume within the minimum and maximum set forth in the contract amounts. The Symmetry Energy Solutions gas supply is transported to Entergy New Orleans pursuant to a transportation service agreement with Gulf South Pipeline Co. This service is subject to FERC-approved rates. Entergy New Orleans also makes interruptible spot market purchases.
Entergy Louisiana purchased natural gas for resale in 2022 under a firm contract from Sequent Energy Management L.P. The gas is delivered through a combination of intrastate and interstate pipelines.
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As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy Louisiana’s or Entergy New Orleans’s suppliers failed to perform their obligations to deliver gas under their supply agreements. Gulf South Pipeline Co. could curtail transportation capacity only in the event of pipeline system constraints.
Federal Regulation of the Utility
State or local regulatory authorities, as described above, regulate the retail rates of the Utility operating companies. The FERC regulates wholesale sales of electricity rates and interstate transmission of electricity, including System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. See Note 2 to the financial statements for further discussion of federal regulation proceedings.
Transmission and MISO Markets
In December 2013 the Utility operating companies integrated into the MISO RTO. Although becoming a member of MISO did not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities, MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. MISO also exercises functional control of transmission planning and congestion management and provides schedules and pricing for the commitment and dispatch of generation that is offered into MISO’s markets, as well as pricing for load that bids into the markets. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their generating facilities into the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. Each Utility operating company has its own transmission pricing zone and a formula rate template (included as Attachment O to the MISO tariff) used to establish transmission rates within MISO. The terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets and the allocation of transmission upgrade costs, are subject to regulation by the FERC.
System Energy and Related Agreements
System Energy recovers costs related to its interest in Grand Gulf through rates charged to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans for capacity and energy under the Unit Power Sales Agreement (described below). In 1998 the FERC approved requests by Entergy Arkansas and Entergy Mississippi to accelerate a portion of their Grand Gulf purchased power obligations. Entergy Arkansas’s and Entergy Mississippi’s acceleration of Grand Gulf purchased power obligations ceased effective July 2001 and July 2003, respectively, as approved by the FERC. See Note 2 to the financial statements for discussion of proceedings at the FERC related to System Energy.
Unit Power Sales Agreement
The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System Energy’s ownership and leasehold interests in Grand Gulf to Entergy Arkansas (36%), Entergy Louisiana (14%), Entergy Mississippi (33%), and Entergy New Orleans (17%). Each of these companies is obligated to make payments to System Energy for its entitlement of capacity and energy on a full cost-of-service basis regardless of the quantity of energy delivered. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenue. The financial condition of System Energy depends upon the continued commercial operation of Grand Gulf and the receipt of such payments. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans generally recover payments made under the Unit Power Sales Agreement through rates charged to their customers.
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In the case of Entergy Arkansas and Entergy Louisiana, payments are also recovered through sales of electricity from their respective retained shares of Grand Gulf. Under a settlement agreement entered into with the APSC in 1985 and amended in 1988, Entergy Arkansas retains 22% of its 36% share of Grand Gulf-related costs and recovers the remaining 78% of its share in rates. In the event that Entergy Arkansas is not able to sell its retained share to third parties, it may sell such energy to its retail customers at a price equal to its avoided cost, which is currently less than Entergy Arkansas’s cost from its retained share. Entergy Arkansas has life-of-resources purchased power agreements with Entergy Louisiana and Entergy New Orleans that sell a portion of the output of Entergy Arkansas’s retained share of Grand Gulf to those companies, with the remainder of the retained share being sold to Entergy Mississippi through a separate life-of-resources purchased power agreement. In a series of LPSC orders, court decisions, and agreements from late 1985 to mid-1988, Entergy Louisiana was granted cost recovery with respect to costs associated with Entergy Louisiana’s share of capacity and energy from Grand Gulf, subject to certain terms and conditions. Entergy Louisiana retains and does not recover from retail ratepayers 18% of its 14% share of the costs of Grand Gulf capacity and energy and recovers the remaining 82% of its share in rates. Entergy Louisiana is allowed to recover through the fuel adjustment clause at 4.6 cents per kWh for the energy related to its retained portion of these costs. Alternatively, Entergy Louisiana may sell such energy to non-affiliated parties at prices above the fuel adjustment clause recovery amount, subject to the LPSC’s approval. Entergy Arkansas also has a life-of-resources purchased power agreement with Entergy Mississippi to sell a portion of the output of Entergy Arkansas’s non-retained share of Grand Gulf. Entergy Mississippi was granted cost recovery for those purchases by the MPSC through its annual unit power cost rate mechanism.
Availability Agreement
The Availability Agreement among System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans was entered into in 1974 in connection with the original financing by System Energy of Grand Gulf. The Availability Agreement provides that System Energy make available to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans all capacity and energy available from System Energy’s share of Grand Gulf.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans also agreed severally to pay System Energy monthly for the right to receive capacity and energy from Grand Gulf in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement) would at least equal System Energy’s total operating expenses for Grand Gulf (including depreciation at a specified rate and expenses incurred in a permanent shutdown of Grand Gulf) and interest charges.
The allocation percentages under the Availability Agreement are fixed as follows: Entergy Arkansas - 17.1%; Entergy Louisiana - 26.9%; Entergy Mississippi - 31.3%; and Entergy New Orleans - 24.7%. The allocation percentages under the Availability Agreement would remain in effect and would govern payments made under such agreement in the event of a shortfall of operating expense funds available to System Energy from other sources, including payments under the Unit Power Sales Agreement.
System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for all of its outstanding series of first mortgage bonds, as well as for its outstanding term loan and the pollution control revenue refunding bonds issued on its behalf. In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they were prohibited by governmental action from making payments under the Availability Agreement (for example, if the FERC reduced or disallowed such payments as constituting excessive rates), they would then make subordinated advances to System Energy in the same amounts and at the same times as the prohibited payments. System Energy would not be allowed to repay these subordinated advances so long as it remained in default under the related indebtedness or in other similar circumstances.
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Each of the assignment agreements relating to the Availability Agreement provides that Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans will make payments directly to System Energy. However, if there is an event of default, those payments must be made directly to the holders of indebtedness that are the beneficiaries of such assignment agreements. The payments must be made pro rata according to the amount of the respective obligations secured.
The obligations of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans to make payments under the Availability Agreement are subject to the receipt and continued effectiveness of all necessary regulatory approvals. Sales of capacity and energy under the Availability Agreement would require that the Availability Agreement be submitted to the FERC for approval with respect to the terms of such sale. No such filing with the FERC has been made because sales of capacity and energy from Grand Gulf are being made pursuant to the Unit Power Sales Agreement. If, for any reason, sales of capacity and energy are made in the future pursuant to the Availability Agreement, the jurisdictional portions of the Availability Agreement would be submitted to the FERC for approval.
Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement to System Energy have exceeded the amounts payable under the Availability Agreement and, therefore, 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 certain of 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 because their Availability Agreement obligations exceed their Unit Power Sales Agreement obligations.
The Availability Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, without further consent of any assignees or other creditors.
Service Companies
Entergy Services, a limited liability company wholly-owned by Entergy Corporation, provides management, administrative, accounting, legal, engineering, and other services primarily to the Utility operating companies, but also provides services to Entergy Wholesale Commodities. Entergy Operations is also wholly-owned by Entergy Corporation and provides nuclear management, operations and maintenance services under contract for ANO, River Bend, Waterford 3, and Grand Gulf, subject to the owner oversight of Entergy Arkansas, Entergy Louisiana, and System Energy, respectively. Entergy Services and Entergy Operations provide their services to the Utility operating companies and System Energy on an “at cost” basis, pursuant to cost allocation methodologies for these service agreements that were approved by the FERC.
Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas
Effective December 31, 2007, Entergy Gulf States, Inc. completed a jurisdictional separation into two vertically integrated utility companies, one operating under the sole retail jurisdiction of the PUCT, Entergy Texas, and the other operating under the sole retail jurisdiction of the LPSC, Entergy Gulf States Louisiana. Entergy Texas owns all Entergy Gulf States, Inc. distribution and transmission assets located in Texas, the gas-fired generating plants located in Texas, undivided 42.5% ownership shares of Entergy Gulf States, Inc.’s 70% ownership interest in Nelson Unit 6 and 42% ownership interest in Big Cajun 2, Unit 3, which are coal-fired generating plants located in Louisiana, and other assets and contract rights to the extent related to utility operations in Texas. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, owns all of the remaining assets that were owned by Entergy Gulf States, Inc. On a book value basis, approximately 58.1% of the Entergy Gulf States, Inc. assets were allocated to Entergy Gulf States Louisiana and approximately 41.9% were allocated to Entergy Texas.
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Entergy Texas purchases from Entergy Louisiana pursuant to a life-of-unit purchased power agreement a 42.5% share of capacity and energy from the 70% of River Bend subject to retail regulation. Entergy Texas was allocated a share of River Bend’s nuclear and environmental liabilities that is identical to the share of the plant’s output purchased by Entergy Texas under the purchased power agreement. In connection with the termination of the System Agreement effective August 31, 2016, the purchased power agreements that were put in place for certain legacy units at the time of the jurisdictional separation were also terminated at that time. See Note 2 to the financial statements for additional discussion of the purchased power agreements.
Entergy Louisiana and Entergy Gulf States Louisiana Business Combination
On October 1, 2015, the businesses formerly conducted by Entergy Louisiana (Old Entergy Louisiana) and Entergy Gulf States Louisiana (Old Entergy Gulf States Louisiana) were combined into a single public utility. In order to effect the business combination, under the Texas Business Organizations Code (TXBOC), Old Entergy Louisiana allocated substantially all of its assets to a new subsidiary, Entergy Louisiana Power, LLC, a Texas limited liability company (New Entergy Louisiana), and New Entergy Louisiana assumed the liabilities of Old Entergy Louisiana, in a transaction regarded as a merger under the TXBOC. Under the TXBOC, Old Entergy Gulf States Louisiana allocated substantially all of its assets to a new subsidiary (New Entergy Gulf States Louisiana) and New Entergy Gulf States Louisiana assumed the liabilities of Old Entergy Gulf States Louisiana, in a transaction regarded as a merger under the TXBOC. New Entergy Gulf States Louisiana then merged into New Entergy Louisiana with New Entergy Louisiana surviving the merger. Thereupon, Old Entergy Louisiana changed its name from “Entergy Louisiana, LLC” to “EL Investment Company, LLC” and New Entergy Louisiana changed its name from “Entergy Louisiana Power, LLC” to “Entergy Louisiana, LLC” (Entergy Louisiana). With the completion of the business combination, Entergy Louisiana holds substantially all of the assets, and has assumed the liabilities, of Old Entergy Louisiana and Old Entergy Gulf States Louisiana.
Entergy New Orleans Internal Restructuring
In November 2017, pursuant to the agreement in principle, Entergy New Orleans, Inc. undertook a multi-step restructuring, including the following:
•Entergy New Orleans, Inc. redeemed its outstanding preferred stock at a price of approximately $21 million, which included a call premium of approximately $819,000, plus any accumulated and unpaid dividends.
•Entergy New Orleans, Inc. converted from a Louisiana corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy New Orleans, Inc. allocated substantially all of its assets to a new subsidiary, Entergy New Orleans Power, LLC, a Texas limited liability company (Entergy New Orleans Power), and Entergy New Orleans Power assumed substantially all of the liabilities of Entergy New Orleans, Inc. in a transaction regarded as a merger under the TXBOC. Entergy New Orleans, Inc. remained in existence and held the membership interests in Entergy New Orleans Power.
•Entergy New Orleans, Inc. contributed the membership interests in Entergy New Orleans Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy New Orleans Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2017, Entergy New Orleans, Inc. changed its name to Entergy Utility Group, Inc., and Entergy New Orleans Power then changed its name to Entergy New Orleans, LLC. Entergy New Orleans, LLC holds substantially all of the assets, and has assumed substantially all of the liabilities, of Entergy New Orleans, Inc. The restructuring was accounted for as a transaction between entities under common control.
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Entergy Arkansas Internal Restructuring
In November 2018, Entergy Arkansas undertook a multi-step restructuring, including the following:
•Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.
•Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Arkansas Power, LLC, a Texas limited liability company (Entergy Arkansas Power), and Entergy Arkansas Power assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.
•Entergy Arkansas, Inc. contributed the membership interests in Entergy Arkansas Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Arkansas Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Arkansas, Inc. changed its name to Entergy Utility Property, Inc., and Entergy Arkansas Power then changed its name to Entergy Arkansas, LLC. Entergy Arkansas, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Arkansas, Inc. The transaction was accounted for as a transaction between entities under common control.
Entergy Mississippi Internal Restructuring
In November 2018, Entergy Mississippi undertook a multi-step restructuring, including the following:
•Entergy Mississippi, Inc. redeemed its outstanding preferred stock, at the aggregate redemption price of approximately $21.2 million.
•Entergy Mississippi, Inc. converted from a Mississippi corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Mississippi, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Mississippi Power and Light, LLC, a Texas limited liability company (Entergy Mississippi Power and Light), and Entergy Mississippi Power and Light assumed substantially all of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Mississippi, Inc. remained in existence and held the membership interests in Entergy Mississippi Power and Light.
•Entergy Mississippi, Inc. contributed the membership interests in Entergy Mississippi Power and Light to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Mississippi Power and Light is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Mississippi, Inc. changed its name to Entergy Utility Enterprises, Inc., and Entergy Mississippi Power and Light then changed its name to Entergy Mississippi, LLC. Entergy Mississippi, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Mississippi, Inc. The restructuring was accounted for as a transaction between entities under common control.
Entergy Wholesale Commodities
See “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the shutdown and sale of each of the Entergy Wholesale Commodities nuclear power plants. With the sale of Palisades in June 2022, Entergy completed its multi-year strategy to exit the merchant power business.
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Entergy Wholesale Commodities includes the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. Entergy Wholesale Commodities also provides decommissioning-related services to nuclear power plants owned by non-affiliated entities in the United States.
Property
Entergy Wholesale Commodities includes ownership in the following non-nuclear power plants:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Plant | | Location | | Ownership | | Net Owned Capacity (a) | | Type |
| Independence Unit 2; 842 MW | | Newark, AR | | 14% | | 121 MW(b) | | Coal |
| Nelson Unit 6; 550 MW | | Westlake, LA | | 11% | | 60 MW(b) | | Coal |
(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.
All of Entergy Wholesale Commodities’ owned generation falls under the authority of MISO. Entergy Wholesale Commodities’ customers for the sale of both energy and capacity from its owned generation and its contracted power purchases include retail power providers, utilities, electric power co-operatives, power trading organizations, and other power generation companies. The majority of Entergy Wholesale Commodities’ owned generation and contracted power purchases are sold under cost-based contract.
Other Business Activities
TLG Services, a subsidiary in the Entergy Wholesale Commodities segment, offers decommissioning, engineering, and related services to nuclear power plant owners.
Regulation of Entergy’s Business
Federal Power Act
The Federal Power Act provides the FERC the authority to regulate:
•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.
The Federal Power Act gives the FERC jurisdiction over the rates charged by System Energy for Grand Gulf capacity and energy provided to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans and over the rates charged by Entergy Arkansas and Entergy Louisiana to unaffiliated wholesale customers. The FERC also regulates wholesale power sales between the Utility operating companies. In addition, the FERC regulates the MISO RTO, an independent entity that maintains functional control over the combined transmission systems of its members and administers wholesale energy, capacity, and ancillary services markets for market participants in the MISO region, including the Utility operating companies. FERC regulation of the MISO RTO includes regulation of the design and implementation of the wholesale markets administered by the MISO RTO, as
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well as the rates, terms, and conditions of open access transmission service over the member systems and the allocation of costs associated with transmission upgrades.
Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 65 MW of capacity.
State Regulation
Utility
Entergy Arkansas is subject to regulation by the APSC as to the following:
•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 non-exempt 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.
Additionally, Entergy Arkansas serves a limited number of retail customers in Tennessee. Pursuant to legislation enacted in Tennessee, Entergy Arkansas is subject to complaints before the Tennessee Regulatory Authority only if it fails to treat its retail customers in Tennessee in the same manner as its retail customers in Arkansas. Additionally, Entergy Arkansas maintains limited facilities in Missouri but does not provide retail electric service to customers in Missouri. Although Entergy Arkansas obtained a certificate with respect to its Missouri facilities, Entergy Arkansas is not subject to retail ratemaking jurisdiction in Missouri.
Entergy Louisiana’s electric and gas business is subject to regulation by the LPSC as to the following:
•utility service;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment clause, environmental adjustment charge, 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 for purchase power contracts that exceed either 5 MW or one year in term;
•procurement process to acquire capacity over 50 MW;
•audits of the energy efficiency rider;
•avoided cost payment to non-exempt Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers and acquisitions and other changes of control.
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Entergy Mississippi is subject to regulation by the MPSC as to the following:
•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;
•certification of generating facilities and certain transmission projects;
•avoided cost payments to non-exempt Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers, acquisitions, and other changes of control.
Entergy Mississippi is also subject to regulation by the APSC as to the certificate of environmental compatibility and public need for the Independence Station, which is located in Arkansas.
Entergy New Orleans is subject to regulation by the City Council as to the following:
•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;
•avoided cost payments to non-exempt Qualifying Facilities;
•issuance and sale of certain securities; and
•utility mergers and acquisitions and other changes of control.
To the extent authorized by governing legislation, Entergy Texas is subject to the original jurisdiction of the municipal authorities of a number of incorporated cities in Texas with appellate jurisdiction over such matters residing in the PUCT. Entergy Texas is also subject to regulation by the PUCT as to the following:
•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 non-exempt Qualifying Facilities;
•net energy metering; 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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Regulation of the Nuclear Power Industry
Atomic Energy Act of 1954 and Energy Reorganization Act of 1974
Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose civil penalties or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, Entergy Louisiana, and System Energy, as owners of all or portions of ANO, River Bend and Waterford 3, and Grand Gulf, respectively, and Entergy Operations, as the licensee and operator of these units, are subject to the jurisdiction of the NRC.
Nuclear Waste Policy Act of 1982
Spent Nuclear Fuel
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 Arkansas is the only one of the Utility operating companies that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 2022 of $195.0 million for the one-time fee. The fees payable to the DOE may be adjusted in the future to assure full recovery. 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. Entergy’s total spent fuel fees to date, including the one-time fee liability of Entergy Arkansas, have surpassed $1.7 billion (exclusive of amounts relating to Entergy plants that were paid or are owed by prior owners of those plants).
The permanent spent fuel repository in the U.S. has been legislated to be Yucca Mountain, Nevada. The DOE is required by law to proceed with the licensing (the DOE filed the license application in June 2008) and, after the license is granted by the NRC, proceed with the repository construction and commencement of receipt of spent fuel. 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. The DOE continues to delay meeting its obligation. Specific steps were taken to discontinue the Yucca Mountain project, including a motion to the NRC to withdraw the license application with prejudice and the establishment of a commission to develop recommendations for alternative spent fuel storage solutions. In August 2013 the U.S. Court of Appeals for the D.C. Circuit ordered the NRC to continue with the Yucca Mountain license review, but only to the extent of funds previously appropriated by Congress for that purpose and not yet used. Although the NRC completed the safety evaluation report for the license review in 2015, the previously appropriated funds are not sufficient to complete the review, including required hearings. The government has taken no effective action to date related to the recommendations of the appointed spent fuel study commission. Accordingly, large uncertainty remains regarding the time frame under which the DOE will begin to accept spent fuel from Entergy’s facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at Entergy’s nuclear sites.
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 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
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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.
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. These subsidiaries have been, and continue to be, involved in litigation to recover the damages caused by the DOE’s delay in performance. See Note 8 to the financial statements for discussion of final judgments recorded by Entergy in 2020, 2021, and 2022 related to Entergy’s nuclear owner licensee subsidiaries’ litigation with the DOE. Through 2022, Entergy’s subsidiaries have won and collected on judgments against the government totaling approximately $1 billion.
Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are providing their own spent fuel storage. Storage capability additions using dry casks began operations at ANO in 1996, at River Bend in 2005, at Grand Gulf in 2006, and at Waterford 3 in 2011. These facilities will be expanded as needed.
Nuclear Plant Decommissioning
Entergy Arkansas, Entergy Louisiana, and System Energy are entitled to recover from customers through electric rates the estimated decommissioning costs for ANO, Waterford 3, and Grand Gulf, respectively. In addition, Entergy Louisiana and Entergy Texas are entitled to recover from customers through electric rates the estimated decommissioning costs for the portion of River Bend subject to retail rate regulation. The collections are deposited in trust funds that can only be used in accordance with NRC and other applicable regulatory requirements. Entergy periodically reviews and updates the estimated decommissioning costs to reflect inflation and changes in regulatory requirements and technology, and then makes applications to the regulatory authorities to reflect, in rates, the changes in projected decommissioning costs.
In December 2018 the APSC ordered collections in rates for decommissioning ANO 2 and found that ANO 1’s decommissioning was adequately funded without additional collections. In November 2021, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that both ANO 1 and 2 decommissioning trusts were adequately funded without further collections, and in December 2021 the APSC ordered zero collections for ANO 1 and 2 decommissioning. In November 2022, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that ANO 1’s decommissioning trust was adequately funded, but that ANO 2’s fund had a projected shortage as a result of a decline in decommissioning trust fund investment values over the past year. The filing proposes a reinstatement of decommissioning cost recovery for ANO 2. Management cannot predict the outcome of this filing.
In July 2010 the LPSC approved increased decommissioning collections for Waterford 3 and the Louisiana regulated share of River Bend to address previously identified funding shortfalls. This LPSC decision contemplated that the level of decommissioning collections could be revisited should the NRC grant license extensions for both Waterford 3 and River Bend. In July 2019, following the NRC approval of license extensions for Waterford 3 and River Bend, Entergy Louisiana made a filing with the LPSC seeking to adjust decommissioning and depreciation rates for those plants, including one proposed scenario that would adjust Louisiana-jurisdictional decommissioning collections to zero for both plants (including an offsetting increase in depreciation rates). Because of the ongoing public health emergency arising from the COVID-19 pandemic and accompanying economic uncertainty, Entergy Louisiana determined that the relief sought in the filing was no longer appropriate, and in November 2020, filed an unopposed motion to dismiss the proceeding. Following that filing, in a December 2020 order, the LPSC dismissed the proceeding without prejudice. In July 2021, Entergy Louisiana made a filing with the LPSC to adjust Waterford 3 and River Bend decommissioning collections based on the latest site-specific decommissioning cost estimates for those plants. The filing seeks to increase Waterford 3 decommissioning collections and decrease River Bend decommissioning collections. The procedural schedule in the case has been suspended pending settlement negotiations. Management cannot predict the outcome of this filing.
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In December 2010 the PUCT approved increased decommissioning collections for the Texas share of River Bend to address previously identified funding shortfalls. In December 2018 the PUCT approved a settlement that eliminated River Bend decommissioning collections for the Texas jurisdictional share of the plant based on a determination by Entergy Texas that the existing decommissioning fund was adequate following license renewal. In July 2022, Entergy Texas filed a rate case that proposed continuation of the cessation of River Bend decommissioning collections. In December 2022, Entergy Texas filed on behalf of the parties a motion to abate the hearing on the merits to give parties additional time to finalize a settlement, which was approved by the presiding ALJ along with an order for the parties to file monthly settlement status reports. Management cannot predict the outcome of this filing.
In December 2016 the NRC issued a 20-year operating license renewal for Grand Gulf. In a 2017 filing at the FERC, System Energy stated that with the renewed operating license, Grand Gulf’s decommissioning trust was sufficiently funded, and proposed, among other things, to cease decommissioning collections for Grand Gulf effective October 1, 2017. The FERC accepted a settlement including the proposed decommissioning revenue requirement by letter order in August 2018.
Entergy currently believes its decommissioning funding will be sufficient for its nuclear plants subject to retail rate regulation, although decommissioning cost inflation and trust fund performance will ultimately determine the adequacy of the funding amounts.
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. In March 2021 filings with the NRC were made reporting on decommissioning funding for all of Entergy’s subsidiaries’ nuclear plants. Those reports showed that decommissioning funding for each of the nuclear plants met the NRC’s financial assurance requirements.
Additional information with respect to Entergy’s decommissioning costs and decommissioning trust funds is found in Note 9 and Note 16 to the financial statements.
Price-Anderson Act
The Price-Anderson Act requires that reactor licensees purchase and maintain the maximum amount of nuclear liability insurance available and participate in an industry assessment program called Secondary Financial Protection in order to protect 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 limits the contingent liability for a single nuclear incident to a maximum assessment of approximately $137.6 million per reactor (with 96 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, Entergy Louisiana, or System Energy is liable, protection is afforded through a combination of private insurance and the Secondary Financial Protection program. In addition to this, insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units is also purchased. The Price-Anderson Act and insurance applicable to the nuclear programs of Entergy are discussed in more detail in Note 8 to the financial statements.
NRC Reactor Oversight Process
The NRC’s Reactor Oversight Process is a program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response. The NRC evaluates plant performance by analyzing two distinct inputs: inspection findings resulting from the NRC’s inspection program and performance indicators reported by the licensee. The evaluations result in the placement of
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each plant in one of the NRC’s Reactor Oversight Process Action Matrix columns: “licensee response column,” or Column 1, “regulatory response column,” or Column 2, “degraded cornerstone column,” or Column 3, and “multiple/repetitive degraded cornerstone column,” or Column 4, and “unacceptable performance,” or Column 5. Plants in Column 1 are subject to normal NRC inspection activities. Plants in Column 2, Column 3, or Column 4 are subject to progressively increasing levels of inspection by the NRC. Continued plant operation is not permitted for plants in Column 5. All of the nuclear generating plants owned and operated by Entergy’s Utility business are currently in Column 1, except Waterford 3, which is in Column 2.
In September 2022 the NRC placed Waterford 3 in Column 2 based on an error associated with a radiation monitor calibration. Entergy corrected the issue with the radiation monitor in February 2022; however, Waterford 3 is expected to remain in Column 2 until third quarter 2023 based on a subsequent radiation monitor calibration issue.
Environmental Regulation
Entergy’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy’s businesses are in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted below. Because environmental regulations are subject to change, future compliance requirements and costs cannot be precisely estimated. Except to the extent discussed below, at this time compliance with federal, state, and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of Entergy’s businesses and is not expected to have a material effect on their competitive position, results of operations, cash flows, or financial position.
Clean Air Act and Subsequent Amendments
The Clean Air Act and its amendments establish several programs that currently or in the future may affect Entergy’s fossil-fueled generation facilities and, to a lesser extent, certain operations at nuclear and other facilities. Individual states also operate similar independent state programs or delegated federal programs that may include requirements more stringent than federal regulatory requirements. These programs include:
•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.
National Ambient Air Quality Standards
The Clean Air Act requires the EPA to set National Ambient Air Quality Standards (NAAQS) for ozone, carbon monoxide, lead, nitrogen dioxide, particulate matter, and sulfur dioxide, and requires periodic review of those standards. When an area fails to meet an ambient standard, it is considered to be in nonattainment and is classified as “marginal,” “moderate,” “serious,” or “severe.” When an area fails to meet the ambient air standard, the EPA requires state regulatory authorities to prepare state implementation plans meant to cause progress toward bringing the area into attainment with applicable standards.
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Ozone Nonattainment
Entergy Texas operates two fossil-fueled generating facilities (Lewis Creek and Montgomery County Power Station) in a geographic area that is not in attainment with the applicable NAAQS for ozone. The ozone nonattainment area that affects Entergy Texas is the Houston-Galveston-Brazoria area. Both Lewis Creek and the Montgomery County Power Station hold all necessary permits for operation and comply with applicable air quality program regulations. Measures enacted to return the area to ozone attainment could make these program regulations more stringent. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and nonattainment with the ozone NAAQS.
Potential SO2Nonattainment
The EPA issued a final rule in June 2010 adopting an SO2 1-hour national ambient air quality standard of 75 parts per billion. In Entergy’s utility service territory, only St. Bernard Parish and Evangeline Parish in Louisiana are designated as nonattainment. In August 2017 the EPA issued a letter indicating that East Baton Rouge and St. Charles parishes would be designated by December 31, 2020, as monitors were installed to determine compliance. In March 2021 the EPA published a final rule designating East Baton Rouge, St. Charles, St. James, and West Baton Rouge parishes in Louisiana as attainment/unclassifiable, and, in Texas, Jefferson County as attainment/unclassifiable and Orange County as unclassifiable. No challenges to these final designations were filed within the 60 day deadline. Entergy continues to monitor this situation.
Hazardous Air Pollutants
The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011, which had a compliance date, with a widely granted one-year extension, of April 2016. The required controls have been installed and are operational at all affected Entergy units. In May 2020 the EPA finalized a rule that finds that it is not “appropriate and necessary” to regulate hazardous air pollutants from electric steam generating units under the provisions of section 112(n) of the Clean Air Act. This is a reversal of the EPA’s previous finding requiring such regulation. The final appropriate and necessary finding does not revise the underlying MATS rule. Several lawsuits have been filed challenging the appropriate and necessary finding. In February 2021 the D.C. Circuit granted the EPA’s motion to hold the litigation in abeyance pending the agency’s review of the appropriate and necessary rule. In February 2022 the EPA issued a proposed rule revoking the 2020 rule and determining, again, that it is “appropriate and necessary” to regulate hazardous air pollutants. The EPA is seeking additional information, which it could use to further tighten the standard. Entergy will continue to monitor this situation.
Cross-State Air Pollution
In March 2005 the EPA finalized the Clean Air Interstate Rule (CAIR), which was intended to reduce SO2 and NOx emissions from electric generation plants in order to improve air quality in twenty-nine eastern states. The rule required a combination of capital investment to install pollution control equipment and increased operating costs through the purchase of emission allowances. Entergy began implementation in 2007, including installation of controls at several facilities and the development of an emission allowance procurement strategy. Based on several court challenges, CAIR and its subsequent versions, now known as the Cross-State Air Pollution Rule (CSAPR), have been remanded to and modified by the EPA on multiple occasions.
In April 2022 the EPA published a rule to address interstate transport for the 2015 ozone NAAQS which will increase the stringency of the CSAPR program in all four of the states where the Utility operating companies operate. If finalized as proposed, the rule will significantly reduce emission allowances and would likely require the installation of post-combustion nitrogen oxides (NOx) emissions controls on any coal or large legacy gas units that will operate beyond 2026 and are not currently equipped with such controls. Fifteen Entergy-owned units, totaling approximately 9,370 MW of total unit capacity, are identified by the EPA for selective catalytic reduction retrofits.
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Based on the EPA estimates, Entergy’s share of the capital costs would be approximately $1.6 billion if all the identified units were in fact retrofitted. Additionally, the EPA is proposing controls on certain non-electric generating NOx sources. Since releasing the proposed rule, the price for Group 3 NOx sources allowances has increased significantly, peaking at over $45,000 per allowance in late August 2022 before stabilizing in the range of $15,000 to $18,000 per allowance since September 2022. Comments on the proposed rule were due in June 2022. MISO, other impacted regional transmission organizations, and various state public service commissions all filed comments expressing reliability concerns if the rule is finalized as proposed. Entergy filed individual comments which assert, in addition to other issues, that the EPA’s proposal represents over-control of the Entergy units in Arkansas and Mississippi; the EPA should consider an alternative approach or provide flexibility for units with a limited remaining useful life; the EPA should consult with regional transmission organizations to determine the reliability impacts of the proposed rule; and the EPA should consider and incorporate current economic trends, including inflation, into any benefit-costs analysis supporting the rule.
Regional Haze
In June 2005 the EPA issued its final Clean Air Visibility Rule (CAVR) regulations that potentially could result in a requirement to install SO2 and NOx pollution control technology as Best Available Retrofit Control Technology to continue operating certain of Entergy’s fossil generation units. The rule leaves certain CAVR determinations to the states. This rule establishes a series of 10-year planning periods, with states required to develop State Implementation Plans (SIPs) for each planning period, with each SIP including such air pollution control measures as may be necessary to achieve the ultimate goal of the CAVR by the year 2064. The various states are currently in the process of developing SIPs to implement the second planning period of the CAVR, which addresses the 2018-2028 planning period.
In January and February 2018, Entergy Arkansas, Entergy Mississippi, Entergy Power, and other co-owners received 60-day notice of intent to sue letters from the Sierra Club and the National Parks Conservation Association concerning allegations of violations of new source review and permitting provisions of the Clean Air Act at the Independence and White Bluff coal-burning units, respectively. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims and reducing the risk that Entergy Arkansas, as operator of Independence and White Bluff, might be compelled under the Clean Air Act’s regional haze program to install costly emissions control technologies. Consistent with the terms of the settlement, Entergy Arkansas, along with co-owners, agreed to begin using only low-sulfur coal at Independence and White Bluff by mid-2021; agreed to cease using coal at White Bluff and Independence by the end of 2028 and 2030, respectively; agreed to cease operation of the remaining gas unit at Lake Catherine by the end of 2027; reserved the option to develop new generating sources at each plant site; and committed to installing or proposing to regulators at least 800 MWs of renewable generation by the end of 2027, with at least half installed or proposed by the end of 2022 (which includes two existing Entergy Arkansas projects) and with all qualifying co-owner projects counting toward satisfaction of the obligation. Under the settlement, the Sierra Club and the National Parks Conservation Association also waived certain potential existing claims under federal and state environmental law with respect to specified generating plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the National Parks Conservation Association, was subject to approval by the U.S. District Court for the Eastern District of Arkansas. In November 2020 the court denied motions by the Arkansas Attorney General and the Arkansas Affordable Energy Coalition to intervene and to stay the proceedings. The proposed intervenors did not appeal the ruling. The District Court approved and entered the proposed settlement in March 2021. Entergy met the settlement deadline to use low-sulfur coal and is on target to meet the other requirements of the settlement. See “Remaining Useful Lives Review” in the “State and Local Rate Regulation and Fuel-Cost Recovery” section of Entergy Arkansas, LLC and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the APSC’s proceeding related to Entergy Arkansas’s utility generation units.
The second planning period (2018-2028) for the regional haze program requires states to examine sources for impacts on visibility and to prepare SIPs by July 31, 2021 to ensure reasonable progress is being made to attain
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visibility improvements. Entergy received information collection requests from the Arkansas and Louisiana Departments of Environmental Quality requesting an evaluation of technical and economic feasibility of various NOx and SO2 control technologies for Independence, Nelson 6, Nelson Industrial Steam Company (NISCO), and Ninemile. Responses to the information collection requests have been submitted to the respective state agencies. Louisiana has issued its draft SIP which, at this time, does not propose any additional air emissions controls for the affected Entergy units in Louisiana. Some public commenters, however, believe additional air controls are cost-effective. It is not yet clear how the Louisiana Department of Environmental Quality (LDEQ) will respond in its final SIP, and the agency, like many other state agencies, did not meet the July 31, 2021 deadline to submit a SIP to the EPA for review.
Similar to the LDEQ, the Arkansas Department of Energy and Environment, Division of Environmental Quality (ADEQ) did not meet the July 31, 2021 SIP submission deadline, but subsequently submitted it to the EPA for review. The ADEQ reviewed Entergy’s Independence plant, but determined that additional air emission controls would not be cost-effective considering the facility’s commitment to cease coal-fired combustion by December 31, 2030.
The Texas Commission on Environmental Quality has completed its second-planning period SIP and submitted it to the EPA for review. There were no Entergy sources selected for additional emission controls. The Mississippi Department of Environmental Quality continues to develop its SIP, but there are no Entergy sources that are expected to be impacted.
In August 2022 the EPA issued findings of failure to submit regional haze SIPs to 15 states, including Louisiana and Mississippi. These findings were effective September 2022 and start the two-year period for the EPA to either approve a SIP submitted by the state or issue a final federal plan.
Greenhouse Gas Emissions
In July 2019 the EPA released the Affordable Clean Energy Rule (ACE), which applies only to existing coal-fired electric generating units. The ACE determines that heat rate improvements are the best system of emission reductions and lists six candidate technologies for consideration by states at each coal unit. The rule and associated rulemakings by the EPA replace the Obama administration’s Clean Power Plan, which established national emissions performance rates for existing fossil-fuel fired steam electric generating units and combustion turbines. The ACE rule provides states discretion in determining how the best system for emission reductions applies to individual units, including through the consideration of technical feasibility and the remaining useful life of the facility. The ADEQ and the LDEQ have issued information collection requests to Entergy facilities to help the states collect the information needed to determine the best system of emission reductions for each facility. Entergy responded to the requests. In January 2021 the U.S. Court of Appeals for the D.C. Circuit vacated ACE. The court held that ACE relied on an incorrect interpretation of the Clean Air Act that the statute expressly forecloses emission reduction approaches, such as emissions trading and generating shifting, that cannot be applied at and to the individual source. The court remanded ACE to the EPA for further consideration and also vacated the repeal of the Clean Power Plan. In March 2021 the D.C. Circuit issued a partial mandate vacating the ACE rule, but withheld the mandate vacating the repeal of the Clean Power Plan pending the EPA’s new rulemaking to regulate greenhouse gas emissions. Thus, there currently is no regulation in place with respect to greenhouse gas emissions from existing electric generating units and states are not expected to take further action to develop and submit plans at this time. In October 2021 the United States Supreme Court agreed to hear a challenge to the already vacated ACE rule. In June 2022 the United States Supreme Court held that the EPA could not use generation shifting as the best system of emission reduction under Section 111(d) of the Clean Air Act. The EPA does still have the authority to regulate greenhouse gas emissions, but those emissions reductions must be technology based. The EPA has announced its intent to propose a rule for existing power plants pursuant to the Clean Air Act by March 2023. The ultimate impact of the United States Supreme Court's decision cannot be determined at this time.
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Entergy Corporation, Utility operating companies, and System Energy
In April 2021, President Biden announced a target for the United States in connection with the United Nations’ “Paris Agreement” on climate change. The target consists of a 50-52 percent reduction in economy-wide net greenhouse gas emissions from 2005 levels by 2030. President Biden has also stated that a goal of his administration is for the electric power industry to decarbonize fully by 2035. The details surrounding implementation of these targets are not finalized, and the impacts to Entergy of any potential related legislation cannot be predicted.
Entergy continues to support national legislation that would most efficiently reduce economy-wide greenhouse gas emissions and increase planning certainty for electric utilities. By virtue of its proportionally large investment in low-emitting generation technologies, Entergy has a low overall carbon dioxide emission “intensity,” or rate of carbon dioxide emitted per megawatt-hour of electricity generated. In anticipation of the imposition of carbon dioxide emission limits on the electric industry, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included a formal program to stabilize owned power plant carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in reducing emissions below 2000 levels. In 2006, Entergy started including emissions from controllable power purchases in addition to its ownership share of generation and established a second formal voluntary program to stabilize power plant carbon dioxide emissions and emissions from controllable power purchases, cumulatively over the period, at 20% below 2000 levels through 2010. In 2011, Entergy extended this commitment through 2020, which it ultimately outperformed by approximately 8% both cumulatively and on an annual basis. In 2019, in connection with a climate scenario analysis following the recommendations of the Task Force on Climate-related Financial Disclosures describing climate-related governance, strategy, risk management, and metrics and targets, Entergy announced a 2030 carbon dioxide emission rate goal focused on a 50% reduction from Entergy’s base year - 2000. Entergy now anticipates achieving this reduction several years early. In September 2020, Entergy announced a commitment to achieve net-zero greenhouse gas emissions by 2050 inclusive of all businesses, all applicable gases, and all emission scopes. In 2022, Entergy enhanced its commitment to include an interim goal of 50% carbon-free energy generating capacity by 2030 and expanded its interim emission rate goal to include all purchased power. See “Risk Factors” in Part I Item 1A for discussion of the risks associated with achieving these climate goals. Entergy’s comprehensive, third-party verified greenhouse gas inventory and progress against its voluntary goals are published on its website.
Entergy participates in the M.J. Bradley & Associates’ Annual Benchmarking Air Emissions Report, an annual analysis of the 100 largest U.S. electric power producers. The report is available on the M.J. Bradley website. Entergy participates annually in the Dow Jones Sustainability Index and in 2022 was listed on the North American Index. Entergy has been listed on the World or North American Index, or both, for 21 consecutive years. Entergy also participated in the 2022 CDP Climate Change and CDP Water Security evaluations, receiving a ‘B’ for both responses.
Potential Legislative, Regulatory, and Judicial Developments
In addition to the specific instances described above, there are a number of legislative and regulatory initiatives that are under consideration at the federal, state, and local level. Because of the nature of Entergy’s business, the imposition of any of these initiatives could affect Entergy’s operations. Entergy continues to monitor these initiatives and activities in order to analyze their potential operational and cost implications. These initiatives include:
•reconsideration and revision of ambient air quality standards downward which could lead to additional areas of nonattainment;
•designation by the EPA and state environmental agencies of areas that are not in attainment with national ambient air quality standards;
•introduction of bills in Congress and development of regulations by the EPA proposing further limits on SO2, mercury, carbon dioxide, and other air emissions. New legislation or regulations applicable to
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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 cap and trade programs to limit carbon dioxide and other greenhouse gases;
•efforts on the local, 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 polychlorinated biphenyls (PCBs);
•efforts by certain external groups to encourage reporting and disclosure of environmental, social, and governance 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;
•the regulation of the management, disposal, and beneficial reuse of coal combustion residuals; and
•the regulation of the management and disposal and recycling of equipment associated with renewable and clean energy sources such as used solar panels, wind turbine blades, hydrogen usage, or battery storage.
Clean Water Act
The 1972 amendments to the Federal Water Pollution Control Act (known as the Clean Water Act) provide the statutory basis for the National Pollutant Discharge Elimination System permit program, section 402, and the basic structure for regulating the discharge of pollutants from point sources to waters of the United States. The Clean Water Act requires virtually all discharges of pollutants to waters of the United States to be permitted. Section 316(b) of the Clean Water Act regulates cooling water intake structures, section 401 of the Clean Water Act requires a water quality certification from the state in support of certain federal actions and approvals, and section 404 regulates the dredge and fill of waters of the United States, including jurisdictional wetlands.
Federal Jurisdiction of Waters of the United States
In June 2020 the EPA’s revised definition of waters of the United States in the Navigable Waters Protection Rule (NWPR) became effective, narrowing the scope of Clean Water Act jurisdiction, as compared to a 2015 definition which had been stayed by several federal courts. In August 2021 a federal district court vacated and remanded the NWPR for further consideration. The EPA and the U.S. Army Corps of Engineers (Corps) subsequently issued a statement that the agencies would revert to pre-2015 regulations pending a new rulemaking. In December 2022 the EPA and the Corps released a final definition of waters of the United States that replaces the NWPR with a definition that is consistent with the pre-2015 regulatory regime as interpreted by several United States Supreme Court decisions. Most notably, the exclusion for waste treatment systems is retained.
Comprehensive Environmental Response, Compensation, and Liability Act of 1980
The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), authorizes the EPA to mandate clean-up by, or to collect reimbursement of clean-up costs from, owners or operators of sites at which hazardous substances may be or have been released. Certain private parties also may use CERCLA to recover response costs. Parties that transported hazardous substances to these sites or arranged for the disposal of the substances are also deemed liable by CERCLA. CERCLA has been interpreted to impose strict, joint, and several liability on responsible parties. Many states have adopted programs similar to CERCLA. Entergy subsidiaries in the Utility and Entergy Wholesale Commodities businesses have sent waste materials to various
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disposal sites over the years, and releases have occurred at Entergy facilities including nuclear facilities that have been or will be sold to decommissioning companies. In addition, environmental laws now regulate certain of Entergy’s operating procedures and maintenance practices that historically were not subject to regulation. Some disposal sites used by Entergy subsidiaries have been the subject of governmental action under CERCLA or similar state programs, resulting in site clean-up activities. Entergy subsidiaries have participated to various degrees in accordance with their respective potential liabilities in such site clean-ups and have developed experience with clean-up costs. The affected Entergy subsidiaries have established provisions for the liabilities for such environmental clean-up and restoration activities. Details of potentially material CERCLA and similar state program liabilities are discussed in the “Other Environmental Matters” section below.
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. As of December 31, 2022, Entergy has recorded asset retirement obligations related to CCR management of $27 million.
Pursuant to the EPA Rule, Entergy operates groundwater monitoring systems surrounding its coal combustion residual landfills located at White Bluff, Independence, and Nelson. Monitoring to date has detected concentrations of certain listed constituents in the area, but has not indicated that these constituents originated at the active landfill cells. Reporting has occurred as required, and detection monitoring will continue as the rule requires. In late-2017, Entergy determined that certain in-ground wastewater treatment system recycle ponds at its White Bluff and Independence facilities require management under the new EPA regulations. Consequently, in order to move away from using the recycle ponds, White Bluff and Independence each have installed a new permanent bottom ash handling system that does not fall under the CCR rule. As of November 2020, both sites are operating the new system and no longer are sending waste to the recycle ponds. Each site has commenced closure of its two recycle ponds (four ponds total), prior to the April 11, 2021 deadline under the finalized CCR rule for unlined recycle ponds. Any potential requirements for corrective action or operational changes under the new CCR rule continue to be assessed. Notably, ongoing litigation has resulted in the EPA’s continuing review of the rule. Consequently, the nature and cost of additional corrective action requirements may depend, in part, on the outcome of the EPA’s review.
Other Environmental Matters
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas
The EPA notified Entergy that the EPA believes Entergy is a PRP concerning PCB contamination at the F.J. Doyle Salvage facility in Leonard, Texas. The facility operated as a scrap salvage business during the 1970s to the 1990s. In May 2018 the EPA investigated the site surface and sub-surface soils and, in November 2018 the EPA conducted a removal action, including disposal of PCB contaminated soils. Entergy responded to the EPA’s information requests in May and July 2019. In November 2020 the EPA sent Entergy and other PRPs a demand letter seeking reimbursement for response costs totaling $4 million expended at the site. Liability and PRP
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allocation of response costs are yet to be determined. In December 2020, Entergy responded to the demand letter, without admitting liability or waiving any rights, indicating that it would engage in good faith negotiations with the EPA with respect to the demand. An initial meeting between the EPA and the PRPs took place in June 2021. Negotiations between the PRPs and the EPA are ongoing.
Litigation
Entergy uses legal and appropriate means to contest litigation threatened or filed against it, but certain states in which Entergy operates have proven to be unusually litigious environments. Judges and juries in Louisiana, Mississippi, and Texas have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. The litigation environment in these states poses a significant business risk to Entergy.
Asbestos Litigation(Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas)
See Note 8 to the financial statements for a discussion of this litigation.
Employment and Labor-related Proceedings (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
See Note 8 to the financial statements for a discussion of these proceedings.
Human Capital
Employees
Employees are an integral part of Entergy’s commitment to serving customers. As of December 31, 2022, Entergy subsidiaries employed 11,707 people.
| | | | | |
| Utility: | |
| Entergy Arkansas | 1,227 | |
| Entergy Louisiana | 1,597 | |
| Entergy Mississippi | 716 | |
| Entergy New Orleans | 296 | |
| Entergy Texas | 648 | |
| System Energy | — | |
| Entergy Operations | 3,317 | |
| Entergy Services | 3,870 | |
| Entergy Nuclear Operations | 13 | |
| Other subsidiaries | 23 | |
| Total Entergy | 11,707 | |
Approximately 3,084 employees are represented by the International Brotherhood of Electrical Workers, the United Government Security Officers of America, and the International Union, Security, Police, and Fire Professionals of America.
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Below is the breakdown of Entergy’s employees by gender and race/ethnicity:
| | | | | | | | | | | |
| Gender (%) | 2022 | | 2021 |
| Female | 22.2 | | 21.4 |
| Male | 77.8 | | 78.6 |
| | | | | | | | | | | |
| Race/Ethnicity (%) | 2022 | | 2021 |
| White | 74.8 | | 76.4 |
| Black/African American | 17.3 | | 16.4 |
| Hispanic/Latino | 3.0 | | 2.7 |
| Asian | 2.3 | | 2.0 |
| Other | 2.6 | | 2.5 |
Entergy’s Approach to Human Resources
Entergy’s people and culture enable its success; that is why acquiring, retaining, and developing talent are important components of Entergy’s human resources strategy. Entergy focuses on an approach that includes, among other things, governance and oversight; safety; organizational health, including diversity, inclusion, and belonging; and talent management.
Governance and Oversight
Ensuring that workplace processes support the desired culture and strategy begins with the Board of Directors and the Office of the Chief Executive. The Talent and Compensation Committee (formerly Personnel Committee) establishes priorities and each quarter reviews strategies and results on a range of topics covering the workforce, the workplace, and the marketplace. It oversees Entergy’s incentive plan design and administers its executive compensation plans to incentivize the behaviors and outcomes that support achievement of Entergy’s corporate objectives. Annually, it reviews executive performance, development, succession plans, and talent pipeline to align a high performing executive team with Entergy’s priorities. The Talent and Compensation Committee also oversees Entergy’s performance through regular briefings on a wide variety of human resources topics including Entergy’s safety culture and performance; organizational health; and diversity, inclusion, and belonging initiatives and performance.
The Talent and Compensation Committee’s Charter was revised in 2021 to acknowledge the committee’s responsibility for overseeing and monitoring the effectiveness of Entergy’s human capital strategies, including its workforce diversity, inclusion, and organizational health and safety strategies, programs, and initiatives. In recognition of the importance that organizational health and diversity, inclusion, and belonging play in enabling Entergy to achieve its business strategies, the committee receives periodic reports on Entergy’s organization health and diversity, inclusion, and belonging programs, strategies, and performance, including briefings at each of its regular meetings. The committee also receives updates on Entergy’s performance to date on key workforce, workplace, and marketplace measures, including progress in the representation of women and underrepresented minorities, both in the total workforce and in director level and above placements, progress in key diversity, inclusion, and belonging initiatives and diverse supplier spend.
Other committees of the Board oversee other key aspects of Entergy’s culture. For example, the Audit Committee reviews reports on enterprise risks, ethics, and compliance training and performance, as well as regular reports on calls made to Entergy’s ethics line and related investigations. To maximize the sharing of information and facilitate the participation of all Board members in these discussions, the Board schedules its regular committee meetings in a manner such that all directors can attend.
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The Office of the Chief Executive, which includes the Senior Vice President and Chief Human Resources Officer, ensures annual business plans are designed to support Entergy’s talent objectives, reviews workforce-related metrics, and regularly discusses the development, succession planning, and performance of their direct reports and other company officers.
Safety
Entergy’s safety objective is: Everyone Safe. All Day. Every Day. The continuation of the COVID-19 pandemic and another historic hurricane season presented significant challenges. Entergy employees achieved a total recordable incident rate of 0.51 in 2022, compared to 0.46 in 2021, and 0.40 in 2020. The results of 2021 unfortunately included an employee fatality. Entergy has enhanced dramatically leadership efforts and field presence to further its objective of zero fatalities, which it achieved in 2022. Also in 2022, there was a significant decrease in the number of serious injuries. The recordable incident rate equals the number of recordable incidents per 100 full-time equivalents. Recordable incidents include fatalities, lost-time accidents, restricted-duty accidents, and medical attentions and is not inclusive of potential work-related COVID-19 cases.
Organizational Health, including Diversity, Inclusion and Belonging (DIB)
Entergy believes that organizational health fosters an engaged and productive culture that positions Entergy to deliver sustainable value to its stakeholders. Entergy measures its progress through an organizational health survey coordinated by an external third party. Since initially administering the survey in 2014, Entergy improved from an initial score of 49 (fourth quartile) to a score in 2020 of 72 (second quartile), in 2021 of 63 (third quartile), and in 2022 of 61 (third quartile). Although the score declined slightly in 2022 as compared to 2021, it improved from the 2014 baseline. Management uses the results of the annual survey to design and implement strategies to positively influence organizational health. Initial employee participation of 66 percent in 2014 rose to and remains at approximately 90 percent in 2019-2022.
Entergy believes that creating a culture of diversity, inclusion, and belonging drives foundational engagement. Entergy is committed to developing and retaining a workforce that reflects the rich diversity of the communities it serves. In 2019, Entergy embarked on a three-year phased approach to enhance inclusion for individuals and teams. In 2022, Entergy continued to focus its actions to engage a diverse workforce, infusing DIB into hiring policies, practices and procedures, aligning Employee Resource Group goals to DIB goals, growing its DIB Champion network, integrating DIB into Entergy’s leadership development programs, and facilitating training from the executive leadership ranks down to the frontline. Through these efforts, Entergy aspires to create greater understanding and accountability regarding the behaviors and outcomes that are indicative of a premier utility.
Talent Management
Entergy’s focus on talent management is organized in three areas: developing and attracting a diverse pool of talent, equipping its leaders to develop the organization, and building premier utility capability through employee performance management and succession programs. Entergy believes that developing a diverse pool of local talent equipped with the skills needed, today and in the future, and reflecting the communities Entergy serves will give it a long-term competitive advantage. The focus of Entergy’s leadership development programs is to equip managers with the skills needed to effectively develop their teams and improve the leader-employee relationship. Entergy’s talent development infrastructure, which includes a combination of business function-specific and enterprise-wide learning and development programs, is designed to ensure Entergy has qualified staff with the skills, experiences, and behaviors needed to perform today and prepare for the future. Entergy strives to achieve its strategic priorities by aligning and enhancing team and individual performance with business objectives, effectively deploying talent through succession planning, and managing workforce transitions.
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Availability of SEC filings and other information on Entergy’s website
Entergy electronically files reports with the SEC, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxies, and amendments to such reports. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding registrants that file electronically with the SEC at http://www.sec.gov. Copies of the reports that Entergy files with the SEC can be obtained at the SEC’s website.
Entergy uses its website, http://www.entergy.com, as a routine channel for distribution of important information, including news releases, analyst presentations and financial information. Filings made with the SEC are posted and available without charge on Entergy’s website as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. These filings include annual and quarterly reports on Forms 10-K and 10-Q and current reports on Form 8-K (including related filings in XBRL format); proxy statements; and any amendments to those reports or statements. All such postings and filings are available on Entergy’s Investor Relations website free of charge. Entergy is providing the address to its internet site solely for the information of investors and does not intend the address to be an active link. The contents of the website are not incorporated into this report.
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
Item 1A. RISK FACTORS
See “RISK FACTORS SUMMARY” in Part I Item 1 for a summary of Entergy’s and the Registrant Subsidiaries’ risk factors.
Investors should review carefully the following risk factors and the other information in this Form 10-K. The risks that Entergy faces are not limited to those in this section. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely affect Entergy’s financial condition, results of operations, and liquidity. See “FORWARD-LOOKING INFORMATION.”
Utility Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The terms and conditions of service, including electric and gas rates, of the Utility operating companies and System Energy are determined through regulatory approval proceedings that can be lengthy and subject to appeal, potentially resulting in delays in effecting rate changes, lengthy litigation, the risk of disallowance of recovery of certain costs, and uncertainty as to ultimate results.
The Utility operating companies are regulated on a cost-of-service and rate of return basis and are subject to statutes and regulatory commission rules and procedures. The rates that the Utility operating companies and System Energy charge reflect their capital expenditures, operations and maintenance costs, allowed rates of return, financing costs, and related costs of service. These rates significantly influence the financial condition, results of operations, and liquidity of Entergy and each of the Utility operating companies and System Energy. These rates are determined in regulatory proceedings and are subject to periodic regulatory review and adjustment, including adjustment upon the initiative of a regulator or, in some cases, affected stakeholders. Regulators in a future rate proceeding may alter the timing or amount of certain costs for which recovery is allowed or modify the current authorized rate of return. Rate refunds may also be required, subject to applicable law.
In addition, regulators have initiated and may initiate additional proceedings to investigate the prudence of costs in the Utility operating companies’ and System Energy’s base rates and examine, among other things, the reasonableness or prudence of the companies’ operation and maintenance practices, level of expenditures (including storm costs and costs associated with capital projects), allowed rates of return and rate base, proposed resource acquisitions, and previously incurred capital expenditures that the operating companies seek to place in rates. The regulators may disallow costs subject to their jurisdiction found not to have been prudently incurred or found not to have been incurred in compliance with applicable tariffs, creating some risk to the ultimate recovery of those costs. Regulatory proceedings relating to rates and other matters typically involve multiple parties seeking to limit or reduce rates. Traditional base rate proceedings, as opposed to formula rate plans, generally have long timelines, are primarily based on historical costs, and may or may not be limited in scope or duration by statute. The length of these base rate proceedings can cause the Utility operating companies and System Energy to experience regulatory lag in recovering costs through rates, such that the Utility operating companies may not fully recover all costs during the rate effective period and may, therefore, earn less than their allowed returns. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with rate case proceedings. For a discussion of such appeals and related litigation for both the Utility operating companies and System Energy, see Note 2 to the financial statements.
The Utility operating companies have large customer and stakeholder bases and, as a result, could be the subject of public criticism or adverse publicity focused on issues including the operation and maintenance of their assets and infrastructure, their preparedness for major storms or other extreme weather events and/or the time it takes to restore service after such events, or the quality of their service or the reasonableness of the cost of their
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service. Criticism or adverse publicity of this nature could render legislatures and other governing bodies, public service commissions and other regulatory authorities, and government officials less likely to view the applicable operating company in a favorable light and could potentially negatively affect legislative or regulatory processes or outcomes, as well as lead to increased regulatory oversight or more stringent legislative or regulatory requirements or other legislation or regulatory actions that adversely affect the Utility operating companies.
The Utility operating companies and System Energy, and the energy industry as a whole, have experienced a period of rising costs and investments and an upward trend in spending, especially with respect to infrastructure investments, which is likely to continue in the foreseeable future and could result in more frequent rate cases and requests for, and the continuation of, cost recovery mechanisms, all of which could face resistance from customers and other stakeholders especially in a rising cost environment, whether due to inflation or high fuel prices or otherwise, and/or in periods of economic decline or hardship. Significant increases in costs could increase financing needs and otherwise adversely affect Entergy, the Utility operating companies, and System Energy’s business, financial position, results of operation, or cash flows. For information regarding rate case proceedings and formula rate plans applicable to the Utility operating companies, see Note 2 to the financial statements.
Changes to state or federal legislation or regulation affecting electric generation, electric and natural gas transmission, distribution, and related activities could adversely affect Entergy and the Utility operating companies’ financial position, results of operations, or cash flows and their utility businesses.
If legislative and regulatory structures evolve in a manner that erodes the Utility operating companies’ exclusive rights to serve their regulated customers, they could lose customers and sales and their results of operations, financial position, or cash flows could be materially affected. Additionally, technological advances in energy efficiency and distributed energy resources are reducing the costs of these technologies and, together with ongoing state and federal subsidies, the increasing penetration of these technologies could result in reduced sales by the Utility operating companies. Such loss of sales, due to the methodology used to determine cost of service rates or otherwise, could put upward pressure on rates, possibly resulting in adverse regulatory actions to mitigate such effects on rates. Further, the failure of regulatory structures to evolve to accommodate the changing needs and desires of customers with respect to the sourcing and use of electricity also could diminish sales by the operating companies. Entergy and the Utility operating companies cannot predict if or when they may be subject to changes in legislation or regulation, or the extent and timing of reductions of the cost of distributed energy resources, nor can they predict the impact of these changes on their results of operations, financial position, or cash flows.
The Utility operating companies recover fuel, purchased power, and associated costs through rate mechanisms that are subject to risks of delay or disallowance in regulatory proceedings, and sudden or prolonged increases in fuel and purchased power costs could lead to increased customer arrearages or bad debt expenses.
The Utility operating companies recover their fuel, purchased power, and associated costs from their customers through rate mechanisms subject to periodic regulatory review and adjustment. Because regulatory review can result in the disallowance of incurred costs found not to have been prudently incurred or not reflected in rates as permitted by approved rate schedules and accounting rules, including the cost of replacement power purchased when generators experience outages or when planned outages are extended, with the possibility of refunds to ratepayers, there exists some risk to the ultimate recovery of those costs, particularly when there are substantial or sudden increases in such costs. Regulators also may initiate proceedings to investigate the continued usage or the adequacy and operation of the fuel and purchased power recovery clauses of the Utility operating companies and, therefore, there can be no assurance that existing recovery mechanisms will remain unchanged or in effect at all.
The Utility operating companies’ cash flows can be negatively affected by the time delays between when gas, power, or other commodities are purchased and the ultimate recovery from customers of the costs in rates. On occasion, when the level of incurred costs for fuel and purchased power rises very dramatically, some
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of the Utility operating companies may agree to defer recovery of a portion of that period’s fuel and purchased power costs for recovery at a later date, which could increase the near-term working capital and borrowing requirements of those companies. The Utility operating companies also may experience, and in some instances have experienced, an increase in customer bill arrearages and bad debt expenses due to, among other reasons, increases in fuel and purchased power costs, especially in periods of economic decline or hardship. For a description of fuel and purchased power recovery mechanisms and information regarding the regulatory proceedings for fuel and purchased power cost recovery, see Note 2 to the financial statements.
The Utility operating companies are subject to economic risks associated with participation in the MISO markets and the allocation of transmission upgrade costs. The operation of the Utility operating companies’ transmission system pursuant to the MISO RTO tariff and their participation in the MISO RTO’s wholesale markets may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
On December 19, 2013, the Utility operating companies integrated into the MISO RTO. MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their owned and controlled generating facilities into the MISO resource adequacy construct (the annual Planning Resource Auction, discussed below), as well as the day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. The Utility operating companies are subject to economic risks associated with participation in the MISO markets and resource adequacy construct. MISO tariff rules and system conditions, including transmission congestion, could affect the Utility operating companies’ ability to sell capacity, energy, and/or ancillary services in certain regions and/or the economic value of such sales, or the cost of serving the Utility operating companies’ respective loads. MISO market rules may change or be interpreted in ways that cause additional cost and risk, including compliance risk.
The Utility operating companies participate in the MISO regional transmission planning process and are subject to risks associated with planning decisions that MISO makes in the exercise of control over the planning of the Utility operating companies’ transmission assets that are under MISO’s functional control. The Utility operating companies pay transmission rates that reflect the cost of transmission projects that the Utility operating companies do not own, which could increase cash or financing needs. Further, FERC policies and regulation addressing cost responsibility for transmission projects, including transmission projects to interconnect new generation facilities, may potentially give rise to cash and financing-related risks as well as result in upward pressure on the retail rates of the Utility operating companies, which, in turn, may result in adverse actions by the Utility operating companies’ retail regulators. In addition to the cash and financing-related risks arising from the potential additional cost allocation to the Utility operating companies from transmission projects of others or changes in FERC policies or regulation related to cost responsibility for transmission projects, there is a risk that the Utility operating companies’ business and financial position could be harmed as a result of lost investment opportunities and other effects that flow from an increased number of competitive projects being approved and constructed that are interconnected with their transmission systems.
Further, the terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets, the allocation of transmission upgrade costs, the MISO-wide allowed base rate of return on equity, and any required MISO-related charges and credits are subject to regulation by the FERC. The operation of the Utility operating companies’ transmission system pursuant to the MISO tariff and their participation in the MISO wholesale markets, and the resulting costs, may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
Moreover, the resource adequacy construct provided under the MISO tariff confers certain rights and imposes certain obligations upon load-serving entities, including the Utility operating companies, that are served
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from the transmission systems subject to MISO’s functional control, including the transmission facilities of the Utility operating companies. The MISO tariff provisions governing these rights and obligations are subject to change and have recently undergone significant changes, some of which are the subject of pending litigation and/or appeals. Due to their magnitude and the speed with which they have been implemented, these changes carry risk, including compliance risk, and may result in material additional costs being passed through to the Utility operating companies’ customers in retail rates, including but not limited to additional capacity costs incurred in the annual MISO Planning Resource Auction. Also, by virtue of the Utility operating companies’ participation in MISO and the design and terms of the MISO resource adequacy construct, other load-serving entities served by the Utility operating companies’ transmission assets, which are under MISO’s functional control, may be able to circumvent reasonable resource planning obligations and avoid, in whole or in part, the full cost of procuring the resources reasonably needed to reliably supply their respective loads. In particular, the design of the current MISO resource adequacy construct and the absence of a minimum capacity obligation in MISO create a risk of other load-serving entities engaging in “free ridership” through their strategy for participation in the MISO resource adequacy construct and energy and ancillary services markets – specifically, by using energy and ancillary services available from the Utility operating companies’ owned and controlled generating units without paying a reasonable share of the cost of the capacity required to provide such energy and ancillary services. As a result, there are a variety of risks to the Utility operating companies and their customers, including the risk of bearing additional costs for resources needed to ensure reliable service, the risk of reduced reliability and the enhanced risk of outages and lost sales which, because of the methodology for establishing cost of service rates, presents the risk of upward pressure on the Utility operating companies’ rates.
In addition, orders from each of the Utility operating companies’ respective retail regulators generally require that the Utility operating companies make periodic filings, or generally allow the retail regulator to direct the making of such filings, setting forth the results of analysis of the costs and benefits realized from MISO membership as well as the projected costs and benefits of continued membership in MISO and/or requesting approval of their continued membership in MISO. These filings have been submitted periodically by each of the Utility operating companies as required by their respective retail regulators, and the outcome of the resulting proceedings may affect the Utility operating companies’ continued membership in MISO.
The continued impacts of the COVID-19 pandemic and responsive measures taken on Entergy’s and its Utility operating companies’ business, results of operations, and financial condition are highly uncertain and cannot be predicted.
The global 2019 novel coronavirus pandemic continues to be an evolving situation and could lead to further disruption of the general economy, impacts on the customers of Entergy’s Utility operating companies, and disruption of the operations of Entergy’s subsidiaries, whether due to, among other things, the emergence or spread of new variants of COVID-19, precautionary or reactionary measures, market reactions or impacts, or supply chain constraints.
Entergy and its Utility operating companies experienced an increase in arrearages and bad debt expense due to non-payment by customers. The arrearages due to COVID-19 have begun to decline, although management cannot predict the timing of the completion of collections of such arrearages. While the Utility operating companies are working with regulators to ensure ultimate recovery for those and other COVID-19 related costs, the amount, method, and timing of such recovery is subject to approval by the retail regulators.
Entergy and its Registrant Subsidiaries also could experience, and in some cases have experienced, among other challenges that originated during or have been exacerbated by the COVID-19 pandemic: supply chain, vendor, and contractor disruptions, including shortages or delays in the availability of key components, parts, and supplies such as electronic components and solar panels; delays in completion of capital or other construction projects, maintenance, and other operations activities, including prolonged or delayed refueling and maintenance outages; delays in regulatory proceedings; workforce availability challenges, including from COVID-19 infections, health, or safety issues; increased storm recovery costs; increased cybersecurity risks as a result of many employees
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telecommuting; volatility in the credit or capital markets (and any related increased cost of capital or any inability to access the capital markets or draw on available credit facilities); or other adverse impacts on their ability to execute on business strategies and initiatives.
Although the economy has been recovering, another economic decline could adversely impact Entergy’s and the Utility operating companies’ liquidity and cash flows, including through declining sales, reduced revenues, delays in receipts of customer payments, or increased bad debt expense. The Utility operating companies also may experience regulatory outcomes that require them to postpone planned investment and otherwise reduce costs due to the impact of the COVID-19 pandemic on their customers, especially in an environment of higher inflation. In addition, if the COVID-19 pandemic or related impacts create additional disruptions or turmoil in the credit or financial markets, or adversely impact Entergy’s credit metrics or ratings, such developments could adversely affect its ability to access capital on favorable terms and continue to meet its liquidity needs or cause a decrease in the value of its defined benefit pension trust funds, as well as its nuclear decommissioning trust funds, all of which are highly uncertain and cannot be predicted.
Entergy cannot predict the extent or duration of the ongoing COVID-19 pandemic, the impact of new or existing variants of COVID-19, the effectiveness of mitigation efforts, further governmental responsive measures, or the extent of the effects or ultimate impacts on the global, national or local economy, the capital markets, or its customers, suppliers, operations, financial condition, results of operations, or cash flows.
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather, the impact on customer bills of permitted storm cost recovery, or the inability to securitize future storm restoration costs could have material effects on Entergy and its Utility operating companies.
Entergy’s and its Utility operating companies’ results of operations, liquidity, and financial condition can be materially affected by the destructive effects of severe weather. Severe weather can also result in significant outages for the customers of the Utility operating companies and, therefore, reduced revenues for the Utility operating companies during the period of the outages. A delay or failure in recovering amounts for storm restoration costs incurred, inability to securitize future storm restoration costs, or loss of revenues as a result of severe weather could have a material effect on Entergy and those Utility operating companies affected by severe weather, including lower credit ratings and, thus, higher costs for future debt issuances. The inability to recover losses either excluded by insurance or in excess of the insurance limits that can be secured economically also could have a material effect on Entergy and its Utility operating companies. In addition, the recovery of major storm restoration costs from customers could effectively limit our ability to make planned capital or other investments due to the impact of such storm cost recovery on customer bills, especially in a rising cost environment.
In August 2021, Hurricane Ida caused extensive damage to the Entergy distribution and, to a lesser extent, transmission systems across Louisiana, resulting in storm costs of $2.5 billion. Entergy Louisiana began recovering a portion of these costs through securitization financings in 2022. In January 2023 the LPSC issued orders finding prudent the costs incurred by Entergy Louisiana in responding to Hurricane Ida and allowing Entergy Louisiana to securitize the remaining $1.491 billion in such costs. Because such orders are not yet final and non-appealable (due to the forty-five day appeal period) and, further, because the bond rating and marketing process has yet to occur, there is an element of risk, and Entergy Louisiana is unable to predict with certainty the ultimate success of its recovery initiatives or the timing of such recovery.
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Weather, economic conditions, technological developments, and other factors may have a material impact on electricity and gas sales and otherwise materially affect the Utility operating companies’ results of operations and system reliability.
Temperatures above normal levels in the summer tend to increase electric cooling demand and revenues, and temperatures below normal levels in the winter tend to increase electric and gas heating demand and revenues. As a corollary, mild temperatures in either season tend to decrease energy usage and resulting revenues. Higher consumption levels coupled with seasonal pricing differentials typically cause the Utility operating companies to report higher revenues in the third quarter of the fiscal year than in the other quarters. Changing weather patterns and extreme weather conditions, including hurricanes or tropical storms, flooding events, or ice storms, the frequency or intensity of which may be exacerbated by climate change, may stress the Utility operating companies’ generation facilities and transmission and distribution systems, resulting in increased maintenance and capital costs (and potential increased financing needs), limits on their ability to meet peak customer demand, increased regulatory oversight, criticism or adverse publicity, and reduced customer satisfaction. These extreme conditions could have a material effect on the Utility operating companies’ financial condition, results of operations, and liquidity.
Entergy’s electricity sales volumes are affected by a number of factors including weather and economic conditions, trends in energy efficiency, new technologies, and self-generation alternatives, including the willingness and ability of large industrial customers to develop co-generation facilities that greatly reduce their grid demand. In addition, changes to regulatory policies, such as those that allow customers to directly access the market to procure wholesale energy or those that incentivize development and utilization of new, developing, or alternative sources of generation, could, and in some instances, have reduced sales, and other non-traditional procurements, such as virtual purchase power agreements, could, and in some instances have limited growth opportunities or reduced sales at the Utility operating companies. Some of these factors are inherently cyclical or temporary in nature, such as the weather or economic conditions, and rarely have a long-lasting effect on Entergy’s operating results. Others, such as the organic turnover of appliances and lighting and their replacement with more efficient ones and adoption of newer technologies, including smart thermostats, new building codes, distributed energy resources, energy storage, demand side management, and rooftop solar, are having a more permanent effect by reducing sales growth rates from historical norms. As a result of these emerging efficiencies and technologies, the Utility operating companies may lose customers or experience lower average use per customer in the residential and commercial classes, and continuing advances have the potential to further limit sales or sales growth in the future.
The Utility operating companies also may face competition from other companies offering products and services to Entergy’s customers. Electricity sales to industrial customers, in particular, benefit from steady economic growth and favorable commodity markets; however, industrial sales are sensitive to changes in conditions in the markets in which its customers operate. Negative changes in any of these or other factors, particularly sustained economic downturns or sluggishness, have the potential to result in slower sales growth or sales declines and increased bad debt expense, which could materially affect Entergy’s and the Utility operating companies’ results of operations, financial condition, and liquidity. The Utility operating companies also may not realize anticipated or expected growth in industrial sales from electrification opportunities to help such customers achieve their environmental and sustainability goals. This could occur because of changes in customers’ goals or business priorities, competition from other companies, or decisions by such customers to seek to achieve such goals through methods not offered by Entergy.
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Nuclear Operating, Shutdown, and Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)
Certain of the Utility operating companies and System Energy are expected to consistently operate their nuclear power plants at high capacity factors in order to be successful, and lower capacity factors could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Nuclear capacity factors significantly affect the results of operations of certain Utility operating companies and System Energy. Nuclear plant operations involve substantial fixed operating costs. Consequently, there is pressure on plant owners to operate nuclear power plants at higher capacity factors, though such operations always must be consistent with safety, reliability, and nuclear regulatory requirements. For the Utility operating companies that own nuclear plants, lower nuclear plant capacity factors can increase production costs by requiring the affected companies to generate additional energy, sometimes at higher costs, from their owned or contractually controlled facilities or purchase additional energy in the spot or forward markets in order to satisfy their supply needs.
Certain of the Utility operating companies and System Energy periodically shut down their nuclear power plants to replenish fuel. Plant maintenance and upgrades are often scheduled during such refueling outages. If refueling outages last longer than anticipated or if unplanned outages arise, Entergy’s and their results of operations, financial condition, and liquidity could be materially affected.
Outages at nuclear power plants to replenish fuel require the plant to be “turned off.” Refueling outages generally are planned to occur once every 18 to 24 months. Plant maintenance and upgrades are often scheduled during such planned outages, which may extend the planned outage duration beyond that required for only refueling activities. When refueling outages last longer than anticipated or a plant experiences unplanned outages, capacity factors decrease, and maintenance costs may increase.
Certain of the Utility operating companies and System Energy face risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication). These risks could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Based upon currently planned fuel cycles, Entergy’s nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable prices through most of 2027. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners. While there are a number of possible alternate suppliers that may be accessed to mitigate any supplier performance failure, the pricing of any such alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S. Market prices for nuclear fuel have been extremely volatile from time to time in the past and may be subject to increased volatility due to the imposition of tariffs, domestic purchase requirements or limitations on importation of uranium or uranium products from foreign countries, geopolitical conditions, or shifting trade arrangements between countries. Although Entergy’s nuclear fuel contract portfolio provides a degree of hedging against market risks for several years, costs for nuclear fuel in the future cannot be predicted with certainty due to normal inherent market uncertainties, and price changes could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.
Entergy’s ability to assure nuclear fuel supply also depends upon the performance and reliability of conversion, enrichment, and fabrication services providers. These service providers are fewer in number than uranium suppliers. For conversion and enrichment services, Entergy diversifies its supply by supplier and country and may take special measures to ensure a reliable supply of enriched uranium for fabrication into nuclear fuel. For fabrication services, each plant is dependent upon the performance of the fabricator of that plant’s nuclear fuel;
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therefore, Entergy relies upon additional monitoring, inspection, and oversight of the fabrication process to assure reliability and quality of its nuclear fuel. Certain of the suppliers and service providers are located in or dependent upon foreign countries, such as Russia, and international sanctions or tariffs impacting trade with such countries could further restrict the ability of such suppliers or service providers to continue to supply fuel or provide such services at acceptable prices or at all. The inability of such suppliers or service providers to perform such obligations could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.
Certain of the Utility operating companies and System Energy face the risk that the NRC will change or modify its regulations, suspend or revoke their licenses, or increase oversight of their nuclear plants, which could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Under the Atomic Energy Act and Energy Reorganization Act, the NRC regulates the operation of nuclear power plants. The NRC may modify, suspend, or revoke licenses, shut down a nuclear facility and impose civil penalties for failure to comply with the Atomic Energy Act, related regulations, or the terms of the licenses for nuclear facilities. Interested parties may also intervene which could result in prolonged proceedings. A change in the Atomic Energy Act, other applicable statutes, or the applicable regulations or licenses, or the NRC’s interpretation thereof, may require a substantial increase in capital expenditures or may result in increased operating or decommissioning costs and could materially affect the results of operations, liquidity, or financial condition of Entergy, certain of the Utility operating companies, or System Energy. A change in the classification of a plant owned by one of these companies under the NRC’s Reactor Oversight Process, which is the NRC’s program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response, also could cause the owner of the plant to incur material additional costs as a result of the increased oversight activity and potential response costs associated with the change in classification. For additional information concerning the current classification of the plants owned by Entergy Arkansas, Entergy Louisiana, and System Energy, see “Regulation of Entergy’s Business- Regulation of the Nuclear Power Industry - NRC Reactor Oversight Process” in Part I, Item 1.
Events at nuclear plants owned by one of these companies, as well as those owned by others, may lead to a change in laws or regulations or the terms of the applicable licenses, or the NRC’s interpretation thereof, or may cause the NRC to increase oversight activity or initiate actions to modify, suspend, or revoke licenses, shut down a nuclear facility, or impose civil penalties. As a result, if an incident were to occur at any nuclear generating unit, whether an Entergy nuclear generating unit or not, it could materially affect the financial condition, results of operations, and liquidity of Entergy, certain of the Utility operating companies, or System Energy.
Certain of the Utility operating companies and System Energy are exposed to risks and costs related to operating and maintaining their nuclear power plants, and their failure to maintain operational efficiency at their nuclear power plants could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
The nuclear generating units owned by certain of the Utility operating companies and System Energy began commercial operations in the 1970s-1980s. Older equipment may require more capital expenditures to keep each of these nuclear power plants operating safely and efficiently. This equipment is also likely to require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages, or any unanticipated capital expenditures, could result in increased costs, some of which costs may not be fully recoverable by these Utility operating companies and System Energy in regulatory proceedings should there be a determination of imprudence. Operations at any of the nuclear generating units owned and operated by Entergy’s subsidiaries could degrade to the point where the affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. A decision may be made to close a unit rather than incur the expense of restarting it or returning the unit to full capacity. For these Utility operating companies and System Energy, this could result in certain costs being stranded
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and potentially not fully recoverable in regulatory proceedings. In addition, the operation and maintenance of Entergy’s nuclear facilities require the commitment of substantial human resources that can result in increased costs.
Moreover, Entergy is becoming more dependent on fewer suppliers for key parts of Entergy’s nuclear power plants that may need to be replaced or refurbished, and in some cases, parts are no longer available and have to be reverse-engineered for replacement. In addition, certain major parts have long lead-times to manufacture if an unplanned replacement is needed. This dependence on a reduced number of suppliers and long lead-times on certain major parts for unplanned replacements could result in delays in obtaining qualified replacement parts and, therefore, greater expense for Entergy, certain of the Utility operating companies, and System Energy.
The costs associated with the storage of the spent nuclear fuel of certain of the Utility operating companies and System Energy, as well as the costs of and their ability to fully decommission their nuclear power plants, could be significantly affected by the timing of the opening of a spent nuclear fuel disposal facility, as well as interim storage and transportation requirements.
Certain of the Utility operating companies and System Energy incur costs for the on-site storage of spent nuclear fuel. The approval of a license for a national repository for the disposal of spent nuclear fuel, such as the one proposed for Yucca Mountain, Nevada, or any interim storage facility, and the timing of such facility opening, will significantly affect the costs associated with on-site storage of spent nuclear fuel. For example, while the DOE is required by law to proceed with the licensing of Yucca Mountain and, after the license is granted by the NRC, to construct the repository and commence the receipt of spent fuel, the NRC licensing of the Yucca Mountain repository is effectively at a standstill. These actions are prolonging the time before spent fuel is removed from Entergy’s plant sites. Because the DOE has not accomplished its objectives, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts, and Entergy has sued the DOE for such breach. Furthermore, Entergy is uncertain as to when the DOE will commence acceptance of spent fuel from its facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at the companies’ nuclear sites and maintenance costs on existing storage facilities, including aging management of fuel storage casks, may increase. The costs of on-site storage are also affected by regulatory requirements for such storage. In addition, the availability of a repository or other off-site storage facility for spent nuclear fuel may affect the ability to fully decommission the nuclear units and the costs relating to decommissioning. For further information regarding spent fuel storage, see the “Critical Accounting Estimates – Nuclear Decommissioning Costs – Spent Fuel Disposal” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy and Note 8 to the financial statements.
Certain of the Utility operating companies and System Energy may be required to pay substantial retrospective premiums imposed under the Price-Anderson Act and/or by Nuclear Electric Insurance Limited (NEIL) in the event of a nuclear incident, and losses not covered by insurance could have a material effect on Entergy’s and their results of operations, financial condition, or liquidity.
Accidents and other unforeseen problems at nuclear power plants have occurred both in the United States and elsewhere. As required by the Price-Anderson Act, the Utility operating companies and System Energy carry the maximum available amount of primary nuclear off-site liability insurance with American Nuclear Insurers, which is $450 million for each operating site. Claims for any nuclear incident exceeding that amount are covered under Secondary Financial Protection. The Price-Anderson Act limits each reactor owner’s public liability (off-site) for a single nuclear incident to the payment of retrospective premiums into a secondary insurance pool, which is referred to as Secondary Financial Protection, up to approximately $137.6 million per reactor. With 96 reactors currently participating, this translates to a total public liability cap of approximately $13 billion per incident. The limit is subject to change to account for the effects of inflation, a change in the primary limit of insurance coverage, and changes in the number of licensed reactors. As a result, in the event of a nuclear incident that causes damages (off-site) in excess of the primary insurance coverage, each owner of a nuclear plant reactor, including Entergy’s Utility operating companies and System Energy, regardless of fault or proximity to the incident, will be required to
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pay a retrospective premium, equal to its proportionate share of the loss in excess of the primary insurance level, up to a maximum of approximately $137.6 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $688 million). The retrospective premium payment is currently limited to approximately $21 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $137.6 million cap.
NEIL is a utility industry mutual insurance company, owned by its members, including the Utility operating companies and System Energy. NEIL provides onsite property and decontamination coverage. All member plants could be subject to an annual assessment (retrospective premium of up to 10 times current annual premium for all policies) should the NEIL surplus (reserve) be significantly depleted due toinsured losses. As of January 1, 2023, the maximum annual assessment amounts total approximately $70 million for the Utility plants. Retrospective premium insurance available through NEIL’s reinsurance treaty can cover the potential assessments.
As mentioned above, as an owner of nuclear power plants, Entergy participates in industry self-insurance programs and could be liable to fund claims should a plant owned by a different company experience a major event. Any resulting liability from a nuclear accident may exceed the applicable primary insurance coverage and require contribution of additional funds through the industry-wide program that could significantly affect the results of operations, financial condition, or liquidity of Entergy, certain of the Utility operating companies, or System Energy.
The decommissioning trust fund assets for the nuclear power plants owned by certain of the Utility operating companies and System Energy may not be adequate to meet decommissioning obligations if market performance and other changes decrease the value of assets in the decommissioning trusts, if one or more of Entergy’s nuclear power plants is retired earlier than the anticipated shutdown date, if the plants cost more to decommission than estimated, or if current regulatory requirements change, which then could require significant additional funding.
Owners of nuclear generating plants have an obligation to decommission those plants. Certain of the Utility operating companies and System Energy maintain decommissioning trust funds for this purpose. Certain of the Utility operating companies and System Energy collect funds from their customers, which are deposited into the trusts covering the units operated for or on behalf of those companies. Those rate collections, as adjusted from time to time by rate regulators, are generally based upon operating license lives and trust fund balances as well as estimated trust fund earnings and decommissioning costs. Assets in these trust funds are subject to market fluctuations, will yield uncertain returns that may fall below projected return rates, and may result in losses resulting from the recognition of impairments of the value of certain securities held in these trust funds.
Under NRC regulations, nuclear plant owners are permitted to project the NRC-required decommissioning amount, based on an NRC formula or a site-specific estimate, and the amount that will be available in each nuclear power plant’s decommissioning trusts combined with any other decommissioning financial assurances in place. The projections are made based on the operating license expiration date and the mid-point of the subsequent decommissioning process, or the anticipated actual completion of decommissioning if a site-specific estimate is used. If the projected amount of each individual plant’s decommissioning trusts exceeds the NRC-required decommissioning amount, then its NRC license termination decommissioning obligations are considered to be funded in accordance with NRC regulations. If the projected costs do not sufficiently reflect the actual costs required to decommission these nuclear power plants, or funding is otherwise inadequate, or if the formula, formula inputs, or site-specific estimate is changed to require increased funding, additional resources or commitments would be required. Furthermore, depending upon the level of funding available in the trust funds, the NRC may not permit the trust funds to be used to pay for related costs such as the management of spent nuclear fuel that are not included in the NRC’s formula. The NRC may also require a plan for the provision of separate funding for spent fuel management costs.
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Further, federal or state regulatory changes, including mandated increases in decommissioning funding or changes in the methods or standards for decommissioning operations, may also increase the funding requirements of, or accelerate the timing for funding of, the obligations related to the decommissioning of the nuclear generating plant owned by certain of the Utility operating companies or System Energy or may restrict the decommissioning-related costs that can be paid from the decommissioning trusts. Such changes also could result in the need for additional contributions to decommissioning trusts, or the posting of parent guarantees, letters of credit, or other surety mechanisms. As a result, under any of these circumstances, the results of operations, liquidity, and financial condition of Entergy, certain of the Utility operating companies, or System Energy could be materially affected.
An early plant shutdown (either generally or relative to current expectations), poor investment results, or higher than anticipated decommissioning costs (including as a result of changing regulatory requirements) could cause trust fund assets to be insufficient to meet the decommissioning obligations, with the result that certain of the Utility operating companies or System Energy may be required to provide significant additional funds or credit support to satisfy regulatory requirements for decommissioning, which, with respect to these Utility operating companies or System Energy, may not be recoverable from customers in a timely fashion or at all.
For further information regarding nuclear decommissioning costs, management’s decision to exit the merchant power business, and the impairment charges that resulted from such decision, see the “Critical Accounting Estimates- Nuclear Decommissioning Costs” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy, the “Entergy Wholesale Commodities Exit from the Merchant Power Business” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries, and Notes 9, 14, and 16 to the financial statements.
New or existing safety concerns regarding operating nuclear power plants and nuclear fuel could lead to restrictions upon the operation and decommissioning of Entergy’s nuclear power plants.
New and existing concerns are being expressed in public forums about the safety of nuclear generating units and nuclear fuel. These concerns have led to, and may continue to lead to, various proposals to federal regulators and governing bodies in some localities where Entergy’s subsidiaries own nuclear generating units for legislative and regulatory changes that might lead to the shutdown of nuclear units, additional requirements or restrictions related to spent nuclear fuel on-site storage and eventual disposal, or other adverse effects on owning, operating, and decommissioning nuclear generating units. Entergy vigorously responds to these concerns and proposals. If any of the existing proposals, or any proposals that may arise in the future with respect to legislative and regulatory changes, become effective, they could have a material effect on Entergy’s results of operations and financial condition.
General Business
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Entergy and its Registrant Subsidiaries depend on access to the capital markets and, at times, may face potential liquidity constraints, which could make it more difficult to handle future contingencies such as natural disasters or substantial increases in gas and fuel prices. Disruptions in the capital and credit markets may adversely affect Entergy’s and its subsidiaries’ ability to meet liquidity needs, access capital and operate and grow their businesses, and the cost of capital.
Entergy’s business is capital intensive and dependent upon its ability to access capital at reasonable rates and other terms. At times there are also spikes in the price for natural gas and other commodities that increase the liquidity requirements of the Utility operating companies. In addition, Entergy’s and the Registrant Subsidiaries’ liquidity needs could significantly increase in the event of a hurricane or other weather-related or unforeseen disaster similar to that experienced in Entergy’s service area with Hurricane Katrina and Hurricane Rita in 2005,
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Hurricane Gustav and Hurricane Ike in 2008, Hurricane Isaac in 2012, Hurricane Laura, Hurricane Delta, and Hurricane Zeta in 2020, and Winter Storm Uri and Hurricane Ida in 2021. The occurrence of one or more contingencies, including an adverse decision or a delay in regulatory recovery of fuel or purchased power costs or storm restoration costs, an acceleration of payments or decreased credit lines, less cash flow from operations than expected, changes in regulation or governmental policy (including tax and trade policy), or other unknown events, could cause the financing needs of Entergy and its subsidiaries to increase. In addition, accessing the debt capital markets more frequently in these situations may result in an increase in leverage. Material leverage increases could negatively affect the credit ratings of Entergy, the Utility operating companies, and System Energy, which in turn could negatively affect access to the capital markets.
The inability to raise capital on favorable terms, particularly during times of high interest rates, and uncertainty or reduced liquidity in the capital markets, could negatively affect Entergy and its subsidiaries’ ability to maintain and to expand their businesses. Access to capital markets could be restricted and/or borrowing costs could be increased due to certain sources of debt and equity capital being unwilling to invest in offerings to fund fossil fuel projects or companies that are impacted by extreme weather events, that rely on fossil fuels, or that are impacted by risks related to climate change. Factors beyond Entergy’s control may create uncertainty that could increase its cost of capital or impair its ability to access the capital markets, including the ability to draw on its bank credit facilities. These factors include depressed economic conditions, a recession, increasing interest rates, inflation, sanctions, trade restrictions, political instability, war, terrorism, and extreme volatility in the debt, equity, or credit markets. Entergy and its subsidiaries are unable to predict the degree of success they will have in renewing or replacing their credit facilities as they come up for renewal. Moreover, the size, terms, and covenants of any new credit facilities may not be comparable to, and may be more restrictive than, existing facilities. If Entergy and its subsidiaries are unable to access the credit and capital markets on terms that are reasonable, they may have to delay raising capital, issue shorter-term securities, and/or bear an unfavorable cost of capital, which, in turn, could impact their ability to grow their businesses, decrease earnings, significantly reduce financial flexibility, and/or limit Entergy Corporation’s ability to sustain its current common stock dividend level.
A downgrade in Entergy’s or its Registrant Subsidiaries’ credit ratings could negatively affect Entergy’s and its Registrant Subsidiaries’ ability to access capital or the cost of such capital and/or could require Entergy or its subsidiaries to post collateral, accelerate certain payments, or repay certain indebtedness.
There are a number of factors that rating agencies evaluate to arrive at credit ratings for each of Entergy and the Registrant Subsidiaries, including each Registrant Subsidiary’s regulatory framework, ability to recover costs and earn returns, storm risk exposure, diversification, and financial strength and liquidity. If one or more rating agencies downgrade Entergy’s or any of the Registrant Subsidiaries’ ratings, particularly below investment grade, borrowing costs would increase, the potential pool of investors and funding sources would likely decrease, and cash or letter of credit collateral demands may be triggered by the terms of a number of commodity contracts, leases, and other agreements.
Most of Entergy’s and its subsidiaries’ suppliers and counterparties require sufficient creditworthiness to enter into transactions. If Entergy’s or the Registrant Subsidiaries’ ratings decline, particularly below investment grade, or if certain counterparties believe Entergy or the Utility operating companies are losing creditworthiness and demand adequate assurance under fuel, gas, and purchased power contracts, the counterparties may require posting of collateral in cash or letters of credit, prepayment for fuel, gas or purchased power or accelerated payment, or counterparties may decline business with Entergy or its subsidiaries.
Entergy or its Registrant Subsidiaries may be materially adversely affected by negative publicity or the inability to meet its stated goals or commitments, among other potential causes.
As with any company, Entergy’s and its Registrant Subsidiaries’ reputations are an important element of their ability to effectively conduct their business. Entergy’s and its Registrant Subsidiaries’ reputations could be harmed by a variety of factors, including: failure of a generating asset or supporting infrastructure; failure to restore
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power after a hurricane or other severe weather event in a manner perceived as timely by regulators or customers; the incurrence of storm restoration costs perceived as excessive by regulators or customers; failure to effectively manage land and other natural resources; real or perceived violations of environmental regulations, including those related to climate change; real or perceived issues with Entergy’s safety culture or work environment; inability to meet their climate or human capital strategy goals; inability to keep their electricity rates stable; involvement in a class-action or other high-profile lawsuit; significant delays in construction projects; occurrence of or responses to cyber attacks or security vulnerabilities; acts or omissions of Entergy management or acts or omissions of a contractor or other third-party working with or for Entergy or its Registrant Subsidiaries, which actually or perceivably reflect negatively on Entergy or its Registrant Subsidiaries; measures taken to offset reductions in demand or to supply rising demand; a significant dispute with one of Entergy’s or its Registrant Subsidiaries’ customers or other stakeholders; or negative political and public sentiment resulting in a significant amount of adverse press coverage and other adverse statements affecting Entergy or its Registrant Subsidiaries.
Addressing any adverse publicity or regulatory scrutiny is time consuming and expensive and, regardless of the factual basis for the assertions being made (or lack thereof), can have a negative impact on the reputations of Entergy or its Registrant Subsidiaries, on the morale and performance of their employees, and on their relationships with their respective regulators, customers, and commercial counterparties. Adverse publicity or regulatory scrutiny may also have a negative impact on Entergy or its Registrant Subsidiaries’ ability to take timely advantage of various business or market opportunities.
Deterioration in Entergy’s or its Registrant Subsidiaries’ reputations may harm Entergy’s or its Registrant Subsidiaries’ relationships with their customers, regulators, and other stakeholders, may increase their cost of doing business, may interfere with its ability to attract and retain a qualified, inclusive, and diverse workforce, may impact Entergy’s or its Registrant Subsidiaries’ ability to raise debt capital, and may potentially lead to the enactment of new laws and regulations, or the modification of existing laws and regulations, that negatively affect the way Entergy or its Registrant Subsidiaries conduct their business, or may have a material adverse effect on their financial condition and results of operations.
Recent U.S. tax legislation may materially adversely affect Entergy’s financial condition, results of operations, and cash flows.
The Tax Cuts and Jobs Act of 2017 and CARES Act of 2020 significantly changed the U.S. Internal Revenue Code, including taxation of U.S. corporations, by, among other things, reducing the federal corporate income tax rate, limiting interest deductions, and altering the expensing of capital expenditures. The Inflation Reduction Act of 2022 further significantly changed the U.S. Internal Revenue Code by, among other things, enacting a new corporate alternative minimum tax and expanding federal tax credits for clean energy production. The interpretive guidance issued by the IRS and state tax authorities may be inconsistent with Entergy’s own interpretation and the legislation could be subject to amendments, which could lessen or increase certain impacts of the legislation. Further, changes in tax legislation or guidance, or uncertainties regarding interpretation of such tax legislation or guidance, could impact interpretation of and negotiations around certain contractual arrangements with counterparties, which could result in unfavorable changes to such arrangements or delays. In addition, the retail regulatory treatment of the expanded tax credits and corporate alternative minimum tax included in the Inflation Reduction Act of 2022 could materially impact Entergy’s future cash flows, and this legislation could result in unintended consequences not yet identified that could have a material adverse impact on Entergy’s financial results and future cash flows.
Based on initial IRS guidance and current internal forecasts, Entergy and the Registrant Subsidiaries may become subject to the corporate alternative minimum tax included in the Inflation Reduction Act of 2022 beginning in the next two to three years.
The tax rate decrease included in the Tax Cuts and Jobs Act required Entergy to record a regulatory liability for income taxes payable to customers. Such regulatory liability for income taxes is described in Note 3 to the
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financial statements. Depending on the outcome of IRS examinations or tax positions and elections that Entergy may make, Entergy and the Registrant Subsidiaries may be required to record additional charges or credits to income tax expense.
See Note 3 to the financial statements for discussion of the effects of the Tax Cuts and Jobs Act on 2022, 2021, and 2020 results of operations and financial condition, the provisions of the Tax Cuts and Jobs Act, and the uncertainties associated with accounting for the Tax Cuts and Jobs Act, and Note 2 to the financial statements for discussion of the regulatory proceedings that have considered the effects of the Tax Cuts and Jobs Act. For further discussion of the effects of the Inflation Reduction Act of 2022, see the “Income Tax Legislation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 3 to the financial statements.
Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy’s and the Registrant Subsidiaries’ results of operations, financial condition, and liquidity.
Entergy and its subsidiaries make judgments regarding the potential tax effects of various transactions and results of operations to estimate their obligations to taxing authorities. These tax obligations include income, franchise, real estate, sales and use, and employment-related taxes. These judgments include provisions for potential adverse outcomes regarding tax positions that have been taken. Entergy and its subsidiaries also estimate their ability to utilize tax benefits, including those in the form of carryforwards for which the benefits have already been reflected in the financial statements. Changes in federal, state, or local tax laws or interpretive guidance relating thereto, adverse tax audit results or adverse tax rulings on positions taken by Entergy and its subsidiaries could negatively affect Entergy’s and the Registrant Subsidiaries’ results of operations, financial condition, and liquidity. The intended and unintended consequences of recently enacted legislation could have a material adverse impact on Entergy’s financial results and future cash flows. For further information regarding Entergy’s income taxes, see Note 3 to the financial statements.
Entergy and its subsidiaries’ ability to successfully execute on their business strategies, including their ability to complete strategic transactions, is subject to significant risks, and, as a result, they may be unable to achieve some or all of the anticipated results of such strategies, which could materially affect their future prospects, results of operations, and benefits that they anticipate from such transactions.
Entergy and its subsidiaries’ future prospects and results of operations significantly depend on their ability to successfully implement their business strategies, including achieving Entergy’s climate goals and commitments, which are subject to business, regulatory, economic, and other risks and uncertainties, many of which are beyond their control. As a result, Entergy and its subsidiaries may be unable to fully achieve the anticipated results of such strategies.
Additionally, Entergy and its subsidiaries have pursued and may continue to pursue strategic transactions including merger, acquisition, divestiture, joint venture, restructuring, or other strategic transactions. For example, a significant portion of Entergy’s utility business plan over the next several years includes the construction and/or purchase of a variety of solar facilities. These or other transactions and plans are or may become subject to regulatory approval and other material conditions or contingencies, including increased costs or delays resulting from supply chain issues. The failure to complete these transactions or plans or any future strategic transaction successfully or on a timely basis could have an adverse effect on Entergy’s or its subsidiaries’ financial condition or results of operations and the market’s perception of Entergy’s ability to execute its strategy. Further, these transactions, and any completed or future strategic transactions, involve substantial risks, including the following:
•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;
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•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 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, 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.
Entergy and its subsidiaries may not be successful in managing these or any other significant risks that they may encounter in acquiring or divesting a business, or engaging in other strategic transactions, which could have a material effect on their business, financial condition, or results of operations.
The completion of capital projects, including the construction of power generation facilities, and other capital improvements, involve substantial risks. Should such efforts be unsuccessful, the financial condition, results of operations, or liquidity of Entergy and the Utility operating companies could be materially affected.
Entergy’s and the Utility operating companies’ ability to complete capital projects, including the construction of power generation facilities, or make other capital improvements, such as transmission and distribution infrastructure replacements or upgrades, in a timely manner and within budget is contingent upon many variables and subject to substantial risks. These variables include, but are not limited to, project management expertise, escalating costs for materials, labor, and environmental compliance, reliance on suppliers for timely and satisfactory performance, continued pandemic-related delays and cost increases, and supply chains and material constraints, including those that may result from major storm events, both within and outside of Entergy’s service area. Delays in obtaining permits, challenges in securing sufficient land for the siting of solar panels, shortages in materials and qualified labor, levels of public support or opposition, suppliers and contractors not performing as expected or required under their contracts and/or experiencing financial problems that inhibit their ability to fulfill their obligations under contracts, changes in the scope and timing of projects, poor quality initial cost estimates from contractors, the inability to raise capital on favorable terms, changes in commodity prices affecting revenue, fuel costs, or materials costs, downward changes in the economy, changes in law or regulation, including environmental compliance requirements, further direct and indirect trade and tariff issues, including those associated with imported solar panels, supply chain delays or disruptions, and other events beyond the control of the Utility operating companies may occur that may materially affect the schedule, cost, and performance of these projects. If these projects or other capital improvements are significantly delayed or become subject to cost overruns or cancellation, Entergy and the Utility operating companies could incur additional costs and termination payments or face increased risk of potential write-off of the investment in the project. In addition, the Utility operating companies could be exposed to higher costs and market volatility, which could affect cash flow and cost recovery, should their respective regulators decline to approve the construction of the project or new generation needed to meet the reliability needs of customers at the lowest reasonable cost.
For further information regarding capital expenditure plans and other uses of capital in connection with capital projects, including the potential construction and/or purchase of additional generation supply sources within the Utility operating companies’ service areas, see the “Capital Expenditure Plans and Other Uses of Capital” section of Management’s Financial Discussion and Analysis for Entergy and each of the Registrant Subsidiaries.
Failure to attract, retain and manage an appropriately qualified workforce could negatively affect Entergy or its subsidiaries’ results of operations.
Entergy relies on a large and changing workforce of team members, including employees, contractors, and temporary staffing. Certain factors, such as an aging workforce, mismatching of skill sets, failing to appropriately
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anticipate future workforce needs, workforce impacts from public health concerns such as the COVID-19 pandemic and responsive measures, challenges competing with other employers offering fully remote work options, rising salary and other labor costs, or the unavailability of contract resources, may lead to operating challenges and increased costs. The challenges include inability to attract or retain talent, lack of resources, loss of knowledge base, and the time required for skill development. In this case, costs, including costs for contractors to replace employees, productivity costs, and safety costs, may increase. Failure to hire and adequately train replacement employees, or the future availability and cost of contract labor, may adversely affect the ability to manage and operate the business, especially considering the workforce needs associated with nuclear generation facilities and new skills required to develop and operate a modernized, technology-enabled, and lower carbon power grid. If Entergy and its subsidiaries are unable to successfully attract, retain, and manage an appropriately qualified workforce, their results of operations, financial position, and cash flows could be negatively affected.
Entergy and Entergy’s subsidiaries, including the Utility operating companies and System Energy, may incur substantial costs to fulfill their obligations related to environmental and other matters.
The businesses in which Entergy’s subsidiaries, including the Utility operating companies and System Energy, operate are subject to extensive environmental regulation by local, state, and federal authorities. These laws and regulations affect the manner in which the Utility operating companies and System Energy conduct their operations and make capital expenditures. These laws and regulations also affect how Entergy’s subsidiaries, including the Utility operating companies and System Energy, manage air emissions, discharges to water, wetlands impacts, solid and hazardous waste storage and disposal, cooling and service water intake, the protection of threatened and endangered species, certain migratory birds and eagles, hazardous materials transportation, and similar matters. Federal, state, and local authorities continually revise these laws and regulations, and the laws and regulations are subject to judicial interpretation and to the permitting and enforcement discretion vested in the implementing agencies. Developing and implementing plans for facility compliance with these requirements can lead to capital, personnel, and operation and maintenance expenditures. Violations of these requirements can subject the Utility operating companies and System Energy to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, remediation and clean-up costs, civil penalties, and exposure to third parties’ claims for alleged health or property damages or for violations of applicable permits or standards. In addition, Entergy and its subsidiaries, including the Utility operating companies and System Energy, are subject to potential liability under these laws for the costs of remediation of environmental contamination of property now or formerly owned or operated by the Utility operating companies and System Energy and of property potentially contaminated by hazardous substances they generate. The Utility operating companies currently are involved in proceedings relating to sites where hazardous substances have been released and may be subject to additional proceedings in the future. Entergy’s subsidiaries, including the Utility operating companies and System Energy, have incurred and expect to incur significant costs related to environmental compliance.
Emissions of nitrogen and sulfur oxides, mercury, particulates, greenhouse gases, and other regulated emissions from generating plants potentially are subject to increased regulation, controls, and mitigation expenses. In addition, existing environmental regulations and programs promulgated by the EPA often are challenged legally, or are revised or withdrawn by the EPA, sometimes resulting in large-scale changes to anticipated regulatory regimes and the resulting need to shift course, both operationally and economically, depending on the nature of the changes. Risks relating to global climate change, initiatives to regulate, or otherwise compel reductions of greenhouse gas emissions, and water availability issues are discussed below.
Entergy and its subsidiaries may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals, or if Entergy and its subsidiaries fail to obtain, maintain, or comply with any such approval, the operation of its facilities could be stopped or become subject to additional costs. For further information regarding environmental regulation and environmental matters, including Entergy’s response to climate change, see the “Regulation of Entergy’s Business– Environmental Regulation” section of Part I, Item 1.
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The Utility operating companies, System Energy, and Entergy’s non-regulated operations may incur substantial costs related to reliability standards.
Entergy’s business is subject to extensive and mandatory reliability standards. Such standards, which are established by the NERC, the SERC, and other regional enforcement entities, are approved by the FERC and frequently are reviewed, amended, and supplemented. Failure to comply with such standards could result in the imposition of fines or civil penalties, and potential exposure to third party claims for alleged violations of such standards. The standards, as well as the laws and regulations that govern them, are subject to judicial interpretation and to the enforcement discretion vested in the implementing agencies. In addition to exposure to civil penalties and fines, the Utility operating companies have incurred and expect to incur significant costs related to compliance with new and existing reliability standards, including costs associated with the Utility operating companies’ transmission system and generation assets. In addition, the retail regulators of the Utility operating companies possess the jurisdiction, and in some cases have exercised such jurisdiction, to impose standards governing the reliable operation of the Utility operating companies’ distribution systems, including penalties if these standards are not met. The changes to the reliability standards applicable to the electric power industry are ongoing, and Entergy cannot predict the ultimate effect that the reliability standards will have on its Utility and Entergy’s non-regulated operations.
Environmental and regulatory obligations intended to combat the effects of climate change, including by compelling greenhouse gas emission reductions or reporting, increasing clean or renewable energy requirements, or placing a price on greenhouse gas emissions, or the achievement of voluntary climate commitments could materially affect the financial condition, results of operations, and liquidity of Entergy and Entergy’s subsidiaries, including the Utility operating companies and System Energy.
In an effort to address climate change concerns, some federal, state, and local authorities are calling for additional laws and regulations aimed at known or suspected causes of climate change. For example, the EPA, various environmental interest groups, and other organizations have focused considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. The EPA has promulgated regulations controlling greenhouse gas emissions from certain vehicles, and from new, existing, and significantly modified stationary sources of emissions, including electric generating units. Such regulations continue to evolve. As examples of state action, in the Northeast, the Regional Greenhouse Gas Initiative establishes a cap on CO2 emissions from electric power plants and requires generators to purchase emission permits to cover their CO2 emissions, and a similar program has been developed in California. In Louisiana, the Office of the Governor announced the creation of a Climate Initiatives Task Force and issued an executive order that established a path to net-zero emissions by 2050 while the City Council of New Orleans passed a renewable and clean portfolio standard that sets a goal of net-zero emissions by 2040 and absolute zero emissions by 2050. The impact that continued changes in the governmental response to climate change risk and any judicial interpretation thereof will have on existing and pending environmental laws and regulations related to greenhouse gas emissions currently is unclear.
Developing and implementing plans for compliance with greenhouse gas emissions reduction or reporting or clean/renewable energy requirements, or for achieving voluntary climate commitments can lead to additional capital, personnel, and operation and maintenance expenditures and could significantly affect the economic position of existing facilities and proposed projects. The operations of low or non-emitting generating units (such as nuclear units) at lower than expected capacity factors could require increased generation from higher emitting units, thus increasing Entergy’s greenhouse gas emission rate. Moreover, long-term planning to meet environmental requirements can be negatively impacted and costs may increase to the extent laws and regulations change prior to full implementation. These requirements could, in turn, lead to changes in the planning or operations of balancing authorities or organized markets in areas where Entergy’s subsidiaries, including the Utility operating companies or System Energy, do business. Violations of such requirements may subject the Utility operating companies to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, civil penalties, and exposure to third parties’ claims for alleged health
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or property damages or for violations of applicable permits or standards. Further, real or perceived violations of environmental regulations, including those related to climate change, or inability to meet Entergy’s voluntary climate commitments, could adversely impact Entergy’s reputation or inhibit Entergy’s ability to pursue its decarbonization objectives. To the extent Entergy believes any of these costs are recoverable in rates, however, additional material rate increases for customers could be resisted by Entergy’s regulators and, in extreme cases, Entergy’s regulators might attempt to deny or defer timely recovery of these costs.
Future changes in regulation or policies governing the reporting or emission of CO2 and other greenhouse gases or mix of generation sources could (i) result in significant additional costs to Entergy’s Utility operating companies, their suppliers, or customers, (ii) make some of Entergy’s electric generating units uneconomical to maintain or operate, (iii) result in the early retirement of generation facilities and stranded costs if Entergy’s Utility operating companies are unable to fully recover the costs and investment in generation, and (iv) increase the difficulty that Entergy and its Utility operating companies have with obtaining or maintaining required environmental regulatory approvals, each of which could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries. In addition, lawsuits have occurred or are reasonably expected against emitters of greenhouse gases alleging that these companies are liable for personal injuries and property damage caused by climate change. These lawsuits may seek injunctive relief, monetary compensation, and punitive damages.
In March 2019, Entergy voluntarily set a climate goal to achieve a 50 percent reduction in its carbon emission rate from the year 2000 by 2030. In September 2020, Entergy voluntarily committed to achieving net zero carbon emissions by 2050. In November 2022, Entergy voluntarily set a climate goal to achieve 50 percent carbon-free energy capacity by 2030. Risks to achieving the 2030 and 2050 goals include, among other things, the ability to execute on renewable resource plans, regulatory approvals, customer demand for carbon-free energy, potential tariffs, carbon policy and regulation, and supply chain costs and constraints. Technology research and development, innovation, and advancements in carbon-free generation are also critical to Entergy’s ability to achieve its 2050 commitment. Entergy cannot predict the ultimate impact of achieving these objectives, or the various implementation aspects, on its system reliability, or its results of operations, financial condition, or liquidity.
The physical effects of climate change could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries.
Potential physical risks from climate change include an increase in sea level, wind and storm surge damages, more frequent or intense hurricanes and wildfires, wetland and barrier island erosion, flooding and changes in weather conditions (such as increases in precipitation, drought, or changes in average temperatures), and potential increased impacts of extreme weather conditions or storms. Entergy’s subsidiaries own assets in, and serve, communities that are at risk from sea level rise, changes in weather conditions, storms, and loss of the protection offered by coastal wetlands. A significant portion of the nation’s oil and gas infrastructure is located in these areas and susceptible to storm damage that could be aggravated by the physical impacts of climate change, which could give rise to fuel supply interruptions and price spikes. Entergy and its subsidiaries also face the risk that climate change could impact the availability and quality of water supplies necessary for operations.
These and other physical changes could result in changes in customer demand, increased costs associated with repairing and maintaining generation facilities and transmission and distribution systems resulting in increased maintenance and capital costs (and potential increased financing needs), limits on the Entergy system’s ability to meet peak customer demand, more frequent and longer lasting outages, increased regulatory oversight, criticism or adverse publicity, and lower customer satisfaction. Also, to the extent that climate change adversely impacts the economic health of a region or results in energy conservation or demand side management programs, it may adversely impact customer demand and revenues. Such physical or operational risks could have a material effect on Entergy’s and its subsidiaries’ financial condition, results of operations, and liquidity.
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Due in part to the recent increase in frequency and intensity of major storm activity along the Gulf Coast, Entergy is developing plans to accelerate investments that would enhance the resilience of the electric systems of the Utility operating companies to enable them to better withstand major storms or other adverse weather events, to enable more rapid restoration of electricity after major storm or other adverse events, and to deliver electricity to critical customers more immediately after such events. The need for this investment and these expenditures could give rise to liquidity, capital or other financing-related risks as well as result in upward pressure on the retail rates of the Utility operating companies, which, particularly when combined with upward pressure resulting from the recovery of the costs of recent and future storms, may result in adverse actions by the Utility operating companies’ retail regulators or effectively limit the ability to make other planned capital or other investments.
Continued and future availability and quality of water for cooling, process, and sanitary uses could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries.
Water is a vital natural resource that is also critical to Entergy and its subsidiaries. Entergy’s and its subsidiaries’ facilities use water for cooling, boiler make-up, sanitary uses, potable supply, and many other uses. Entergy’s Utility operating companies also own and/or operate hydroelectric facilities. Accordingly, water availability and quality are critical to Entergy’s and its subsidiaries’ business operations. Impacts to water availability or quality could negatively impact both operations and revenues.
Entergy and its subsidiaries secure water through various mechanisms (ground water wells, surface waters intakes, municipal supply, etc.) and operate under the provisions and conditions set forth by the provider and/or regulatory authorities. Entergy and its subsidiaries also obtain and operate in substantial compliance with water discharge permits issued under various provisions of the Clean Water Act and/or state water pollution control provisions. Regulations and authorizations for both water intake and use and for waste discharge can become more stringent in times of water shortages, low flows in rivers, low lake levels, low groundwater aquifer volumes, and similar conditions. The increased use of water by industry, agriculture, and the population at large, population growth, and the potential impacts of climate change on water resources may cause water use restrictions that affect Entergy and its subsidiaries.
Entergy and its subsidiaries may not be adequately hedged against changes in commodity prices, which could materially affect Entergy’s and its subsidiaries’ results of operations, financial condition, and liquidity.
To manage near-term and medium-term financial exposure related to commodity price fluctuations, Entergy and its subsidiaries, including the Utility operating companies, may enter into contracts to hedge portions of their purchase and sale commitments, fuel requirements, and inventories of natural gas, uranium and its conversion and enrichment, coal, refined products, and other commodities, within established risk management guidelines. As part of this strategy, Entergy and its subsidiaries may utilize fixed- and variable-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. However, Entergy and its subsidiaries normally cover only a portion of the exposure of their assets and positions to market price volatility, and the coverage will vary over time. In addition, Entergy also elects to leave certain volumes during certain years unhedged. To the extent Entergy and its subsidiaries have unhedged positions, fluctuating commodity prices can materially affect Entergy’s and its subsidiaries’ results of operations and financial position.
Although Entergy and its subsidiaries devote a considerable effort to these risk management strategies, they cannot eliminate all the risks associated with these activities. As a result of these and other factors, Entergy and its subsidiaries cannot predict with precision the impact that risk management decisions may have on their business, results of operations, or financial position.
Entergy’s over-the-counter financial derivatives are subject to rules implementing the Dodd-Frank Wall Street Reform and Consumer Protection Act that are designed to promote transparency, mitigate systemic risk, and protect against market abuse. Entergy cannot predict the impact any proposed or not fully-implemented final rules
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
will have on its ability to hedge its commodity price risk or on over-the-counter derivatives markets as a whole, but such rules and regulations could have a material effect on Entergy's risk exposure, as well as reduce market liquidity and further increase the cost of hedging activities.
Entergy has guaranteed or indemnified the performance of a portion of the obligations relating to hedging and risk management activities. Reductions in Entergy’s or its subsidiaries’ credit quality or changes in the market prices of energy commodities could increase the cash or letter of credit collateral required to be posted in connection with hedging and risk management activities, which could materially affect Entergy’s or its subsidiaries’ liquidity and financial position.
The Utility operating companies and Entergy’s non-regulated operations are exposed to the risk that counterparties may not meet their obligations, which may materially affect the Utility operating companies and Entergy’s non-regulated operations.
The hedging and risk management practices of the Utility operating companies and Entergy's non-regulated operations are exposed to the risk that counterparties that owe Entergy and its subsidiaries money, energy, or other commodities will not perform their obligations. Currently, some hedging agreements contain provisions that require the counterparties to provide credit support to secure all or part of their obligations to Entergy or its subsidiaries. If the counterparties to these arrangements fail to perform, Entergy or its subsidiaries may enforce and recover the proceeds from the credit support provided and acquire alternative hedging arrangements, which credit support may not always be adequate to cover the related obligations. In such event, Entergy and its subsidiaries might incur losses in addition to amounts, if any, already paid to the counterparties. In addition, the credit commitments of Entergy’s lenders under its bank facilities may not be honored for a variety of reasons, including unexpected periods of financial distress affecting such lenders, which could materially affect the adequacy of its liquidity sources.
Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding and result in increased benefit plan costs.
The performance of the capital markets affects the values of the assets held in trust under Entergy’s pension and postretirement benefit plans. A decline in the market value of the assets may increase the funding requirements relating to Entergy’s benefit plan liabilities and also result in higher benefit costs. As the value of the assets decreases, the “expected return on assets” component of benefit costs decreases, resulting in higher benefits costs. Additionally, asset losses are incorporated into benefit costs over time, thus increasing benefits costs. Volatility in the capital markets has affected the market value of these assets, which may affect Entergy’s planned levels of contributions in the future. Additionally, changes in interest rates affect the liabilities under Entergy’s pension and postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding and recognition of higher liability carrying costs. The funding requirements of the obligations related to the pension benefit plans can also increase as a result of changes in, among other factors, retirement rates, life expectancy assumptions, or federal regulations. For further information regarding Entergy’s pension and other postretirement benefit plans, refer to the “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” section of Management’s Financial Discussion and Analysis for Entergy and each of its Registrant Subsidiaries and Note 11 to the financial statements.
The litigation environment in the states in which the Registrant Subsidiaries operate poses a significant risk to those businesses.
Entergy and its subsidiaries and related entities are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, asbestos, hazardous material and customer matters, and injuries and damages issues, among other matters. The states in which the Registrant Subsidiaries operate have proven to be unusually litigious environments. Judges and juries in these states have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
cases. Entergy and its subsidiaries use legal and appropriate means to contest litigation threatened or filed against them, but the litigation environment in these states poses a significant business risk.
Terrorist attacks, physical attacks, cyber attacks, system failures or data breaches of Entergy’s and its subsidiaries’ or their suppliers’ infrastructure or technology systems may adversely affect Entergy’s results of operations.
Entergy and its subsidiaries operate in a business that requires evolving information technology systems that include sophisticated data collection, processing systems, software, network infrastructure, and other technologies that are becoming more complex and may be subject to mandatory and prescriptive reliability and security standards. The functionality of Entergy’s technology systems depends on its own and its suppliers’ and their contractors’ technology. Suppliers’ and their contractors’ technology systems to which Entergy is connected directly or indirectly support a variety of business processes and activities to store sensitive data, including (i) intellectual property, (ii) proprietary business information, (iii) personally identifiable information of customers, employees, and others, and (iv) data with respect to invoicing and the collection of payments, accounting, procurement, and supply-chain activities. Any significant failure or malfunction of such information technology systems could result in loss of or inappropriate access to data or disruptions of operations.
There have been attacks and threats of attacks on energy infrastructure by cyber actors, including those associated with foreign governments. As an operator of critical infrastructure, Entergy and its subsidiaries face a heightened risk of physical attacks or acts or threats of terrorism, cyber attacks, including ransomware attacks, and data breaches, whether as a direct or indirect act against one of Entergy’s generation, transmission or distribution facilities, operations centers, infrastructure, or information technology systems used to manage, monitor, and transport power to customers and perform day-to-day business functions as well as against the systems of critical suppliers and contractors. Further, attacks may become more frequent in the future as technology becomes more prevalent in energy infrastructure. An attack could affect Entergy’s ability to operate, including its ability to operate the information technology systems and network infrastructure on which it relies to conduct business.
Given the rapid technological advancements of existing and emerging threats, Entergy’s technology systems remain inherently vulnerable despite implementations and enhancements of the multiple layers of security and controls. If Entergy’s or its subsidiaries’ technology systems, or those of critical suppliers or contractors, were compromised and unable to detect or recover in a timely fashion to a normal state of operations, Entergy or its subsidiaries could be unable to perform critical business functions that are essential to the company’s well-being and could result in a loss of or inappropriate access to its confidential, sensitive, and proprietary information, including personal information of its customers, employees, suppliers, and others in Entergy’s care.
Any such attacks, failures, or data breaches could have a material effect on Entergy’s and the Utility operating companies’ business, financial condition, results of operations or reputation. Although Entergy and the Utility operating companies purchase insurance for cyber attacks and data breaches, such insurance prices have increased substantially, and coverage may not be adequate to cover all losses that might arise in connection with these events. Such events may also expose Entergy to an increased risk of litigation (and associated damages and fines).
Entergy and the Registrant Subsidiaries are subject to risks associated with their ability to obtain adequate insurance at acceptable costs.
The global economic cost to insurers resulting from cyber attacks, natural disasters and other catastrophic events, in addition to an increased focus on climate issues could have disruptive effects on insurance markets. The availability of insurance capacity may decrease, and the insurance policies that Entergy or the Registrant Subsidiaries are able to obtain may have higher deductibles, higher premiums, and more restrictive terms and conditions. Further, the insurance policies of Entergy or the Registrant Subsidiaries may not cover all of their potential exposures or actual amounts of losses incurred.
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
Significant increases in commodity prices, other materials and supplies, and operation and maintenance expenses may adversely affect Entergy's results of operations, financial condition, and liquidity.
Entergy and its subsidiaries have observed and expect future inflationary pressures related to commodity prices, other materials and supplies, and operation and maintenance expenses, including in the areas of labor, health care, and pension costs. The contracts for the construction of certain of the Utility operating companies’ generation facilities also have included, and in the future may include, price adjustment provisions that, subject to certain limitations, may enable the contractor to increase the contract price to reflect increases in certain costs of constructing the facility. These inflationary pressures could impact the ability of Entergy and its subsidiaries to control costs and/or make substantial investments in their businesses, including their ability to recover costs and investments, and to earn their allowed return on equity within frameworks established by their regulators while maintaining affordability of their services for their customers, in addition to having unpredictable effects on Entergy’s customers. Increases in commodity prices, other materials and supplies, and operation and maintenance expenses, including increasing labor costs and costs and funding requirements associated with Entergy's defined benefit retirement plans, health care plans, and other employee benefits, could increase their financing needs and otherwise adversely affect their results of operations, financial condition, and liquidity.
(Entergy New Orleans)
The effect of higher purchased gas cost charges to customers taking gas service may adversely affect Entergy New Orleans’s results of operations and liquidity.
Gas rates charged to retail gas customers are comprised primarily of purchased gas cost charges, which provide no return or profit to Entergy New Orleans, and distribution charges, which provide a return or profit to the utility. Distribution charges recover fixed costs on a volumetric basis and, thus, are affected by the amount of gas sold to customers. When purchased gas cost charges increase due to higher gas procurement costs, customer usage may decrease, especially in weaker economic times, resulting in lower distribution charges for Entergy New Orleans, which, given its relatively smaller size, could adversely affect results of operations. Purchased gas cost charges, which comprise most of a customer’s bill and may be adjusted monthly, represent gas commodity costs that Entergy New Orleans recovers from its customers. Entergy New Orleans’s cash flows can be affected by differences between the time when gas is purchased and the time when ultimate recovery from customers occurs.
(Entergy Corporation and System Energy)
System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on sales to affiliated companies for all of its revenues. Certain contractual arrangements relating to System Energy, the affiliated companies, and these revenues are the subject of ongoing litigation and regulatory proceedings. The aggregate amount of refunds claimed in these proceedings substantially exceeds the current net book value of System Energy. In the event of an adverse decision in one or more of these proceedings requiring the payment of substantial additional refunds, System Energy would be required to seek financing to pay such refunds which financing may not be available on terms acceptable to System Energy, or may not be available at all, when required. If one or more of the foregoing events occurs, System Energy may be required to explore other options or protections available to it to extend, restructure, or retire its indebtedness and to prioritize its obligations.
System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf. Charges under the Unit Power Sales Agreement are paid by the Utility operating companies (other than Entergy Texas) as consideration for their respective entitlements to receive capacity and energy. The useful economic life of Grand Gulf is finite and is limited by the terms of its operating license, which currently expires in November 2044. System Energy’s financial condition depends both on the receipt of payments from the Utility operating companies (other than Entergy Texas)
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
under the Unit Power Sales Agreement and on the continued commercial operation of Grand Gulf. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC, including a challenge with respect to System Energy’s uncertain tax positions, sale leaseback arrangement, authorized return on equity and capital structure, a broader investigation of rates under the Unit Power Sales Agreement, and a prudence complaint challenging the extended power uprate completed at Grand Gulf in 2012 and the operation and management of Grand Gulf, particularly in the 2016-2020 time period.
The claims in these proceedings include claims for refunds and claims for rate adjustments. The aggregate amount of refunds claimed in these proceedings substantially exceeds the current net book value of System Energy. Entergy Corporation is not obligated to provide funding to System Energy to enable it to pay any such refunds. In the event that an adverse decision in one or more of these proceedings required the payment of substantial additional refunds, System Energy would need to source additional financing to pay such refunds. Such financing may not be available on terms acceptable to System Energy, or may not be available at all, when required. An adverse development in one or more of these proceedings also could jeopardize System Energy’s ability to finance its operations and pay its obligations, at a reasonable cost or when due. If one or more of the foregoing events occurs, System Energy may be required to explore other options or protections available to it to extend, restructure, or retire its indebtedness and to prioritize its obligations. One or more rating agencies may downgrade the ratings of System Energy or its debt securities, which could adversely affect the market prices of System Energy’s debt securities and otherwise adversely affect System Energy’s financial condition.
In addition, an order requiring System Entergy to pay substantial additional refunds could result in a default and, in certain cases, acceleration under one or more of System Energy’s existing bond indentures, credit agreements, or other financing arrangements. Certain events constituting events of default under System Energy’s financing agreements may also result in defaults under, or acceleration with respect to, financing arrangements involving certain credit agreement and guarantee obligations of Entergy Corporation.
These proceedings are pending before their respective adjudicators and no final decisions have been reached. Thus, Entergy cannot predict with certainty the outcome of any of these proceedings, or the magnitude of any refunds or rate adjustments, and an adverse outcome in any of them could have a material adverse effect on Entergy’s or System Energy’s results of operations, financial condition, or liquidity. In particular, in connection with the uncertain tax position proceeding and related December 2022 FERC order and System Energy’s compliance report filed in January 2023, if the FERC were to order additional refunds at a level consistent with the position of the LPSC, the APSC, and the City Council on the remedy for the formerly uncertain tax positions, System Energy’s continued financial viability would be jeopardized. See Note 2 to the financial statements for further discussion of the proceedings. The Utility operating companies (other than Entergy Texas) have agreed to implement certain protocols for providing retail regulators with information regarding rates billed under the Unit Power Sales Agreement.
For information regarding the Unit Power Sales Agreement, the sale and leaseback transactions and certain other agreements relating to certain Entergy System companies’ support of System Energy, see Notes 5 and 8 to the financial statements and the “Utility - System Energy and Related Agreements” section of Part I, Item 1.
(Entergy Corporation)
Entergy’s non-regulated operations are subject to substantial governmental regulation and may be adversely affected by legislative, regulatory, or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
Entergy’s non-regulated operations are subject to regulation under federal, state, and local laws. Compliance with the requirements under these various regulatory regimes may cause Entergy’s non-regulated operations to incur significant additional costs, and failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of liens, fines, and/or civil or criminal liability.
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
Public utilities under the Federal Power Act are required to obtain FERC acceptance of their rate schedules for wholesale sales of electricity. Entergy’s non-regulated operations include legal entities that meet the definition of a “public utility” under the Federal Power Act by virtue of making wholesale sales of electric energy and/or owning wholesale electric transmission facilities. The FERC has granted those entities the authority to sell electricity at market-based rates. The FERC’s orders that grant those entities market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that those entities can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, market-based sales are subject to certain market behavior rules, and if one of those entities were deemed to have violated one of those rules, they would be subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority and potential penalties of up to $1.29 million per day per violation. If one of those entities were to lose their market-based rate authority, it would be required to obtain the FERC’s acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have an adverse effect on the rates those entities charge for power from its facilities.
Entergy’s non-regulated operations are also affected by legislative and regulatory changes, as well as by changes to market design, market rules, tariffs, cost allocations, and bidding rules imposed by the existing Independent System Operator. The Independent System Operator that oversees the relevant wholesale power market may impose, and in the future may continue to impose, mitigation, including price limitations, offer caps and other mechanisms, to address some of the volatility and the potential exercise of market power in that market. These types of price limitations and other regulatory mechanisms may have an adverse effect on the profitability of Entergy’s non-regulated operations’ generation facilities that sell energy and capacity into the wholesale power markets.
The regulatory environment applicable to the electric power industry is subject to changes as a result of restructuring initiatives at both the state and federal levels. Entergy cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on Entergy’s non-regulated operations. In addition, in some of these markets, interested parties have proposed material market design changes, including the elimination of a single clearing price mechanism, have raised claims that the competitive marketplace is not working, and have made proposals to re-regulate the markets, impose a generation tax, or require divestitures by generating companies to reduce their market share. Other proposals to re-regulate may be made and legislative or other attention to the electric power market restructuring process may delay or reverse the deregulation process, which could require material changes to business planning models. If competitive restructuring of the electric power markets is reversed, modified, discontinued, or delayed, Entergy’s non-regulated operations’ results of operations, financial condition, and liquidity could be materially affected.
As a holding company, Entergy Corporation depends on cash distributions from its subsidiaries to meet its debt service and other financial obligations and to pay dividends on its common stock, and has provided, and may continue to provide, capital contributions or debt financing to its subsidiaries, which would reduce the funds available to meet its other financial obligations.
Entergy Corporation is a holding company with no material revenue generating operations of its own or material assets other than the stock of its subsidiaries. Accordingly, all of its operations are conducted by its subsidiaries. Entergy Corporation has provided, and may continue to provide, capital contributions or debt financing to its subsidiaries, which would reduce the funds available to meet its financial obligations, including making interest and principal payments on outstanding indebtedness, and to pay dividends on Entergy’s common stock. Entergy Corporation’s ability to satisfy its financial obligations, including the payment of interest and principal on its outstanding debt, and to pay dividends on its common stock depends on the payment to it of dividends or distributions by its subsidiaries. The subsidiaries of Entergy Corporation are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any dividends or make distributions to Entergy Corporation. The ability of such subsidiaries to make payments of dividends or distributions to Entergy
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
Corporation depends on their results of operations and cash flows and other items affecting retained earnings, and on any applicable legal, regulatory, or contractual limitations on subsidiaries’ ability to pay such dividends or distributions. Prior to providing funds to Entergy Corporation, such subsidiaries have financial and regulatory obligations that must be satisfied, including among others, debt service and, in the case of Entergy Utility Holding Company and Entergy Texas, dividends and distributions on preferred securities. Any distributions from the Registrant Subsidiaries other than Entergy Texas and System Energy are paid directly to Entergy Utility Holding Company and are therefore subject to prior payment of distributions on its preferred securities.
Item 1B. Unresolved Staff Comments
None.
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
2022 Compared to 2021
Earnings Applicable to Member’s Equity
Earnings decreased $19.3 million primarily due to higher other operation and maintenance expenses, the reversal in 2021 of the remaining $38.8 million regulatory liability for the formula rate plan 2019 historical year netting adjustment, higher depreciation and amortization expenses, higher interest expense, and higher taxes other than income taxes, partially offset by higher retail electric price and higher volume/weather.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 2022 to 2021:
| | | | | |
| Amount |
| (In Millions) |
| 2021 operating revenues | $2,338.6 | |
| Fuel, rider, and other revenues that do not significantly affect net income | 209.2 | |
| Retail electric price | 70.0 | |
| Volume/weather | 47.4 | |
| Return of unprotected excess accumulated deferred income taxes to customers | 8.0 | |
| 2022 operating revenues | $2,673.2 | |
Entergy Arkansas’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.
The retail electric price variance is primarily due to an increase in formula rate plan rates effective January 2022. See Note 2 to the financial statements for further discussion of the 2021 formula rate plan filing.
The volume/weather variance is primarily due to the effect of more favorable weather on residential sales and an increase in demand charges as a result of an updated contract with an industrial customer in the primary metals industry, partially offset by a decrease in weather-adjusted residential usage.
The return of unprotected excess accumulated deferred income taxes to customers resulted from the return of unprotected excess accumulated deferred income taxes through a tax adjustment rider beginning in April 2018. In 2021, $8 million was returned to customers. There was no effect on net income as the reduction in operating revenues was offset by a reduction in income tax expense. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Total electric energy sales for Entergy Arkansas for the years ended December 31, 2022 and 2021 are as follows:
| | | | | | | | | | | | | | | | | |
| 2022 | | 2021 | | % Change |
| (GWh) | | |
| Residential | 8,147 | | | 7,914 | | | 3 | |
| Commercial | 5,615 | | | 5,491 | | | 2 | |
| Industrial | 8,493 | | | 8,466 | | | — | |
| Governmental | 218 | | | 225 | | | (3) | |
| Total retail | 22,473 | | | 22,096 | | | 2 | |
| Sales for resale: | | | | | |
| Associated companies | 1,906 | | | 2,254 | | | (15) | |
| Non-associated companies | 6,520 | | | 6,151 | | | 6 | |
| Total | 30,899 | | | 30,501 | | | 1 | |
See Note 19 to the financial statements for additional discussion of Entergy Arkansas’s operating revenues.
Other Income Statement Variances
Other operation and maintenance expenses increased primarily due to:
•an increase of $24.1 million in power delivery expenses primarily due to higher vegetation maintenance costs, higher safety and training costs, and higher reliability costs, partially offset by a decrease in meter reading expenses as a result of the deployment of advanced metering systems;
•an increase of $17 million in nuclear generation expenses primarily due to a higher scope of work performed in 2022 as compared to 2021 and higher nuclear labor costs;
•an increase of $11.6 million in non-nuclear generation expenses primarily due to a higher scope of work, including during plant outages, performed in 2022 as compared to 2021 and higher costs associated with materials and supplies in 2022 as compared to 2021;
•an increase of $7.9 million in energy efficiency expenses primarily due to the timing of recovery from customers, partially offset by lower energy efficiency costs; and
•an increase of $4.6 million in customer service center support costs primarily due to higher contract costs.
Taxes other than income taxes increased primarily due to increases in ad valorem taxes resulting from higher assessments and millage rate increases, increases in employment taxes, and increases in local franchise taxes.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including the Searcy Solar facility, which was placed in service in December 2021.
Other regulatory charges (credits) - net includes the reversal in first quarter 2021 of the remaining $38.8 million regulatory liability for the 2019 historical year netting adjustment as part of its 2020 formula rate plan proceeding. See Note 2 to the financial statements for discussion of the 2020 formula rate plan filing. In addition, Entergy Arkansas records a regulatory charge or credit for the difference between asset retirement obligation-related expenses and nuclear decommissioning trust earnings plus asset retirement obligation-related costs collected in revenue.
Other income decreased primarily due to changes in decommissioning trust fund activity, including portfolio rebalancing of the decommissioning trust funds in 2021.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Interest expense increased primarily due to the issuance of $200 million of 4.20% Series mortgage bonds in March 2022 and the issuance of $400 million of 3.35% Series mortgage bonds in March 2021, partially offset by the repayment of $350 million of 3.75% Series mortgage bonds in February 2021.
Net loss attributable to noncontrolling interest reflects the earnings or losses attributable to the noncontrolling interest partner of the tax equity partnership for the Searcy Solar facility under HLBV accounting. Entergy Arkansas recorded regulatory charges of $4.5 million in 2022 compared to $18.1 million in 2021 to defer the difference between the losses allocated to the tax equity partner under the HLBV method of accounting and the earnings/loss that would have been allocated to the tax equity partner under its respective ownership percentage in the partnership. See Note 1 to the financial statements for discussion of the HLBV method of accounting.
The effective income tax rates were 21.6% for 2022 and 20.1% for 2021. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates, and for additional discussion regarding income taxes.
2021 Compared to 2020
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy Arkansas’s Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC onFebruary 25, 2022, for discussion of results of operations for 2021 compared to 2020.
Income Tax Legislation
See the “Income Tax Legislation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the Inflation Reduction Act of 2022.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2022, 2021, and 2020 were as follows:
| | | | | | | | | | | | | | | | | | |
| | 2022 | | 2021 | | 2020 | |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period | $12,915 | | | $192,128 | | | $3,519 | | |
| | | | | | |
| Net cash provided by (used in): | | | | | | |
| Operating activities | 699,732 | | | 549,216 | | | 659,818 | | |
| Investing activities | (852,794) | | | (898,193) | | | (795,709) | | |
| Financing activities | 145,425 | | | 169,764 | | | 324,500 | | |
| Net increase (decrease) in cash and cash equivalents | (7,637) | | | (179,213) | | | 188,609 | | |
| | | | | | |
| Cash and cash equivalents at end of period | $5,278 | | | $12,915 | | | $192,128 | | |
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2022 Compared to 2021
Operating Activities
Net cash flow provided by operating activities increased $150.5 million in 2022 primarily due to:
•higher collections from customers;
•the timing of recovery of fuel and purchased power costs. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery; and
•a decrease in spending of $23.6 million on nuclear refueling outages in 2022.
The increase was partially offset by:
•payments to vendors, including timing and increase in cost of operations;
•an increase of $26.3 million in pension contributions in 2022. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding; and
•a decrease of $16.2 million in income tax refunds. Entergy Arkansas received income tax refunds in 2022 and 2021, each in accordance with an intercompany income tax allocation agreement.
Investing Activities
Net cash flow used in investing activities decreased $45.4 million in 2022 primarily due to:
•the purchase of the Searcy Solar facility by the tax equity partnership in December 2021 for approximately $131.8 million. See Note 14 to the financial statements for further discussion of the Searcy Solar facility purchase; and
•a decrease of $16.6 million in non-nuclear generation construction expenditures primarily due to a lower scope of work on projects performed in 2022 as compared to 2021.
The decrease was partially offset by:
•an increase of $78.7 million in distribution construction expenditures primarily due to higher capital expenditures for storm restoration in 2022 and increased investment in the reliability and infrastructure of Entergy Arkansas’s distribution system, partially offset by lower spending in 2022 on advanced metering infrastructure;
•an increase of $27.2 million in decommissioning trust fund investment activity; and
•an increase of $19 million in transmission construction expenditures primarily due to a higher scope of work on projects performed in 2022 as compared to 2021.
Financing Activities
Net cash flow provided by financing activities decreased $24.3 million in 2022 primarily due to:
•the issuance of $400 million of 3.35% Series mortgage bonds in March 2021;
•money pool activity;
•capital contributions of $51.2 million received in 2021 from the noncontrolling tax equity investor in AR Searcy Partnership, LLC and used by the partnership to acquire the Searcy Solar facility. See Note 14 to the financial statements for discussion of the Searcy Solar facility purchase;
•lower prepaid deposits of $50.9 million related to contributions-in-aid-of-construction reimbursement agreements in 2022 as compared to 2021; and
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
•an increase of $36 million in common equity distributions paid in 2022 as compared to 2021 in order to maintain Entergy Arkansas’s capital structure.
The decrease was partially offset by:
•the repayment, at maturity, of $350 million of 3.75% Series mortgage bonds in February 2021;
•the issuance of $200 million of 4.20% Series mortgage bonds in March 2022; and
•the repayment, at maturity, of $45 million of 2.375% Series governmental bonds in January 2021.
Increases in Entergy Arkansas’s payable to the money pool are a source of cash flow, and Entergy Arkansas’s payable to the money pool increased $40.9 million in 2022 compared to increasing by $139.9 million in 2021. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
See Note 5 to the financial statements for further details of long-term debt.
2021 Compared to 2020
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Arkansas’s Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 25, 2022, for discussion of operating, investing, and financing cash flow activities for 2021 compared to 2020.
Capital Structure
Entergy Arkansas’s debt to capital ratio is shown in the following table.
| | | | | | | | | | | |
| | December 31,
2022 | | December 31,
2021 |
| Debt to capital | 52.5 | % | | 52.6 | % |
| Effect of subtracting cash | — | % | | — | % |
| Net debt to net capital (non-GAAP) | 52.5 | % | | 52.6 | % |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. Entergy Arkansas uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition. The net debt to net capital ratio is a non-GAAP measure. Entergy Arkansas also uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition because net debt indicates Entergy Arkansas’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Arkansas seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a distribution, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Arkansas may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reducing distributions, Entergy Arkansas may receive equity contributions to maintain its capital structure.
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Management’s Financial Discussion and Analysis
Uses of Capital
Entergy Arkansas requires capital resources for:
•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.
Following are the amounts of Entergy Arkansas’s planned construction and other capital investments.
| | | | | | | | | | | | | | | | | |
| | 2023 | | 2024 | | 2025 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation | $255 | | | $1,175 | | | $910 | |
| Transmission | 110 | | | 160 | | | 135 | |
| Distribution | 285 | | | 425 | | | 350 | |
| Utility Support | 105 | | | 65 | | | 90 | |
| Total | $755 | | | $1,825 | | | $1,485 | |
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Arkansas includes investments in generation projects to modernize, decarbonize, and diversify Entergy Arkansas’s portfolio, including Walnut Bend Solar, West Memphis Solar, and Driver Solar; investments in ANO 1 and 2; distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to drive reliability and resilience while also supporting renewables expansion; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, government actions, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.
While Entergy Arkansas is still assessing the effect on its planned solar projects, the investigation by the U.S. Department of Commerce into potential circumvention of duties and tariffs may result in increased duties or tariffs on imported solar panels and has exacerbated previously existing supply chain disruptions, which have negatively affected the timing and cost of completion of these projects.
Following are the amounts of Entergy Arkansas’s existing debt and lease obligations (includes estimated interest payments).
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2023 | | 2024 | | 2025 | | 2026-2027 | | After 2027 |
| | (In Millions) |
| Long-term debt (a) | $432 | | | $504 | | | $123 | | | $898 | | | $5,060 | |
| Operating leases (b) | $16 | | | $14 | | | $12 | | | $16 | | | $2 | |
| Finance leases (b) | $3 | | | $3 | | | $3 | | | $4 | | | $2 | |
(a)Long-term debt is discussed in Note 5 to the financial statements.
(b)Lease obligations are discussed in Note 10 to the financial statements.
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Management’s Financial Discussion and Analysis
Other Obligations
Entergy Arkansas currently expects to contribute approximately $54.5 million to its qualified pension plans and approximately $526 thousand to its other postretirement health care and life insurance plans in 2023, although the 2023 required pension contributions will be known with more certainty when the January 1, 2023 valuations are completed, which is expected by April 1, 2023. See “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Entergy Arkansas has $175.4 million of unrecognized tax benefits net of unused tax attributes plus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition, Entergy Arkansas enters into fuel and purchased power agreements that contain minimum purchase obligations. Entergy Arkansas has rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations. See Note 8 to the financial statements for discussion of Entergy Arkansas’s obligations under the Unit Power Sales Agreement.
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Arkansas pays distributions from its earnings at a percentage determined monthly.
Renewables
Walnut Bend Solar
In October 2020, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 100 MW Walnut Bend Solar facility is in the public interest. Entergy Arkansas primarily requested cost recovery through the formula rate plan rider. In July 2021 the APSC granted Entergy Arkansas’s petition and approved the acquisition of the resource and cost recovery through the formula rate plan rider. In addition, the APSC directed Entergy Arkansas to file a report within 180 days detailing its efforts to obtain a tax equity partnership. In January 2022, Entergy Arkansas filed its tax equity partnership status report and will file subsequent reports until a tax equity partnership is obtained or a tax equity partnership is no longer sought. Closing was expected to occur in 2022. The counter-party notified Entergy Arkansas that it was terminating the project, though it was willing to consider an alternative for the site. Entergy Arkansas disputed the right of termination. Negotiations are ongoing, including with respect to cost and schedule and to updates arising as a result of the Inflation Reduction Act of 2022, and the updates would require additional APSC approval. At this time, the project, if approved, is expected to achieve commercial operation in 2024.
West Memphis Solar
In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 180 MW West Memphis Solar facility is in the public interest. In October 2021 the APSC granted Entergy Arkansas’s petition and approved the acquisition of the West Memphis Solar facility and cost recovery through the formula rate plan rider. In addition, the APSC directed Entergy Arkansas to file a report within 180 days detailing its efforts to obtain a tax equity partnership. In April 2022, Entergy Arkansas filed its tax equity partnership status report and will file subsequent reports until a tax equity partnership is obtained or a tax equity partnership is no longer sought. Closing had been expected to occur in 2023. In March 2022 the counter-party notified Entergy Arkansas that it was seeking changes to certain terms of the build-own-transfer agreement, including both cost and schedule. In January 2023, Entergy Arkansas filed a supplemental application with the APSC seeking approval for a change in the transmission route and updates to the cost and schedule that were previously approved by the APSC. The project is expected to achieve commercial operation in 2024.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Driver Solar
In April 2022, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 250 MW Driver Solar facility is in the public interest and requested cost recovery through the formula rate plan rider. The APSC established a procedural schedule with a hearing scheduled in June 2022, but the parties later agreed to waive the hearing and submit the matter to the APSC for a decision consistent with the filed record. In August 2022 the APSC granted Entergy Arkansas’s petition and approved the acquisition of Driver Solar and cost recovery through the formula rate plan rider. In addition, the APSC directed Entergy Arkansas to inform the APSC as to the status of a tax equity partnership once construction is commenced. The parties are evaluating the effects of certain matters related to the Inflation Reduction Act of 2022, including the viability of a tax equity partnership. The project is expected to achieve commercial operation in 2024.
Sources of Capital
Entergy Arkansas’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•the Entergy System money pool;
•debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations, Entergy Arkansas expects to continue, when economically feasible, to retire higher-cost debt and replace it with lower-cost debt if market conditions permit.
All debt and common and preferred membership interest issuances by Entergy Arkansas require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in Entergy Arkansas’s bond indenture and other agreements. Entergy Arkansas has sufficient capacity under these tests to meet its foreseeable capital needs for the next twelve months and beyond.
Entergy Arkansas’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
| | | | | | | | | | | | | | | | | | | | |
| 2022 | | 2021 | | 2020 | | 2019 |
| (In Thousands) |
| ($180,795) | | ($139,904) | | $3,110 | | ($21,634) |
See Note 4 to the financial statements for a description of the money pool.
Entergy Arkansas has a credit facility in the amount of $150 million scheduled to expire in June 2027. Entergy Arkansas also has a $25 million credit facility scheduled to expire in April 2023. The $150 million credit facility includes fronting commitments for the issuance of letters of credit against $5 million of the borrowing capacity of the facility. As of December 31, 2022, there were no cash borrowings and no letters of credit outstanding under the credit facilities. In addition, Entergy Arkansas is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2022, $5.6 million in
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Management’s Financial Discussion and Analysis
letters of credit were outstanding under Entergy Arkansas’s uncommitted letter of credit facility. See Note 4 to the financial statements for further discussion of the credit facilities.
The Entergy Arkansas nuclear fuel company variable interest entity has a credit facility in the amount of $80 million scheduled to expire in June 2025. As of December 31, 2022, there were no loans outstanding under the credit facility for the Entergy Arkansas nuclear fuel company variable interest entity. See Note 4 to the financial statements for further discussion of the nuclear fuel company variable interest entity credit facility.
Entergy Arkansas obtained authorization from the FERC through October 2023 for short-term borrowings not to exceed an aggregate amount of $250 million at any time outstanding and borrowings by its nuclear fuel company variable interest entity. See Note 4 to the financial statements for further discussion of Entergy Arkansas’s short-term borrowing limits. The long-term securities issuances of Entergy Arkansas are limited to amounts authorized by the FERC. The APSC has concurrent jurisdiction over Entergy Arkansas’s first mortgage bond/secured issuances. Entergy Arkansas has obtained long-term financing authorization from the FERC that extends through October 2023. Entergy Arkansas has obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2023.
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy Arkansas charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Arkansas is regulated, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the APSC, is primarily responsible for approval of the rates charged to customers.
Retail Rates
2020 Formula Rate Plan Filing
In July 2020, Entergy Arkansas filed with the APSC its 2020 formula rate plan filing to set its formula rate for the 2021 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2021, as amended through subsequent filings in the proceeding, and a netting adjustment for the historical year 2019. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2021 projected year is 8.22% resulting in a revenue deficiency of $64.3 million. The earned rate of return on common equity for the 2019 historical year was 9.07% resulting in a $23.9 million netting adjustment. The total proposed revenue change for the 2021 projected year and 2019 historical year netting adjustment was $88.2 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $74.3 million. As part of the formula rate plan tariff the calculation for the revenue constraint was updated based on actual revenues which had the effect of reducing the initially-proposed $74.3 million revenue requirement increase to $72.6 million. In October 2020, Entergy Arkansas filed with the APSC a unanimous settlement agreement reached with the other parties that resolved all but one issue. As a result of the settlement agreement, Entergy Arkansas’s requested revenue increase was $68.4 million, including a $44.5 million increase for the projected 2021 year and a $23.9 million netting adjustment. The remaining issue litigated concerned the methodology used to calculate the netting adjustment within the formula rate plan. In December 2020 the APSC issued an order rejecting the netting adjustment method used by Entergy Arkansas. Applying the approach ordered by the APSC changed the netting adjustment for the 2019 historical year from a $23.9 million deficiency to $43.5 million excess. Overall, the decision reduced Entergy Arkansas’s revenue adjustment for 2021 to $1 million. In December 2020, Entergy Arkansas filed a petition for rehearing of the APSC’s decision in the 2020 formula rate plan proceeding regarding the 2019 netting adjustment, and in January 2021 the APSC granted further consideration of Entergy Arkansas’s petition. Based on the progress of the proceeding at that point, in December 2020, Entergy Arkansas recorded a regulatory liability of $43.5 million to reflect the netting adjustment for 2019, as included in the APSC’s December 2020 order, which would be returned
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Management’s Financial Discussion and Analysis
to customers in 2021. Entergy Arkansas also requested an extension of the formula rate plan rider for a second five-year term. In March 2021 the Arkansas Governor signed HB1662 into law (Act 404). Act 404 clarified aspects of the original formula rate plan legislation enacted in 2015, including with respect to the extension of a formula rate plan, the methodology for the netting adjustment, and debt and equity levels; it also reaffirmed the customer protections of the original formula rate plan legislation, including the cap on annual formula rate plan rate changes. Pursuant to Act 404, Entergy Arkansas’s formula rate plan rider was extended for a second five-year term. Entergy Arkansas filed a compliance tariff in its formula rate plan docket in April 2021 to effectuate the netting provisions of Act 404, which reflected a net change in required formula rate plan rider revenue of $39.8 million, effective with the first billing cycle of May 2021. In April 2021 the APSC issued an order approving the compliance tariff and recognizing the formula rate plan extension. Also in April 2021, Entergy Arkansas filed for approval of modifications to the formula rate plan tariff incorporating the provisions in Act 404, and the APSC approved the tariff modifications in April 2021. Given the APSC general staff’s support for the expedited approval of these filings by the APSC, Entergy Arkansas supported an amendment to Act 404 to achieve a reduced return on equity from 9.75% to 9.65% to apply for years applicable to the extension term; that amendment was signed by the Arkansas Governor in April 2021 and is now Act 894. Based on the APSC’s order issued in April 2021, in the first quarter 2021, Entergy Arkansas reversed the remaining regulatory liability for the netting adjustment for 2019. In June 2021, Entergy Arkansas filed another compliance tariff in its formula rate plan proceeding to effectuate the additional provisions of Act 894, and the APSC approved the second compliance tariff filing in July 2021.
2021 Formula Rate Plan Filing
In July 2021, Entergy Arkansas filed with the APSC its 2021 formula rate plan filing to set its formula rate for the 2022 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2022 and a netting adjustment for the historical year 2020. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2022 projected year is 7.65% resulting in a revenue deficiency of $89.2 million. The earned rate of return on common equity for the 2020 historical year was 7.92% resulting in a $19.4 million netting adjustment. The total proposed revenue change for the 2022 projected year and 2020 historical year netting adjustment is $108.7 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase is limited to $72.4 million. In October 2021, Entergy Arkansas filed with the APSC a settlement agreement reached with other parties resolving all issues in the proceeding. As a result of the settlement agreement, the total proposed revenue change is $82.2 million, including a $62.8 million increase for the projected 2022 year and a $19.4 million netting adjustment. Because Entergy Arkansas’s revenue requirement exceeded the constraint, the resulting increase is limited to $72.1 million. In December 2021 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 2022.
2022 Formula Rate Plan Filing
In July 2022, Entergy Arkansas filed with the APSC its 2022 formula rate plan filing to set its formula rate for the 2023 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2023 and a netting adjustment for the historical year 2021. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2023 projected year is 7.40% resulting in a revenue deficiency of $104.8 million. The earned rate of return on common equity for the 2021 historical year was 8.38% resulting in a $15.2 million netting adjustment. The total proposed revenue change for the 2023 projected year and 2021 historical year netting adjustment is $119.9 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement was subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $79.3 million. In October 2022 other parties filed their testimony recommending various adjustments to Entergy Arkansas’s overall proposed revenue deficiency, and Entergy Arkansas filed a response including an update to actual revenues through August 2022, which raised the constraint to $79.8 million. In November 2022, Entergy Arkansas filed with the APSC a settlement agreement reached with other parties resolving all issues in the
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Management’s Financial Discussion and Analysis
proceeding. As a result of the settlement agreement, the total revenue change was $102.8 million, including a $87.7 million increase for the 2023 projected year and a $15.2 million netting adjustment. Because Entergy Arkansas’s revenue requirement exceeded the constraint, the resulting increase was limited to $79.8 million. In December 2022 the APSC approved the settlement agreement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2023.
Green Promise Renewable Tariff
In July 2021, Entergy Arkansas filed a proposed green tariff designed to help participating customers meet their renewable and sustainability goals and to enhance economic development efforts in Arkansas. The total proposed amount of solar capacity requested to be available under this tariff was up to 200 MW. In September and October 2021 the APSC general staff and two net metering developer intervenors filed responses indicating opposition to the tariff as proposed. The tariff was supported by certain commercial and industrial customers that have indicated an interest in subscribing to the tariff. In October 2021, Entergy Arkansas, Walmart, and industrial customers filed a non-unanimous settlement agreement supporting that the tariff should be approved as filed by Entergy Arkansas; the Arkansas Attorney General stated it did not oppose the settlement. In January 2022 the APSC general staff filed in opposition to the non-unanimous settlement agreement, and one of the net metering developer intervenors withdrew from the proceeding. In January 2022 the parties agreed to a paper hearing with written responses to the APSC’s questions being filed in February and March 2022. In May 2022 the APSC found Entergy Arkansas’s proposal for the tariff to be just and reasonable for an initial offering of 100 MW of solar capacity, and in June 2022 the APSC approved Entergy Arkansas’s compliance tariff filing.
Energy Cost Recovery Rider
Entergy Arkansas’s retail rates include an energy cost recovery rider to recover fuel and purchased energy costs in monthly customer bills. The rider utilizes the prior calendar-year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over- or under-recovery, including carrying charges, of the energy costs for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs.
In January 2014, Entergy Arkansas filed a motion with the APSC relating to its upcoming energy cost rate redetermination filing that was made in March 2014. In that motion, Entergy Arkansas requested that the APSC authorize Entergy Arkansas to exclude from the redetermination of its 2014 energy cost rate $65.9 million of incremental fuel and replacement energy costs incurred in 2013 as a result of the ANO stator incident. Entergy Arkansas requested that the APSC authorize Entergy Arkansas to retain that amount in its deferred fuel balance, with recovery to be reviewed in a later period after more information was available regarding various claims associated with the ANO stator incident. In February 2014 the APSC approved Entergy Arkansas’s request to retain that amount in its deferred fuel balance. In July 2017, Entergy Arkansas filed for a change in rates pursuant to its formula rate plan rider. In that proceeding, the APSC approved a settlement agreement agreed upon by the parties, including a provision that requires Entergy Arkansas to initiate a regulatory proceeding for the purpose of recovering funds currently withheld from rates and related to the stator incident, including the $65.9 million of deferred fuel and purchased energy costs and costs related to the incremental oversight previously noted, subject to
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Management’s Financial Discussion and Analysis
certain timelines and conditions set forth in the settlement agreement.agreement, including the resolution of civil litigation currently pending regarding the stator incident by the Circuit Court of Pope County, Arkansas. A trial date was established by the circuit court for March 1, 2023, but has been continued. In December 2022 the APSC approved Entergy Arkansas’s request for an additional extension of the deadline for initiating a regulatory proceeding for the purpose of recovering funds related to the stator incident to no later than sixty days after the circuit court issues a final order in the civil litigation proceedings. See the “ANO Damage, Outage, and NRC Reviews” section in Note 8 to the financial statements for further discussion of the ANO stator incident.
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Management’s Financial Discussion and Analysis
In March 2017, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01164 per kWh to $0.01547 per kWh. The APSC staff filed testimony in March 2017 recommending that the redetermined rate be implemented with the first billing cycle of April 2017 under the normal operation of the tariff. Accordingly, the redetermined rate went into effect on March 31, 2017 pursuant to the tariff. In July 2017 the Arkansas Attorney General requested additional information to support certain of the costs included in Entergy Arkansas’s 2017 energy cost rate redetermination.
In March 2018, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01547 per kWh to $0.01882 per kWh. The Arkansas Attorney General filed a response to Entergy Arkansas’s annual redetermination filing requesting that the APSC suspend the proposed tariff to investigate the amount of the redetermination or, alternatively, to allow recovery subject to refund. Among the reasons the Attorney General cited for suspension were questions pertaining to how Entergy Arkansas forecasted sales and potential implications of the Tax Cuts and Jobs Act. Entergy Arkansas replied to the Attorney General’s filing and stated that, to the extent there are questions pertaining to its load forecasting or the operation of the energy cost recovery rider, those issues exceed the scope of the instant rate redetermination. Entergy Arkansas also stated that potential effects of the Tax Cuts and Jobs Act are appropriately considered in the APSC’s separate proceeding regarding potential implications of the tax law. The APSC general staff filed a reply to the Attorney General’s filing and agreed that Entergy Arkansas’s filing complied with the terms of the energy cost recovery rider. The redetermined rate became effective with the first billing cycle of April 2018. Subsequently in April 2018 the APSC issued an order declining to suspend Entergy Arkansas’s energy cost recovery rider rate and declining to require further investigation at that time of the issues suggested by the Attorney General in the proceeding. Following a period of discovery, the Attorney General filed a supplemental response in October 2018 raising new issues with Entergy Arkansas’s March 2018 rate redetermination and asserting that $45.7 million of the increase should be collected subject to refund pending further investigation. Entergy Arkansas filed to dismiss the Attorney General’s supplemental response, the APSC general staff filed a motion to strike the Attorney General’s filing, and the Attorney General filed a supplemental response disputing Entergy Arkansas and the APSC staff’s filing. Applicable APSC rules and processes authorize its general staff to initiate periodic audits of Entergy Arkansas’s energy cost recovery rider. In late-2018 the APSC general staff notified Entergy Arkansas it 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 2019,2020, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $0.01882$0.01462 per kWh to $0.01462$0.01052 per kWh andkWh. The redetermined rate became effective with the first billing cycle in April 2019. 2020 through the normal operation of the tariff.
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.2021, Entergy Arkansas filed its responseannual redetermination of its energy cost rate pursuant 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 seekingrider, which reflected a decrease from $0.01052 per kWh to $0.00959 per kWh. The redetermined rate calculation also included an investigation intoadjustment to account for a portion of the increased fuel costs resulting from the February 2021 winter storms. The redetermined rate became effective with the first billing cycle in April 2021 through the normal operation of the tariff.
In March 2022, Entergy Arkansas’sArkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, adjustment and referredwhich reflected an increase from $0.00959 per kWh to $0.01785 per kWh. The primary reason for the evaluationrate increase is a large under-recovered balance as a result of such mattershigher natural gas prices in 2021, particularly in the fourth quarter 2021. At the request of the APSC general staff, Entergy Arkansas deferred its request for recovery of $32 million from the under-recovery related to the opportunity sales2021 February winter storms until the 2023 energy cost rate redetermination, unless a request for an interim adjustment to the energy cost recovery proceeding.
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draft report issued in its 2021 February winter storm investigation docket, the APSC included findings that the load shedding plans of the investor-owned utilities and some cooperatives were appropriate and comprehensive, and, further, that Entergy Arkansas’s emergency plan was comprehensive and had a multilayered approach supported by a system-wide response plan, which is considered an industry standard.
Opportunity Sales Proceeding
In June 2009 the LPSC filed a complaint requesting that the FERC determine that certain of Entergy Arkansas’s sales of electric energy to third parties: (a) violated the provisions of the System Agreement that allocated the energy generated by Entergy System resources; (b) imprudently denied the Entergy System and its ultimate consumers the benefits of low-cost Entergy System generating capacity; and (c) violated the provision of the System Agreement that prohibited sales to third parties by individual companies absent an offer of a right-of-first-refusal to other Utility operating companies. The LPSC’s complaint challenged sales made beginning in 2002 and requested refunds. In July 2009 the Utility operating companies filed a response to the complaint arguing among other things that the System Agreement contemplates that the Utility operating companies may make sales to third parties for their own account, subject to the requirement that those sales be included in the load (or load shape) for the applicable Utility operating company. The FERC subsequently ordered a hearing in the proceeding.
After a hearing, the ALJ issued an initial decision in December 2010. The ALJ found that the System Agreement allowed for Entergy Arkansas to make the sales to third parties but concluded that the sales should be accounted for in the same manner as joint account sales. The ALJ concluded that “shareholders” should make refunds of the damages to the Utility operating companies, along with interest. Entergy disagreed with several aspects of the ALJ’s initial decision and in January 2011 filed with the FERC exceptions to the decision.
The FERC issued a decision in June 2012 and held that, while the System Agreement is ambiguous, it does provide authority for individual Utility operating companies to make opportunity sales for their own account and Entergy Arkansas made and priced these sales in good faith. The FERC found, however, that the System Agreement does not provide authority for an individual Utility operating company to allocate the energy associated with such opportunity sales as part of its load but provides a different allocation authority. The FERC further found that the after-the-fact accounting methodology used to allocate the energy used to supply the sales was inconsistent with the System Agreement. The FERC in its decision established further hearing procedures to quantify the effect of repricing the opportunity sales in accordance with the FERC’s June 2012 decision. The hearing was held in May 2013 and the ALJ issued an initial decision in August 2013. The LPSC, the APSC, the City Council, and FERC staff filed briefs on exceptions and/or briefs opposing exceptions. Entergy filed a brief on exceptions requesting that the FERC reverse the initial decision and a brief opposing certain exceptions taken by the LPSC and FERC staff.
In April 2016 the FERC issued orders addressing requests for rehearing filed in July 2012 and the ALJ’s August 2013 initial decision. The first order denied Entergy’s request for rehearing and affirmed the FERC’s earlier rulings that Entergy’s original methodology for allocating energy costs to the opportunity sales was incorrect and, as a result, Entergy Arkansas must make payments to the other Utility operating companies to put them in the same position that they would have been in absent the incorrect allocation. The FERC clarified that interest should be included with the payments. The second order affirmed in part, and reversed in part, the rulings in the ALJ’s August 2013 initial decision regarding the methodology that should be used to calculate the payments Entergy Arkansas is to make to the other Utility operating companies. The FERC affirmed the ALJ’s ruling that a full re-run of intra-system bills should be performed but required that methodology be modified so that the sales have the same priority for purposes of energy allocation as joint account sales. The FERC reversed the ALJ’s decision that any payments by Entergy Arkansas should be reduced by 20%. The FERC also reversed the ALJ’s decision that adjustments to other System Agreement service schedules and excess bandwidth payments should not be taken into account when calculating the payments to be made by Entergy Arkansas. The FERC held that such adjustments and excess bandwidth payments should be taken into account but ordered further proceedings before an ALJ to address
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Management’s Financial Discussion and Analysis
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
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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.appeal.
The hearing required by the FERC’s April 2016 order was held in May 2017. In July 2017 the ALJ issued an initial decision addressing whether a cap on any reduction due to bandwidth payments was necessary and whether to implement the other adjustments to the calculation methodology. In August 2017 the Utility operating companies, the LPSC, the APSC, and FERC staff filed individual briefs on exceptions challenging various aspects of the initial decision. In September 2017 the Utility operating companies, the LPSC, the APSC, the MPSC, the City Council, and FERC staff filed separate briefs opposing exceptions taken by various parties.
Based on testimony previously submitted in the case and its assessment of the April 2016 FERC orders, in the first quarter 2016, Entergy Arkansas recorded a liability of $87 million, which included interest, for its estimated increased costs and payment to the other Utility operating companies, and a deferred fuel regulatory asset of $75 million. Following its assessment of the course of the proceedings, including the FERC’s denial of rehearing in November 2017 described above, in the fourth quarter 2017, Entergy Arkansas recorded an additional liability of $35 million and a regulatory asset of $31 million.
In October 2018 the FERC issued an order addressing the ALJ’s July 2017 initial decision. The FERC reversed the ALJ’s decision to cap the reduction in Entergy Arkansas’s payment to account for the increased bandwidth payments that Entergy Arkansas made to the other operating companies. The FERC also reversed the ALJ’s decision that Grand Gulf sales from January through September 2000 should be included in the calculation of Entergy Arkansas’s payment. The FERC affirmed on other grounds the ALJ’s rejection of the LPSC’s claim that certain joint account sales should be accounted for as part of the calculation of Entergy Arkansas’s payment. In November 2018 the LPSC requested rehearing of the FERC’s October 2018 decision. In December 2019 the FERC denied the LPSC’s request for rehearing. In January 2020 the LPSC appealed the December 2019 decision to the D.C. Circuit.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
In December 2018, Entergy made a compliance filing in response to the FERC’s October 2018 order. The compliance filing provided a final calculation of Entergy Arkansas’s payments to the other Utility operating companies, including interest. No protests were filed in response to the December 2018 compliance filing. The December 2018 compliance filing is pending FERC action. Refunds and interest in the following amounts were paid by Entergy Arkansas to the other operating companies in December 2018:
| | | | | | | | | | | |
| | Total refunds including interest |
| Payment/(Receipt) |
| | (In Millions) |
| Principal | Interest | Total |
| Entergy Arkansas | $68 | $67 | $135 |
| Entergy Louisiana | ($30) | ($29) | ($59) |
| Entergy Mississippi | ($18) | ($18) | ($36) |
| Entergy New Orleans | ($3) | ($4) | ($7) |
| Entergy Texas | ($17) | ($16) | ($33) |
Entergy Arkansas previously recognized a regulatory asset with a balance of $116 million as of December 31, 2018 for a portion of the payments due as a result of this proceeding.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
In February 2019 the LPSC filed a new complaint relating to two issues that were raised in the opportunity sales proceeding, but that, in its October 2018 order, the FERC held were outside the scope of the proceeding. In March 2019, Entergy Services filed an answer and motion to dismiss the new complaint. In November 2019 the FERC issued an order denying the LPSC’s complaint. The order concluded that the settlement agreement approved by the FERC in December 2015 terminating the System Agreement barred the LPSC’s new complaint.
In 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
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
arguments, including demonstrating that the claims in this proceeding differ substantially from those the APSC addressed previously and that the payment resulting from a FERC tariff violation for which Entergy Arkansas seeks retail cost recovery in this proceeding differs materially from the refunds resulting from a FERC tariff amendment that the APSC previously rejected on filed rate doctrine and the retroactive ratemaking grounds. In addition, in January 2020 the Attorney General and Arkansas Electric Energy Consumers, Inc. filed testimony opposing the recovery by Entergy Arkansas of the opportunity sales payment but also claiming that certain components of the payment should be segregated and refunded to customers. In March 2020, Entergy Arkansas filed rebuttal testimony.
In July 2020 the APSC issued a decision finding that Entergy Arkansas’s application is not in the public interest. The order also directed Entergy Arkansas to refund to its retail customers within 30 days of the order the FERC-determined over-collection of $13.7 million, plus interest, associated with a recalculated bandwidth remedy. In addition to these primary findings, the order also denied the Attorney General’s request for Entergy Arkansas to prepare a compliance filing detailing all of the retail impacts from the opportunity sales and denied a request by the Arkansas Electric Energy Consumers to recalculate all costs using the revised responsibility ratio. Entergy Arkansas filed a motion for temporary stay of the 30-day requirement to allow Entergy Arkansas a reasonable opportunity to seek rehearing of the APSC order, but in July 2020 the APSC denied Entergy Arkansas’s request for a stay and directed Entergy Arkansas to refund to its retail customers the component of the total FERC-determined opportunity sales payment that was associated with increased bandwidth remedy payments of $13.7 million, plus interest. The refunds were issued in the August 2020 billing cycle. While the APSC denied Entergy Arkansas’s stay request, Entergy Arkansas believes its actions were prudent and, therefore, the costs, including the $13.7 million, plus interest, are recoverable. In July 2020, Entergy Arkansas requested rehearing of the APSC order, which rehearing was denied by the APSC in August 2020. In September 2020, Entergy Arkansas filed a complaint in the U.S. District Court for the Eastern District of Arkansas challenging the APSC’s order denying Entergy Arkansas’s request to recover the costs of these payments. In October 2020 the APSC filed a motion to dismiss Entergy Arkansas’s complaint, to which Entergy Arkansas responded. Also in December 2020, Entergy Arkansas and the APSC held a pre-trial conference, and filed a report with the court in January 2021. The court held a hearing in February 2021 regarding issues addressed in the pre-trial conference report, and in June 2021 the court stayed all discovery until it rules on pending motions, after which the court will issue an amended schedule if necessary. In March 2022 the court denied the APSC’s motion to dismiss, and, in April 2022, issued a scheduling order including a trial date in February 2023. In June 2022, Entergy Arkansas filed a motion asserting that it is entitled to summary judgment because Entergy Arkansas’s position that the APSC’s order is pre-empted by the filed rate doctrine and violates the Dormant Commerce Clause is premised on facts that are not subject to genuine dispute. In July 2022, Arkansas Electric Energy Consumers, Inc., an industrial customer association, filed a motion to intervene and to hold Entergy Arkansas’s motion for summary judgment in abeyance pending a ruling on the motion to intervene. Entergy Arkansas filed a consolidated opposition to both motions. In August 2022 the APSC filed a motion for summary judgment arguing that there is no genuine issue as to any material fact and the APSC is entitled to judgment as a matter of law. In September 2022, Entergy Arkansas filed an opposition to the motion. In October 2022 the APSC filed a motion asking the court to hold further proceedings in abeyance pending a decision on the motions for summary judgment filed by Entergy Arkansas and the APSC. Also in October 2022, Entergy Arkansas filed an opposition to the motion, and the APSC filed a reply in support of its motion for summary judgment. In January 2023 the judge assigned to the case, on her own motion, identified facts that may present a conflict and recused herself; a new judge was assigned to the case, but he also recused due to a conflict. The case again was reassigned to a new judge. In January 2023 the court denied all pending motions (including those described above) except for a motion by the APSC to exclude certain testimony and further ruled that the matter would proceed to trial. In January 2023, Arkansas Electric Energy Consumers, Inc. filed a notice of appeal of the court’s order denying its motion to intervene to the United States Court of Appeals for the Eighth Circuit and a motion with the district court to stay the proceedings pending the appeal, which was denied. In February 2023, Arkansas Electric Energy Consumers, Inc. filed a motion with the United States Court of Appeals for the Eighth District to stay the proceedings pending the appeal, which also was denied. The trial was held in February 2023. Following the trial, Entergy Arkansas filed a motion with the United States Court of Appeals for the Eighth District
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
to expedite the appeal filed by Arkansas Electric Energy Consumers, Inc. The court granted Entergy Arkansas’s request.
Net Metering Legislation
An Arkansas law was enacted effective July 2019 that, among other things, expands the definition of a “net metering customer” to include two additional types of customers: (1) customers that lease net metering facilities, subject to certain leasing arrangements, and (2) government entities or other entities exempt from state and federal income taxes that enter into a service contract for a net metering facility. The latter provision would allowallows eligible entities, many of whom are small and large general service customers, to purchase renewable energy directly from third party providers and receive bill credits for these purchases. The APSC was given authority under this law to address certain matters, such as cost shifting and the appropriate compensation for net metered energy and has initiated proceedings for this purpose. Because of the size and number of customers eligible under this new law, there is a risk of loss of load and the shifting of costs to customers. A hearing was held in December 2019, with utilities, including Entergy Arkansas, cooperatives, the Arkansas Attorney General, and industrial customers and Entergy Arkansas advocating the need for establishment of a reasonable rate structure that takes into account impacts to non-net metering customers. customers; an additional hearing was conducted in February 2020 for purposes of public comment only. The APSC issued an order in June 2020, and in July 2020 several parties, including Entergy Arkansas, filed for rehearing on multiple grounds, including for the reasons that it imposes an unreasonable rate structure and allows facilities to net meter that do not meet the statutory definition of net metering facilities. After granting the rehearing requests, the APSC issued an order in September 2020 largely upholding its June 2020 order. In October 2020, Entergy Arkansas and several other parties filed an appeal of the APSC’s September 2020 order. In January 2021, Entergy Arkansas, pursuant to an APSC order, filed an updated net metering tariff, which was approved in February 2021. In May 2021, Entergy Arkansas filed a motion to dismiss its pending judicial appeal of the APSC’s September 2020 order on rehearing in the proceeding addressing its net metering rules. In June 2021 the Arkansas Court of Appeals granted the motion and dismissed Entergy Arkansas’s appeal, although other appeals of the September 2020 APSC order remained before the court. In May 2022 the court issued an order affirming the APSC’s decision in part and reversing in part. In June 2022 the APSC sought rehearing from the court with respect to the court’s ruling on a grid charge, which the court of appeals denied in July 2022. One of the cooperative appellants filed a further appeal to the Arkansas Supreme Court in July 2022, which the court decided not to hear.
Separately, as directed by the APSC general staff, the APSC opened a proceeding to compel utilities to amend their net metering tariffs to incorporate the provisions of the legislation that the APSC general staff considered “black letter law.” Entergy Arkansas, the Arkansas Attorney General, and other intervenors opposed this directive pending the development of the rules for implementation that are being considered in the separate net metering rulemaking docket. Nevertheless, reserving its rights, Entergy Arkansas has complied with the directive to amend its tariffs. Asserting procedural and due process violations, in January 2020, Entergy Arkansas and the Arkansas Attorney General separately appealed certain APSC orders in thisthe proceeding. In December 2021 the Arkansas Court of Appeals dismissed the appeal on procedural grounds and without prejudice.
In September 2022 the APSC opened a rulemaking concerning proposed amendments to the net metering rules to address the expiration on December 31, 2022 of the automatic grandfathering of the existing net metering rate structure. Entergy Arkansas and other utility parties filed initial briefs and comments setting forth that the statute imposing the expiration of the automatic grandfathering is not ambiguous and that the APSC does not have
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
the authority to extend the grandfathering period, and the hearing was held in October 2022. In December 2022 the APSC issued an order attempting to modify the net metering rules and purporting to allow for the potential for grandfathering after December 31, 2022. More than thirty applicants filed individual net metering applications in December 2022 seeking to be considered under the APSC’s order, although the APSC issued an order in January 2023 holding those applications in abeyance. Several parties, including Entergy Arkansas, sought rehearing, and the Arkansas’s Governor’s executive order limiting new rulemakings calls into question how the APSC’s order to adopt new rules may be effectuated.
Also in September 2022 the APSC opened another proceeding to investigate the issue of potential cost shifting arising as a result of net metering. Investor owned utilities and some cooperatives were required to make and did make filings in October 2022 with supporting documentation as to the amount and extent of cost shifting and the manner in which they would design tariffs to recover those costs on behalf of non-net metering customers. Responses to the utility and cooperative filings were filed in January 2023, and utilities filed their further responses in February 2023.
COVID-19 Orders
In April 2020, in light of the COVID-19 pandemic, the APSC issued an order requiring utilities, to the extent they had not already done so, to suspend service disconnections during the remaining pendency of the Arkansas Governor’s emergency declaration or until the APSC rescinds the directive. The order also authorized utilities to establish a regulatory asset to record costs resulting from the suspension of service disconnections, directed that in future proceedings the APSC will consider whether the request for recovery of these regulatory assets is reasonable and necessary, and required utilities to track and report the costs and any savings directly attributable to suspension of disconnects. In May 2020 the APSC approved Entergy Arkansas expanding deferred payment agreements to assist customers during the COVID-19 pandemic. Quarterly reporting began in August 2020 and the APSC ordered additional reporting in October 2020 regarding utilities’ transitional plans for ending the moratorium on service disconnects. In March 2021 the APSC issued an order confirming the lifting of the moratorium on service disconnects effective in May 2021. In August 2021 the APSC general staff filed a report recommending that utilities with a formula rate plan discontinue capturing any additional direct costs and savings as a regulatory asset and seek cost recovery through the formula rate plan. The APSC general staff further recommended that uncollectible amounts should be determined as of the end of its write-off period, approximately December 2021, and recovered in the next formula rate plan filing over one year. In November 2021 the APSC found the APSC general staff’s recommendation to be premature and asked utilities to report on the continued need for a regulatory asset. Entergy Arkansas reported a continued need for a regulatory asset due to a variety of factors including the unusually long terms of the customer delayed payment agreements. As of December 31, 2022, Entergy Arkansas had a regulatory asset of $39 million for costs associated with the COVID-19 pandemic.
Remaining Useful Lives Review
In response to recent legislation, the APSC opened a proceeding in December 2022 to establish a procedure to evaluate life extensions of all utility generation units and opened a separate docket to evaluate life extensions for White Bluff, Independence, and Lake Catherine. In January 2023, Entergy Arkansas and one other party filed for rehearing of the order in the general proceeding, and Entergy Arkansas moved to dismiss the separate docket. In February 2023 the APSC granted rehearing in the general proceeding. For additional discussion related to these plants, see “Regulation of Entergy’s Business - Environmental Regulation - National Ambient Air Quality Standards - Regional Haze” in Part I, Item 1.
Federal Regulation
See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Nuclear Matters
Entergy Arkansas owns and, through an affiliate, operates the ANO 1 and ANO 2 nuclear power plants. Entergy Arkansas is, therefore, subject to the risks related to owning and operating nuclear plants. These include risks related to: the use, storage, and handling and disposal of high-level and low-level radioactive materials; the substantial financial requirements, both for capital investments and operational needs, to position Entergy’s nuclear fleet to meet its operational goals,goals; the performance and capacity factors of these nuclear plants including the financial requirements to address emerging issues like stress corrosion cracking of certain materials within the plant systems and the Fukushima event;related to equipment reliability; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license renewal and amendments, and decommissioning; the performance and capacity factors of these nuclear plants; the availability of interim or permanent sites for the disposal of spent nuclear fuel and nuclear waste, including the fees charged for such disposal; the sufficiency of nuclear decommissioning trust fund assets and earnings to complete decommissioning of each site when required; and limitations on the amounts and types of insurance commercially available for losses in connection with nuclear plant operations and catastrophic events such as a nuclear accident. In the event of an unanticipated early shutdown of either ANO 1 or ANO 2, Entergy Arkansas may be required to file with the APSC a rate mechanism to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. ANO 1’s operating license expires in 2034 and ANO 2’s operating license expires in 2038.
Environmental Risks
Entergy Arkansas’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Arkansas is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of Entergy Arkansas’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements that could produce estimates that would have a material effect on the presentation of Entergy Arkansas’s financial position or results of operations.
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 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.
Nuclear Decommissioning Costs
See “Nuclear Decommissioning Costs” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.
Utility Regulatory Accounting
See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Impairment of Long-lived Assets and Trust Fund Investments
See “Impairment of Long-lived Assets and Trust Fund Investments” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the impairment of long-lived assets and trust fund investments.assets.
Taxation and Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.
Qualified Pension and Other Postretirement Benefits
Entergy Arkansas’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Costs and Sensitivities
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2023 Qualified Pension Cost | | Impact on 2022 Qualified Projected Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $1,301 | | $26,969 |
| Rate of return on plan assets | | (0.25%) | | $2,600 | | $— |
| Rate of increase in compensation | | 0.25% | | $1,081 | | $5,122 |
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2020 Qualified Pension Cost | | Impact on 2019 Qualified Projected Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $2,633 | | $43,030 |
| Rate of return on plan assets | | (0.25%) | | $2,803 | | $— |
| Rate of increase in compensation | | 0.25% | | $1,650 | | $7,967 |
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2023 Postretirement Benefit Cost | | Impact on 2022 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $78 | | $4,097 |
| Health care cost trend | | 0.25% | | $287 | | $3,365 |
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2020 Postretirement Benefit Cost | | Impact on 2019 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $343 | | $5,316 |
| Health care cost trend | | 0.25% | | $430 | | $3,474 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Costs and Employer Contributions
Total qualified pension cost for Entergy Arkansas in 20192022 was $44.4 million.$74.8 million, including $36.4 million in settlement costs. Entergy Arkansas anticipates 20202023 qualified pension cost to be $61.1$34.1 million. Entergy Arkansas contributed $75.9$93 million to its qualified pension plans in 20192022 and estimates pension contributions will be approximately $32.5$54.5 million in 2020,2023, although the 20202023 required pension contributions will be known with more certainty when the January 1, 20202023 valuations are completed, which is expected by April 1, 2020.2023.
Total other postretirement health care and life insurance benefit income for Entergy Arkansas in 20192022 was $10.7$5.7 million. Entergy Arkansas expects 20202023 postretirement health care and life insurance benefit income of approximately $12.5$1.9 million. Entergy Arkansas contributed $1.3$1.6 million to its other postretirement plans in 20192022 and estimates 20202023 contributions will be approximately $509$526 thousand.
Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the member and Board of Directors of
Entergy Arkansas, LLC and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy Arkansas, LLC and Subsidiaries (the “Company”) as of December 31, 20192022 and 2018,2021, the related consolidated statements of income, cash flows and changes in member’s equity (pages 317340 through 322344 and applicable items in pages 4953 through 236)245), for each of the three years in the period ended December 31, 2019,2022, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20192022 and 2018,2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2022, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Rate and Regulatory Matters —Entergy Arkansas, LLC and Subsidiaries — Refer to Note 2 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Arkansas Public Service Commission (the “APSC”), which has jurisdiction with respect to the rates of electric companies in Arkansas, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.
The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the APSC and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the APSC and the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs, including costs related to the Opportunity Sales Proceeding and refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the APSC and the FERC, involved specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and significant auditor judgment to evaluate management estimates and the subjectivity of audit evidence.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the APSC and the FERC included the following, among others:
•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 Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
• We read relevant regulatory orders issued by the APSC and the FERC for the Company, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the APSC’s 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.
• For regulatory matters in process, including the Opportunity Sales Proceeding, we inspected the Company’s filings with the APSC and the FERC, including the annual formula rate plan filing, and considered the filings with the APSC and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.
• We obtained an analysis from management and support 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 not yet addressed in a regulatory order, including the Opportunity Sales Proceeding, to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 21, 202024, 2023
We have served as the Company’s auditor since 2001.
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | |
| | | For the Years Ended December 31, |
| | | 2022 | | 2021 | | 2020 |
| | | (In Thousands) |
| | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | | $2,673,194 | | | $2,338,590 | | | $2,084,494 | |
| | | | | | |
| OPERATING EXPENSES | | | | | | |
| Operation and Maintenance: | | | | | | |
| Fuel, fuel-related expenses, and gas purchased for resale | | 640,344 | | | 347,166 | | | 271,896 | |
| Purchased power | | 201,726 | | | 280,504 | | | 187,690 | |
| Nuclear refueling outage expenses | | 53,438 | | | 51,141 | | | 55,737 | |
| Other operation and maintenance | | 754,293 | | | 687,418 | | | 669,518 | |
| Decommissioning | | 82,326 | | | 77,696 | | | 73,319 | |
| Taxes other than income taxes | | 136,565 | | | 127,249 | | | 121,057 | |
| Depreciation and amortization | | 386,272 | | | 361,479 | | | 338,029 | |
| Other regulatory charges (credits) - net | | (89,418) | | | (31,501) | | | (35,310) | |
| TOTAL | | 2,165,546 | | | 1,901,152 | | | 1,681,936 | |
| | | | | | |
| OPERATING INCOME | | 507,648 | | | 437,438 | | | 402,558 | |
| | | | | | |
| OTHER INCOME | | | | | | |
| Allowance for equity funds used during construction | | 17,787 | | | 15,273 | | | 15,019 | |
| Interest and investment income | | 19,554 | | | 76,953 | | | 35,579 | |
| Miscellaneous - net | | (27,348) | | | (22,278) | | | (21,908) | |
| TOTAL | | 9,993 | | | 69,948 | | | 28,690 | |
| | | | | | |
| INTEREST EXPENSE | | | | | | |
| Interest expense | | 150,928 | | | 140,348 | | | 144,834 | |
| Allowance for borrowed funds used during construction | | (7,070) | | | (6,641) | | | (6,595) | |
| TOTAL | | 143,858 | | | 133,707 | | | 138,239 | |
| | | | | | |
| INCOME BEFORE INCOME TAXES | | 373,783 | | | 373,679 | | | 293,009 | |
| | | | | | |
| Income taxes | | 80,896 | | | 75,195 | | | 47,777 | |
| | | | | | |
| NET INCOME | | 292,887 | | | 298,484 | | | 245,232 | |
| | | | | | |
| Net loss attributable to noncontrolling interest | | (4,358) | | | (18,092) | | | — | |
| | | | | | |
| EARNINGS APPLICABLE TO MEMBER'S EQUITY | | $297,245 | | | $316,576 | | | $245,232 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | | |
| | | For the Years Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | |
| $2,259,594 |
| |
| $2,060,643 |
| |
| $2,139,919 |
|
| | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 458,907 |
| | 517,245 |
| | 402,777 |
|
| Purchased power | | 204,640 |
| | 252,390 |
| | 230,652 |
|
| Nuclear refueling outage expenses | | 68,769 |
| | 77,915 |
| | 83,968 |
|
| Other operation and maintenance | | 720,217 |
| | 724,831 |
| | 694,157 |
|
| Decommissioning | | 68,030 |
| | 60,420 |
| | 56,860 |
|
| Taxes other than income taxes | | 115,869 |
| | 104,771 |
| | 103,662 |
|
| Depreciation and amortization | | 307,351 |
| | 292,649 |
| | 277,146 |
|
| Other regulatory credits - net | | (11,186 | ) | | (14,807 | ) | | (16,074 | ) |
| TOTAL | | 1,932,597 |
| | 2,015,414 |
| | 1,833,148 |
|
| | | | | | | |
| OPERATING INCOME | | 326,997 |
| | 45,229 |
| | 306,771 |
|
| | | | | | | |
| OTHER INCOME | | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 15,499 |
| | 16,557 |
| | 18,452 |
|
| Interest and investment income | | 26,020 |
| | 25,406 |
| | 35,882 |
|
| Miscellaneous - net | | (18,566 | ) | | (14,874 | ) | | (13,967 | ) |
| TOTAL | | 22,953 |
| | 27,089 |
| | 40,367 |
|
| | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
|
| Interest expense | | 140,087 |
| | 124,459 |
| | 122,075 |
|
| Allowance for borrowed funds used during construction | | (6,332 | ) | | (7,781 | ) | | (8,585 | ) |
| TOTAL | | 133,755 |
| | 116,678 |
| | 113,490 |
|
| | | | | | | |
| INCOME (LOSS) BEFORE INCOME TAXES | | 216,195 |
| | (44,360 | ) | | 233,648 |
|
| | | | | | | |
| Income taxes | | (46,769 | ) | | (297,067 | ) | | 93,804 |
|
| | | | | | | |
| NET INCOME | | 262,964 |
| | 252,707 |
| | 139,844 |
|
| | | | | | | |
| Preferred dividend requirements | | — |
| | 1,249 |
| | 1,428 |
|
| | | | | | | |
| EARNINGS APPLICABLE TO COMMON EQUITY | |
| $262,964 |
| |
| $251,458 |
| |
| $138,416 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
(Page left blank intentionally)
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | |
| | | For the Years Ended December 31, |
| | | 2022 | | 2021 | | 2020 |
| | | (In Thousands) |
| | | | | | |
| OPERATING ACTIVITIES | | | | | | |
| Net income | | $292,887 | | | $298,484 | | | $245,232 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 532,291 | | | 503,539 | | | 490,457 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 78,958 | | | 100,459 | | | 87,019 | |
| Changes in assets and liabilities: | | | | | | |
| Receivables | | (73,579) | | | 17,682 | | | (24,507) | |
| Fuel inventory | | (252) | | | (7,081) | | | (10,066) | |
| Accounts payable | | 64,944 | | | 27,967 | | | (22,773) | |
| Taxes accrued | | 10,936 | | | 7,753 | | | 6 | |
| Interest accrued | | 1,708 | | | (5,637) | | | (43) | |
| Deferred fuel costs | | (31,009) | | | (162,458) | | | (1,186) | |
| Other working capital accounts | | (29,789) | | | (53,343) | | | (11,061) | |
| Provisions for estimated losses | | 2,914 | | | 6,915 | | | 6,289 | |
| Other regulatory assets | | (120,603) | | | 142,706 | | | (165,534) | |
| Other regulatory liabilities | | (264,054) | | | 21,066 | | | 106,878 | |
| | | | | | |
| Pension and other postretirement liabilities | | (67,783) | | | (175,863) | | | 42,576 | |
| Other assets and liabilities | | 302,163 | | | (172,973) | | | (83,469) | |
| Net cash flow provided by operating activities | | 699,732 | | | 549,216 | | | 659,818 | |
| INVESTING ACTIVITIES | | | | | | |
| Construction expenditures | | (785,168) | | | (722,628) | | | (775,595) | |
| Allowance for equity funds used during construction | | 17,787 | | | 15,273 | | | 15,019 | |
| Nuclear fuel purchases | | (98,635) | | | (84,302) | | | (100,678) | |
| Proceeds from sale of nuclear fuel | | 37,198 | | | 16,279 | | | 30,638 | |
| | | | | | |
| Proceeds from nuclear decommissioning trust fund sales | | 248,191 | | | 530,628 | | | 321,360 | |
| Investment in nuclear decommissioning trust funds | | (269,497) | | | (524,783) | | | (336,392) | |
| Payment for purchase of assets | | (1,044) | | | (131,770) | | | (5,988) | |
| Changes in money pool receivable - net | | — | | | 3,110 | | | (3,110) | |
| | | | | | |
| | | | | | |
| | | | | | |
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | — | | | — | | | 55,001 | |
| | | | | | |
| | | | | | |
| Other | | (1,626) | | | — | | | 4,036 | |
| Net cash flow used in investing activities | | (852,794) | | | (898,193) | | | (795,709) | |
| FINANCING ACTIVITIES | | | | | | |
| Proceeds from the issuance of long-term debt | | 232,731 | | | 719,284 | | | 1,071,121 | |
| Retirement of long-term debt | | (28,521) | | | (728,917) | | | (632,175) | |
| | | | | | |
| Capital contributions from noncontrolling interest | | — | | | 51,202 | | | — | |
| | | | | | |
| Changes in money pool payable - net | | 40,891 | | | 139,904 | | | (21,634) | |
| | | | | | |
| | | | | | |
| Common equity distributions paid | | (86,000) | | | (50,000) | | | (95,000) | |
| | | | | | |
| Other | | (13,676) | | | 38,291 | | | 2,188 | |
| Net cash flow provided by financing activities | | 145,425 | | | 169,764 | | | 324,500 | |
| Net increase (decrease) in cash and cash equivalents | | (7,637) | | | (179,213) | | | 188,609 | |
| Cash and cash equivalents at beginning of period | | 12,915 | | | 192,128 | | | 3,519 | |
| Cash and cash equivalents at end of period | | $5,278 | | | $12,915 | | | $192,128 | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | |
| Cash paid (received) during the period for: | | | | | | |
| Interest - net of amount capitalized | | $147,060 | | | $143,561 | | | $140,735 | |
| Income taxes | | ($2,753) | | | ($18,933) | | | ($21,971) | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
|
|
|
| |
| For the Years Ended December 31, |
| |
| 2019 |
| 2018 |
| 2017 |
| |
| (In Thousands) |
| OPERATING ACTIVITIES | | | | | | |
| Net income | |
| $262,964 |
| |
| $252,707 |
| |
| $139,844 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 465,299 |
| | 443,698 |
| | 427,394 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 94,368 |
| | 129,524 |
| | 67,711 |
|
| Changes in assets and liabilities: | | |
| | |
| | |
|
| Receivables | | (58,077 | ) | | 4,294 |
| | (23,397 | ) |
| Fuel inventory | | (10,597 | ) | | 6,210 |
| | 3,402 |
|
| Accounts payable | | 3,059 |
| | (126,405 | ) | | 16,011 |
|
| Prepaid taxes and taxes accrued | | 24,942 |
| | 9,568 |
| | 40,127 |
|
| Interest accrued | | 3,895 |
| | 678 |
| | 1,635 |
|
| Deferred fuel costs | | 72,560 |
| | 43,869 |
| | 33,190 |
|
| Other working capital accounts | | 18,783 |
| | (30,118 | ) | | 15,087 |
|
| Provisions for estimated losses | | 14,901 |
| | 14,250 |
| | 16,047 |
|
| Other regulatory assets | | (131,873 | ) | | 32,460 |
| | (76,762 | ) |
| Other regulatory liabilities | | 39,293 |
| | (341,682 | ) | | 1,043,507 |
|
| Deferred tax rate change recognized as regulatory liability/asset | | — |
| | — |
| | (1,047,837 | ) |
| Pension and other postretirement liabilities | | 5,831 |
| | (40,157 | ) | | (70,826 | ) |
| Other assets and liabilities | | (127,582 | ) | | (187,071 | ) | | (29,577 | ) |
| Net cash flow provided by operating activities | | 677,766 |
| | 211,825 |
| | 555,556 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
|
| Construction expenditures | | (641,525 | ) | | (660,044 | ) | | (735,816 | ) |
| Allowance for equity funds used during construction | | 15,306 |
| | 17,013 |
| | 19,211 |
|
| Nuclear fuel purchases | | (54,344 | ) | | (99,417 | ) | | (151,424 | ) |
| Proceeds from sale of nuclear fuel | | 22,782 |
| | 54,810 |
| | 51,029 |
|
| Proceeds from nuclear decommissioning trust fund sales | | 317,377 |
| | 300,801 |
| | 339,434 |
|
| Investment in nuclear decommissioning trust funds | | (336,519 | ) | | (315,163 | ) | | (352,138 | ) |
| Insurance proceeds | | — |
| | 14,790 |
| | — |
|
| Other | | 630 |
| | (1,517 | ) | | 392 |
|
| Net cash flow used in investing activities | | (676,293 | ) |
| (688,727 | ) |
| (829,312 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | 834,038 |
| | 958,434 |
| | 294,656 |
|
| Retirement of long-term debt | | (548,952 | ) | | (690,488 | ) | | (175,560 | ) |
| Capital contribution from parent | | — |
| | 350,000 |
| | — |
|
| Redemption of preferred stock | | — |
| | (32,660 | ) | | — |
|
| Change in money pool payable - net | | (161,104 | ) | | 16,601 |
| | 114,905 |
|
| Changes in short-term borrowings - net | | — |
| | (49,974 | ) | | 49,974 |
|
| Distributions/dividends paid: | | |
| | |
| | |
|
| Common equity | | (115,000 | ) | | (91,751 | ) | | (15,000 | ) |
| Preferred stock | | — |
| | (1,606 | ) | | (1,428 | ) |
| Other | | (7,055 | ) | | 12,249 |
| | (8,084 | ) |
| Net cash flow provided by financing activities | | 1,927 |
| | 470,805 |
| | 259,463 |
|
| Net increase (decrease) in cash and cash equivalents | | 3,400 |
| | (6,097 | ) | | (14,293 | ) |
| Cash and cash equivalents at beginning of period | | 119 |
| | 6,216 |
| | 20,509 |
|
| Cash and cash equivalents at end of period | |
| $3,519 |
| |
| $119 |
| |
| $6,216 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $131,134 |
| |
| $118,731 |
| |
| $115,162 |
|
| Income taxes | |
| ($33,989 | ) | |
| $44,393 |
| |
| ($8,141 | ) |
| See Notes to Financial Statements. |
| |
|
| |
|
| |
|
| | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | |
| | | December 31, |
| | | 2022 | | 2021 |
| | | (In Thousands) |
| | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | | $1,911 | | | $8,155 | |
| Temporary cash investments | | 3,367 | | | 4,760 | |
| Total cash and cash equivalents | | 5,278 | | | 12,915 | |
| | | | |
| Accounts receivable: | | | | |
| Customer | | 140,513 | | | 154,412 | |
| Allowance for doubtful accounts | | (6,528) | | | (13,072) | |
| Associated companies | | 45,336 | | | 29,587 | |
| Other | | 101,096 | | | 51,064 | |
| Accrued unbilled revenues | | 116,816 | | | 101,663 | |
| Total accounts receivable | | 397,233 | | | 323,654 | |
| | | | |
| Deferred fuel costs | | 139,739 | | | 108,862 | |
| Fuel inventory - at average cost | | 51,144 | | | 50,892 | |
| Materials and supplies - at average cost | | 288,260 | | | 247,980 | |
| Deferred nuclear refueling outage costs | | 56,443 | | | 65,318 | |
| | | | |
| | | | |
| Prepayments and other | | 26,576 | | | 14,863 | |
| | | | |
| TOTAL | | 964,673 | | | 824,484 | |
| | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | |
| Decommissioning trust funds | | 1,199,860 | | | 1,438,416 | |
| | | | |
| Other | | 2,414 | | | 947 | |
| TOTAL | | 1,202,274 | | | 1,439,363 | |
| | | | |
| UTILITY PLANT | | | | |
| Electric | | 14,077,844 | | | 13,578,297 | |
| | | | |
| Construction work in progress | | 417,244 | | | 241,127 | |
| Nuclear fuel | | 176,174 | | | 182,055 | |
| TOTAL UTILITY PLANT | | 14,671,262 | | | 14,001,479 | |
| Less - accumulated depreciation and amortization | | 5,729,304 | | | 5,472,296 | |
| UTILITY PLANT - NET | | 8,941,958 | | | 8,529,183 | |
| | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | |
| Regulatory assets: | | | | |
| | | | |
| Other regulatory assets | | 1,810,281 | | | 1,689,678 | |
| Deferred fuel costs | | 68,883 | | | 68,751 | |
| Other | | 18,507 | | | 13,660 | |
| TOTAL | | 1,897,671 | | | 1,772,089 | |
| | | | |
| TOTAL ASSETS | | $13,006,576 | | | $12,565,119 | |
| | | | |
| See Notes to Financial Statements. | | | | |
|
| | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | | |
| | | December 31, |
| | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | |
| $3,519 |
| |
| $118 |
|
| Temporary cash investments | | — |
| | 1 |
|
| Total cash and cash equivalents | | 3,519 |
| | 119 |
|
| Securitization recovery trust account | | 4,036 |
| | 4,666 |
|
| Accounts receivable: | | |
| | |
|
| Customer | | 117,679 |
| | 94,348 |
|
| Allowance for doubtful accounts | | (1,169 | ) | | (1,264 | ) |
| Associated companies | | 29,178 |
| | 48,184 |
|
| Other | | 117,653 |
| | 64,393 |
|
| Accrued unbilled revenues | | 108,489 |
| | 108,092 |
|
| Total accounts receivable | | 371,830 |
| | 313,753 |
|
| Deferred fuel costs | | — |
| | 19,235 |
|
| Fuel inventory - at average cost | | 33,745 |
| | 23,148 |
|
| Materials and supplies - at average cost | | 211,320 |
| | 196,314 |
|
| Deferred nuclear refueling outage costs | | 48,875 |
| | 78,966 |
|
| Prepayments and other | | 14,096 |
| | 14,553 |
|
| TOTAL | | 687,421 |
| | 650,754 |
|
| | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
|
| Decommissioning trust funds | | 1,101,283 |
| | 912,049 |
|
| Other | | 345 |
| | 5,480 |
|
| TOTAL | | 1,101,628 |
| | 917,529 |
|
| | | | | |
| UTILITY PLANT | | |
| | |
|
| Electric | | 12,293,483 |
| | 11,611,041 |
|
| Construction work in progress | | 197,775 |
| | 243,731 |
|
| Nuclear fuel | | 195,547 |
| | 220,602 |
|
| TOTAL UTILITY PLANT | | 12,686,805 |
| | 12,075,374 |
|
| Less - accumulated depreciation and amortization | | 5,019,826 |
| | 4,864,818 |
|
| UTILITY PLANT - NET | | 7,666,979 |
| | 7,210,556 |
|
| | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
|
| Regulatory assets: | | |
| | |
|
| Other regulatory assets (includes securitization property of $1,706 as of December 31, 2019 and $14,329 as of December 31, 2018) | | 1,666,850 |
| | 1,534,977 |
|
| Deferred fuel costs | | 67,690 |
| | 67,294 |
|
| Other | | 15,065 |
| | 20,486 |
|
| TOTAL | | 1,749,605 |
| | 1,622,757 |
|
| | | | | |
| TOTAL ASSETS | |
| $11,205,633 |
| |
| $10,401,596 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
| | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | |
| | | December 31, |
| | | 2022 | | 2021 |
| | | (In Thousands) |
| | | | |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | | $290,000 | | | $— | |
| | | | |
| Accounts payable: | | | | |
| Associated companies | | 276,362 | | | 217,310 | |
| Other | | 310,339 | | | 190,476 | |
| Customer deposits | | 102,799 | | | 92,511 | |
| Taxes accrued | | 100,526 | | | 89,590 | |
| | | | |
| Interest accrued | | 18,816 | | | 17,108 | |
| | | | |
| | | | |
| Other | | 43,394 | | | 38,901 | |
| TOTAL | | 1,142,236 | | | 645,896 | |
| | | | |
| NON-CURRENT LIABILITIES | | | | |
| Accumulated deferred income taxes and taxes accrued | | 1,498,234 | | | 1,416,201 | |
| Accumulated deferred investment tax credits | | 28,472 | | | 29,299 | |
| Regulatory liability for income taxes - net | | 435,157 | | | 431,655 | |
| Other regulatory liabilities | | 475,758 | | | 743,314 | |
| Decommissioning | | 1,472,736 | | | 1,390,410 | |
| Accumulated provisions | | 79,998 | | | 77,084 | |
| Pension and other postretirement liabilities | | 118,020 | | | 185,789 | |
| Long-term debt | | 3,876,500 | | | 3,958,862 | |
| Other | | 97,650 | | | 110,754 | |
| TOTAL | | 8,082,525 | | | 8,343,368 | |
| | | | |
| Commitments and Contingencies | | | | |
| | | | |
| | | | |
| | | | |
| EQUITY | | | | |
| Member's equity | | 3,753,990 | | | 3,542,745 | |
| Noncontrolling interest | | 27,825 | | | 33,110 | |
| TOTAL | | 3,781,815 | | | 3,575,855 | |
| | | | |
| TOTAL LIABILITIES AND EQUITY | | $13,006,576 | | | $12,565,119 | |
| | | | |
| See Notes to Financial Statements. | | | | |
|
| | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | | |
| | | December 31, |
| | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | |
| CURRENT LIABILITIES | | | | |
| Accounts payable: | | |
| | |
|
| Associated companies | |
| $111,785 |
| |
| $251,768 |
|
| Other | | 202,201 |
| | 187,387 |
|
| Customer deposits | | 101,411 |
| | 99,053 |
|
| Taxes accrued | | 81,831 |
| | 56,889 |
|
| Interest accrued | | 22,788 |
| | 18,893 |
|
| Deferred fuel costs | | 53,721 |
| | — |
|
| Current portion of unprotected excess accumulated deferred income taxes | | 9,296 |
| | 99,316 |
|
| Other | | 38,760 |
| | 23,943 |
|
| TOTAL | | 621,793 |
| | 737,249 |
|
| | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 1,183,126 |
| | 1,085,545 |
|
| Accumulated deferred investment tax credits | | 31,701 |
| | 32,903 |
|
| Regulatory liability for income taxes - net | | 478,174 |
| | 505,748 |
|
| Other regulatory liabilities | | 559,555 |
| | 402,668 |
|
| Decommissioning | | 1,242,616 |
| | 1,048,428 |
|
| Accumulated provisions | | 63,880 |
| | 48,979 |
|
| Pension and other postretirement liabilities | | 319,075 |
| | 313,295 |
|
| Long-term debt (includes securitization bonds of $6,772 as of December 31, 2019 and $20,898 as of December 31, 2018) | | 3,517,208 |
| | 3,225,759 |
|
| Other | | 62,568 |
| | 17,919 |
|
| TOTAL | | 7,457,903 |
| | 6,681,244 |
|
| | | | | |
| Commitments and Contingencies | |
|
| |
|
|
| | | | | |
| EQUITY | | |
| | |
|
| Member's equity | | 3,125,937 |
| | 2,983,103 |
|
| TOTAL | | 3,125,937 |
| | 2,983,103 |
|
| | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $11,205,633 |
| |
| $10,401,596 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
| | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| For the Years Ended December 31, 2022, 2021, and 2020 |
| | | | | |
| | Noncontrolling Interest | | Member's Equity | | Total |
| | (In Thousands) |
| | | | | |
| Balance at December 31, 2019 | $— | | | $3,125,937 | | | $3,125,937 | |
| Net income | — | | | 245,232 | | | 245,232 | |
| | | | | |
| | | | | |
| Common equity distributions | — | | | (95,000) | | | (95,000) | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Balance at December 31, 2020 | $— | | | $3,276,169 | | | $3,276,169 | |
| Net income (loss) | (18,092) | | | 316,576 | | | 298,484 | |
| | | | | |
| | | | | |
| Common equity distributions | — | | | (50,000) | | | (50,000) | |
| | | | | |
| | | | | |
| Capital contributions from noncontrolling interest | 51,202 | | | — | | | 51,202 | |
| | | | | |
| Balance at December 31, 2021 | $33,110 | | | $3,542,745 | | | $3,575,855 | |
| Net income (loss) | (4,358) | | | 297,245 | | | 292,887 | |
| | | | | |
| | | | | |
| Common equity distributions | — | | | (86,000) | | | (86,000) | |
| | | | | |
| | | | | |
| | | | | |
| Distributions to noncontrolling interest | (927) | | | — | | | (927) | |
| | | | | |
| Balance at December 31, 2022 | $27,825 | | | $3,753,990 | | | $3,781,815 | |
| | | | | |
| See Notes to Financial Statements. | | | | | |
|
| | | |
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY |
For the Years Ended December 31, 2019, 2018, and 2017 |
| |
| |
| Member's Equity |
| (In Thousands) |
| |
Balance at December 31, 2016 |
| $2,253,317 |
|
Net income | 139,844 |
|
Common equity distributions | (15,000 | ) |
Preferred stock dividends | (1,428 | ) |
Other | 21 |
|
Balance at December 31, 2017 |
| $2,376,754 |
|
Net income | 252,707 |
|
Capital contributions from parent | 350,000 |
|
Common equity distributions | (91,751 | ) |
Non-cash contribution from parent | 94,335 |
|
Preferred stock dividends | (1,249 | ) |
Other | 2,307 |
|
Balance at December 31, 2018 |
| $2,983,103 |
|
Net income | 262,964 |
|
Common equity distributions | (115,000 | ) |
Other | (5,130 | ) |
Balance at December 31, 2019 |
| $3,125,937 |
|
| |
See Notes to Financial Statements. | |
|
|
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | | |
| | | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| | | (In Thousands) |
| | | | | | | | | | | |
| Operating revenues | |
| $2,259,594 |
| |
| $2,060,643 |
| |
| $2,139,919 |
| |
| $2,086,608 |
| |
| $2,253,564 |
|
| Net income | |
| $262,964 |
| |
| $252,707 |
| |
| $139,844 |
| |
| $167,212 |
| |
| $74,272 |
|
| Total assets | |
| $11,205,633 |
| |
| $10,401,596 |
| |
| $10,134,029 |
| |
| $9,606,117 |
| |
| $8,747,774 |
|
| Long-term obligations (a) | |
| $3,517,208 |
| |
| $3,225,759 |
| |
| $2,983,749 |
| |
| $2,746,435 |
| |
| $2,691,189 |
|
| | | | | | | | | | | |
| (a) Includes long-term debt (excluding currently maturing debt) and preferred stock without sinking fund. |
| | | | | | | | | | | |
| | | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| | | (Dollars In Millions) |
| | | | | | | | | | | |
| Electric Operating Revenues: | | |
| | |
| | |
| | |
| | |
|
| Residential | |
| $795 |
| |
| $807 |
| |
| $768 |
| |
| $789 |
| |
| $824 |
|
| Commercial | | 539 |
| | 426 |
| | 495 |
| | 495 |
| | 515 |
|
| Industrial | | 521 |
| | 434 |
| | 472 |
| | 446 |
| | 477 |
|
| Governmental | | 21 |
| | 17 |
| | 19 |
| | 18 |
| | 20 |
|
| Total billed retail | | 1,876 |
| | 1,684 |
| | 1,754 |
| | 1,748 |
| | 1,836 |
|
| Sales for resale: | | |
| | |
| | |
| | |
| | |
|
| Associated companies | | 118 |
| | 104 |
| | 128 |
| | 49 |
| | 128 |
|
| Non-associated companies | | 140 |
| | 145 |
| | 121 |
| | 118 |
| | 195 |
|
| Other | | 126 |
| | 128 |
| | 137 |
| | 172 |
| | 95 |
|
| Total | |
| $2,260 |
| |
| $2,061 |
| |
| $2,140 |
| |
| $2,087 |
| |
| $2,254 |
|
| | | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | | |
| | |
| | |
| | |
|
| Residential | | 7,996 |
| | 8,248 |
| | 7,298 |
| | 7,618 |
| | 8,016 |
|
| Commercial | | 5,822 |
| | 5,967 |
| | 5,825 |
| | 5,988 |
| | 6,020 |
|
| Industrial | | 7,759 |
| | 8,071 |
| | 7,528 |
| | 6,795 |
| | 6,889 |
|
| Governmental | | 241 |
| | 239 |
| | 237 |
| | 237 |
| | 235 |
|
| Total retail | | 21,818 |
| | 22,525 |
| | 20,888 |
| | 20,638 |
| | 21,160 |
|
| Sales for resale: | | |
| | |
| | |
| | |
| | |
|
| Associated companies | | 2,180 |
| | 1,773 |
| | 1,782 |
| | 1,609 |
| | 2,239 |
|
| Non-associated companies | | 7,206 |
| | 6,447 |
| | 6,549 |
| | 7,115 |
| | 7,980 |
|
| Total | | 31,204 |
| | 30,745 |
| | 29,219 |
| | 29,362 |
| | 31,379 |
|
ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
20192022 Compared to 20182021
Net Income
Net income increased $15.9$201.9 million primarily due to the net effects of Entergy Louisiana’s storm cost securitization, including a $290 million reduction in income tax expense, partially offset by a $224.4 million ($165.4 million net-of-tax) regulatory charge to reflect its obligation to share the benefits of the securitization with customers. Also contributing to the net income increase was higher volume/weather and higher retail electric price. The increase wasprice, partially offset by an income tax benefit recognized in 2018 as a result of the settlement of the 2012-2013 IRS audit, higher depreciation and amortization expenses, higher other operation and maintenance expenses, higher depreciation and amortization expenses, lower volume/weather,other income, higher interest expense, and higher interest expense.taxes other than income taxes. See Note 2 to the financial statements for further discussion of the securitization.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 20192022 to 2018:
|
| | | | |
| Amount |
| (In Millions) |
20182021 operating revenues |
| $4,296.3 |
|
| Fuel, rider, and other revenues that do not significantly affect net income | (218.11,013.0 | ) |
| Retail electric price | 132.9111.7 |
|
Return of unprotected excess accumulated deferred income taxes to customersVolume/weather | 102.5108.2 |
|
Volume/weatherStorm restoration carrying costs | (28.437.5 | ) |
20192022 operating revenues |
| $4,285.2 |
|
Entergy Louisiana’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.
The retail electric price variance is primarily due to an increaseincreases in formula rate plan revenues, including increases in the distribution and transmission recovery mechanisms, effective September 20182021 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 as approved by the LPSC.September 2022. See Note 2 to the financial statements for further discussion of the formula rate plan proceedings.
The return of unprotected excess accumulated deferred income taxes to customers resulted from the return of unprotected excess accumulated deferred income taxes through changes in the formula rate plan effective May 2018. In 2019, $38.6 million was returned to customers as compared to $141.1 million in 2018. There was no effect on net income as the reduction in operating revenues was offset by a reduction in income tax expense. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act.
The volume/weather variance is primarily due to a decreasean increase of 6732,934 GWh, or 3%5%, in billed electricity usage for residential and commercial customers,across all customer classes, including the effect of lessmore favorable weather. weather on residential sales. The decreaseincrease in commercial usage was partially offset by anprimarily due to the effect of the COVID-19 pandemic on businesses in 2021. The increase in industrial usage was primarily due to an increase in demand from expansion projects, primarily in the chemicals, petroleum refining, and transportation industries.industries, an increase in demand from cogeneration and small industrial customers, and an increase in demand from existing customers, primarily in the chemicals and pulp and paper industries as a result of prior year temporary plant shutdowns. The increased usage from these industrial customers has a relatively smaller effect on operating revenues because a larger portion of the revenues from those customers comes from fixed charges.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Storm restoration carrying costs represent the equity component of storm restoration carrying costs, recorded in second quarter 2022, recognized as part of the securitization of the Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida restoration costs in May 2022. See Note 2 to the financial statements for a discussion of the securitization.
Total electric energy sales for Entergy Louisiana for the years ended December 31, 2022 and 2021 are as follows:
| | | | | | | | | | | | | | | | | |
| 2022 | | 2021 | | % Change |
| (GWh) | | |
| Residential | 14,119 | | | 13,445 | | | 5 | |
| Commercial | 10,927 | | | 10,388 | | | 5 | |
| Industrial | 31,666 | | | 29,978 | | | 6 | |
| Governmental | 820 | | | 787 | | | 4 | |
| Total retail | 57,532 | | | 54,598 | | | 5 | |
| Sales for resale: | | | | | |
| Associated companies | 5,416 | | | 4,950 | | | 9 | |
| Non-associated companies | 3,423 | | | 2,764 | | | 24 | |
| Total | 66,371 | | | 62,312 | | | 7 | |
See Note 19 to the financial statements for additional discussion of Entergy Louisiana’s operating revenues.
Other Income Statement Variances
Other operation and maintenance expenses increased primarily due to:
a $14.8 million gain in 2018 from the sale of Willow Glen Power Station;
•an increase of $12.7$27.7 million in information technology costspower delivery expenses primarily due to higher vegetation maintenance costs, related to applicationshigher reliability costs, and infrastructure support, enhanced cyber security,higher safety and upgrades and maintenance;training costs, partially offset by a decrease in meter reading expenses as a result of the deployment of advanced metering systems;
•an increase of $12.4$19 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.
The increase was partially offset by:
a decrease of $8.5 million in nuclear generation expenses primarily due to a lowerhigher scope of work performed during plant outages in 20192022 as compared to 2018;2021 and higher nuclear labor costs;
•an increase of $10.3 million in bad debt expense, primarily due to the effectsdeferral in 2021 of recording in 2019bad debt expense resulting from 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.COVID-19 pandemic. See Note 82 to the financial statements for a discussion of regulatory activity associated with the spent nuclear fuel litigation.COVID-19 pandemic;
•an increase of $9.8 million due to a $14.8 million gain on the sale of a pipeline recorded in 2021 as compared to a $5 million contingent gain recorded on the 2021 sale in 2022;
•an increase of $7.5 million in customer service center support costs primarily due to higher contract costs;
•an increase of $6.6 million in non-nuclear generation expenses primarily due to higher costs associated with materials and supplies in 2022 as compared to 2021;
•an increase of $5.1 million in loss provisions;
•an increase of $4.8 million in energy efficiency expenses due to the timing of recovery from customers, partially offset by lower energy efficiency costs; and
•several individually insignificant items.
Taxes other than income taxes increased primarily due to increases in franchise taxes, increases in employment taxes, and increases in ad valorem taxes. Ad valorem taxes increased primarily due toresulting from higher assessments.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including the St. Charles Power Station, which was placed into service in May 2019.service.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Other regulatory charges (credits) include- net includes a regulatory chargescharge of $73.1$224 million, recorded in 2018second quarter 2022, to reflect the effectsEntergy Louisiana’s obligation to provide credits to its customers in recognition of a provisionobligations related to an LPSC ancillary order issued in the settlement reached in the formula rate plan extension proceeding to return the benefits of the lower federal income tax rate in 2018 to customers.Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida securitization regulatory proceeding. See Note 2 to the financial statements for discussion of the formula rate plan extension proceeding.securitization. In addition, Entergy Louisiana records a regulatory charge or credit for the difference between asset retirement obligation-related expenses and nuclear decommissioning trust earnings plus asset retirement obligation related costs collected in revenue.
Other income decreased primarily due to:
•changes in decommissioning trust fund activity, including portfolio rebalancing of the decommissioning trust funds in 2022 and 2021; and
•a $31.6 million charge for the LURC’s 1% beneficial interest in the storm trust established as part of the Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida securitization.
The decrease was partially offset by:
•an increase of $58.2 million in affiliated dividend income resulting from the storm trust’s investment of securitization proceeds in affiliated preferred membership interests, partially offset by the liquidation of Entergy Louisiana’s investment in affiliated preferred membership interests acquired in connection with previous securitizations of storm restoration costs; and
•an increase of $16.8 million due to the recognition of storm restoration carrying costs, primarily related to Hurricane Ida.
See Note 2 to the financial statements for discussion of the securitization.
Interest expense increased primarily due to to:
•the issuances of $500 million of 2.35% Series mortgage bonds and $500 million of 3.10% Series mortgage bonds, each in March 2021;
•the issuance of $525 million$1 billion of 4.20%0.95% Series mortgage bonds in March 2019.October 2021;
•the $1.2 billion unsecured term loan drawn in January 2022. The term loan was repaid in June 2022; and
•the issuance of $500 million of 4.75% Series mortgage bonds in August 2022.
The increase was partially offset by the repayment of $200 million of 4.8% Series mortgage bonds in May 2021.
The effective income tax rates were 15% for 2019 and (8.8%(23.5%) for 2018. The difference in the effective income tax rate of 15% versus the federal statutory rate of 21%2022 and 15.5% for 2019 was primarily due to the amortization of excess accumulated deferred income taxes and book and tax differences related to the non-taxable income distributions earned on preferred membership interests. The difference in the effective income tax rate of (8.8%) versus the federal statutory rate of 21% for 2018 was primarily due to the amortization of excess accumulated deferred income taxes and an IRS audit settlement for the 2012-2013 tax returns.2021. See Note 3 to the financial statements for a reconciliation of the federal statutory ratesrate of 21% to the effective income tax rates.rates, and for additional discussion regarding income taxes.
20182021 Compared to 2017
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy Louisiana’s Annual Report on Form 10-K for the year ended December 31, 20182021, filed with the SEC on February 25, 2022, for discussion of results of operations for 20182021 compared to 2017.2020.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Income Tax Legislation
See the “Income Tax Legislation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the Tax CutsInflation Reduction Act of 2022.
Entergy Louisiana, LLC and Jobs Act, the federal income tax legislation enacted in December 2017. Note 3 to the financial statements contains additional discussion of the effect of the Act on 2017, 2018,Subsidiaries
Management’s Financial Discussion and 2019 results of operations and financial position, the provisions of the Act, and the uncertainties associated with accounting for the Act, and Note 2 to the financial statements discusses the regulatory proceedings that have considered the effects of the Act.Analysis
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2019, 2018,2022, 2021, and 20172020 were as follows:
| | | | | | | | | | | | | | | | | |
| | 2022 | | 2021 | | 2020 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period | $18,573 | | | $728,020 | | | $2,006 | |
| | | | | |
| Net cash provided by (used in): | | | | | |
| Operating activities | 1,177,508 | | | 1,052,526 | | | 1,072,986 | |
| Investing activities | (4,707,711) | | | (3,700,199) | | | (1,944,671) | |
| Financing activities | 3,568,243 | | | 1,938,226 | | | 1,597,699 | |
| Net increase (decrease) in cash and cash equivalents | 38,040 | | | (709,447) | | | 726,014 | |
| | | | | |
| Cash and cash equivalents at end of period | $56,613 | | | $18,573 | | | $728,020 | |
|
| | | | | | | | | | | |
| | 2019 | | 2018 | | 2017 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $43,364 |
| |
| $35,907 |
| |
| $213,850 |
|
| | | | | | |
| Net cash provided by (used in): | | | |
| | |
|
| Operating activities | 1,236,002 |
| | 1,395,204 |
| | 1,337,545 |
|
| Investing activities | (1,653,634 | ) | | (1,878,208 | ) | | (1,787,409 | ) |
| Financing activities | 376,274 |
| | 490,461 |
| | 271,921 |
|
| Net increase (decrease) in cash and cash equivalents | (41,358 | ) | | 7,457 |
| | (177,943 | ) |
| �� | | | | | |
| Cash and cash equivalents at end of period |
| $2,006 |
| |
| $43,364 |
| |
| $35,907 |
|
20192022 Compared to 20182021
Operating Activities
Net cash flow provided by operating activities decreased $159.2increased $125 million in 20192022 primarily due to:
income tax payments•a decrease of $15.3$221.9 million in 2019 comparedstorm spending, primarily due to $105.2Hurricane Ida, Hurricane Laura, Hurricane Delta, and Hurricane Zeta restoration efforts in 2021;
•an increase of $64 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 Arkansas2022 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;an intercompany income tax allocation agreement; and
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•higher collections from customers.
The decreaseincrease was partially offset by a decrease in return of unprotected excess accumulated deferred income taxes to customers and the timing of recovery ofby:
•increased fuel and purchased power costs. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery;
•an increase of $23.5 million in spending on nuclear refueling outages;
•an increase of $15.8 million in interest paid in 2022; and
•payments to vendors, including timing and an increase in cost of operations.
Investing Activities
Net cash flow used in investing activities increased $1,007.5 million in 2022 primarily due to:
•an increase in investments in affiliates due to the effects$3,163.6 million purchase by the storm trust of preferred membership interests issued by an Entergy affiliate, partially offset by the $1,390.6 million redemption of preferred membership interests. See Note 2 to the financial statements for a discussion of the securitization;
•net payments to storm reserve escrow accounts of $293.4 million in 2022;
•an increase of $100.4 million in nuclear construction expenditures primarily due to increased spending on various nuclear projects in 2022 and the regulatory activity regarding the Tax Cuts and Jobs Act.higher capital expenditures for storm restoration in 2022;
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Investing Activities
Net cash flow used in investing activities decreased $224.6•an increase of $13.3 million in 2019 primarily due to a decrease of $320 million in fossil-fueled generationinformation technology capital expenditures primarily due to lowerincreased spending on the St. Charles Power Station and Lake Charles Power Stationvarious technology projects in 20192022; and money pool activity.
•an increase of $12.2 million as a result of fluctuations in nuclear fuel activity, primarily due to variations from year to year in the timing and pricing of fuel reload requirements, materials and services deliveries, and the timing of cash payments during the nuclear fuel cycle.
The decreaseincrease was partially offset by:
an increase•a decrease 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$856.2 million in distribution construction expenditures primarily due to lower capital expenditures for storm restoration in 2022 and lower spending in 2022 on advanced metering infrastructure, partially offset by higher capital expenditures as a result of increased development in Entergy Louisiana’s service area, and increased investment in the reliability and infrastructure of Entergy Louisiana’s distribution system, including increased spending on advanced metering infrastructure; andsystem;
an increase•a decrease of $46.5$328.5 million in transmission construction expenditures primarily due to lower capital expenditures for storm spendingrestoration in 2019.2022;
•a decrease of $25.3 million in nuclear decommissioning trust fund activity as a result of a lump sum contribution in 2021 for amounts collected over a 17-month period. See Note 2 to the financial statements for a discussion of nuclear decommissioning expense recovery; and
•money pool activity.
Decreases in Entergy Louisiana’s receivablereceivables from the money pool are a source of cash flow, and Entergy Louisiana’s receivable from the money pool decreased by $46.8$14.5 million in 20192022 compared to increasing by $35.7$1.1 million in 2018.2021. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Financing Activities
Net cash flow provided by financing activities decreased $114.2increased $1,630 million in 20192022 primarily due to:
•proceeds from securitization of $3.2 billion received by the storm trust in 2022;
•a capital contribution of $1 billion received indirectly from Entergy Corporation in May 2022 to finance the establishment of the storm escrow account for Hurricane Ida costs;
•the issuance of $750$500 million of 4.00%4.75% Series mortgage bonds in March 2018. A portionAugust 2022;
•money pool activity;
•the repayment, at maturity, of the proceeds was used to repay $375$200 million of 6.0%4.80% Series mortgage bonds in May 2018;2021;
•the repayment, at maturity, of Entergy Louisiana Waterford VIE’s $40 million of 3.92% Series H secured notes in February 2021; and
•higher prepaid deposits of $32 million related to contributions-in-aid-of-construction reimbursement agreements in 2022 as compared to 2021.
The increase was partially offset by:
•the issuance of $600$500 million of 4.20%2.35% Series mortgage bonds and $500 million of 3.10% Series mortgage bonds, each in March 2021;
•the issuance of $1 billion of 0.95% 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; andOctober 2021;
•an increase of $80$564 million in common equity distributions in 20192022 primarily to return to Entergy Corporation the $125 million capital contribution received in December 2021 to assist in paying for costs associated with Hurricane Ida and to maintain Entergy Louisiana’s targeted capital structure.structure;
The decrease was partially offset by:
•the issuancerepayment, at maturity, of $525$200 million of 4.20%3.3% Series mortgage bonds in March 2019;December 2022;
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
•net repayments of short-term$75 million in 2022 compared to net borrowings of $43.5$125 million in 20182021 on Entergy Louisiana’s revolving credit facility;
•a capital contribution of $125 million received from Entergy Corporation in December 2021 in order to assist in paying costs associated with Hurricane Ida; and
•net repayments of long-term borrowings of $8.4 million in 2022 compared to net long-term borrowings of $24.1 million in 2021 on the nuclear fuel company variable interest entities’ credit facilities.
Increases in Entergy Louisiana’s payable to the money pool are a source of cash flow, and Entergy Louisiana’s payable to the money pool increased by $82.8$226.1 million in 2019.2022.
See Note 5 to the financial statements for details of long-term debt.
20182021 Compared to 2017
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Louisiana’s Annual Report on Form 10-K for the year ended December 31, 20182021, filed with the SEC on February 25, 2022, for discussion of operating, investing, and financing cash flow activities for 20182021 compared to 2017.2020.
Capital Structure
Entergy Louisiana’s debt to capital ratio is shown in the following table.
The decrease in the debt to capital ratio for Entergy Louisiana LLC and Subsidiariesis primarily due to the $1.0 billion capital contribution received indirectly from Entergy Corporation in May 2022.
Management’s Financial Discussion and Analysis | | | | | | | | | | | |
| | December 31,
2022 | | December 31,
2021 |
| Debt to capital | 53.0 | % | | 57.2 | % |
| | | |
| | | |
| Effect of subtracting cash | (0.1 | %) | | 0.0 | % |
| Net debt to net capital (non-GAAP) | 52.9 | % | | 57.2 | % |
|
| | | | | |
| | December 31,
2019 | | December 31,
2018 |
| Debt to capital | 53.4 | % | | 53.6 | % |
| Effect of excluding securitization bonds | (0.1 | %) | | (0.3 | %) |
| Debt to capital, excluding securitization bonds (a) | 53.3 | % | | 53.3 | % |
| Effect of subtracting cash | (0.1 | %) | | (0.1 | %) |
| Net debt to net capital, excluding securitization bonds (a) | 53.2 | % | | 53.2 | % |
| |
(a) | Calculation excludes the securitization bonds, which are non-recourse to Entergy Louisiana. |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and common equity. Net capital consists of capital less cash and cash equivalents. Entergy Louisiana uses the debt to capital ratios excluding securitization bondsratio in analyzing its financial condition and believes they provideit provides useful information to its investors and creditors in evaluating Entergy Louisiana’s financial condition because the securitization bonds are non-recoursecondition. The net debt to Entergy Louisiana, as more fully described in Note 5 to the financial statements.net capital ratio is a non-GAAP measure. Entergy Louisiana also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Louisiana’s financial condition because net debt indicates Entergy Louisiana’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Louisiana seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a distribution, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Louisiana may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reducing distributions, Entergy Louisiana may receive equity contributions to maintain its capital structure.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Uses of Capital
Entergy Louisiana requires capital resources for:
•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.
Following are the amounts of Entergy Louisiana’s planned construction and other capital investments.
| | | | | | | | | | | | | | | | | |
| | 2023 | | 2024 | | 2025 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation | $405 | | | $435 | | | $1,305 | |
| Transmission | 245 | | | 545 | | | 490 | |
| Distribution | 445 | | | 545 | | | 635 | |
| Utility Support | 175 | | | 110 | | | 120 | |
| Total | $1,270 | | | $1,635 | | | $2,550 | |
|
| | | | | | | | | | | |
| | 2020 | | 2021 | | 2022 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation |
| $580 |
| |
| $485 |
| |
| $320 |
|
| Transmission | 440 |
| | 445 |
| | 230 |
|
| Distribution | 300 |
| | 245 |
| | 190 |
|
| Utility Support | 300 |
| | 385 |
| | 390 |
|
| Total |
| $1,620 |
| |
| $1,560 |
| |
| $1,130 |
|
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Louisiana LLCincludes specific investments in generation projects to modernize, decarbonize, and Subsidiariesdiversify Entergy Louisiana’s portfolio, including the St. Jacques Facility; investments in River Bend and Waterford 3; distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to drive reliability and resilience while also supporting renewables expansion; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, government actions, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.
Management’s Financial Discussion
While Entergy Louisiana is still assessing the effect on its planned solar projects, the investigation by the U.S. Department of Commerce into potential circumvention of duties and Analysistariffs may result in increased duties or tariffs on imported solar panels and has exacerbated previously existing supply chain disruptions, which have negatively affected the timing and cost of completion of these projects.
Following are the amounts of Entergy Louisiana’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations..
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2023 | | 2024 | | 2025 | | 2026-2027 | | After 2027 |
| | (In Millions) |
| Long-term debt (a) | $1,362 | | | $2,029 | | | $655 | | | $1,733 | | | $10,288 | |
| Operating leases (b) | $15 | | | $12 | | | $10 | | | $10 | | | $2 | |
| Finance leases (b) | $5 | | | $4 | | | $4 | | | $5 | | | $2 | |
| | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2021-2022 | | 2023-2024 | | After 2024 | | Total |
| | (In Millions) |
| Long-term debt (a) |
| $640 |
| |
| $1,120 |
| |
| $1,550 |
| |
| $8,662 |
| |
| $11,972 |
|
| Operating leases (b) |
| $11 |
| |
| $17 |
| |
| $8 |
| |
| $3 |
| |
| $39 |
|
| Finance leases (b) |
| $4 |
| |
| $7 |
| |
| $5 |
| |
| $3 |
| |
| $19 |
|
| Purchase obligations (c) |
| $731 |
| |
| $1,423 |
| |
| $1,521 |
| |
| $5,905 |
| |
| $9,580 |
|
| |
(a) | Includes estimated interest payments. (a)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. |
In addition to the contractualfinancial statements.
(b)Lease obligations given above, are discussed in Note 10 to the financial statements.
Other Obligations
Entergy Louisiana currently expects to contribute approximately $38.8$44.6 million to its qualified pension plans and approximately $18.5$15.4 million to its other postretirement health care and life insurance plans in 2020,2023, although the 20202023 required pension contributions will be known with more certainty when the January 1, 20202023 valuations are
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
completed, which is expected by April 1, 2020.2023. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Also, in addition to the contractual obligations, Entergy Louisiana has $808.4$21.9 million of unrecognized tax benefits and interest net of unused tax attributes plus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition, to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Louisiana includes specific investments, such asenters into fuel and purchased power agreements that contain minimum purchase obligations. Entergy Louisiana has rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations. See Note 8 to the Washington Parish Energy Center and Lake Charlesfinancial statements for discussion of Entergy Louisiana’s obligations under the Unit Power Station, each discussed below; transmission projects 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; resource planning, including potential generation projects; system improvements; investments in River Bend and Waterford 3; software and security; and other investments. Entergy’s Utility supply plan initiative will continue to seek to transform its generation portfolio with new or repowered generation resources. Opportunities resulting from the supply plan initiative, including new projects or the exploration of alternative financing sources, could result in increases or decreases in the capital expenditure estimates given above. The estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans,Sales Agreement and the ability to access capital.Vidalia purchased power agreement.
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Louisiana pays distributions from its earnings at a percentage determined monthly.
2021 Solar Certification and the Geaux Green Option
In November 2021, Entergy Louisiana filed an application with the LPSC seeking certification of and approval for the addition of four new solar photovoltaic resources with a combined nameplate capacity of 475 megawatts (the 2021 Solar Portfolio) and the implementation of a new green tariff, the Geaux Green Option (Rider GGO). The 2021 Solar Portfolio consists of four resources that are expected to provide $242 million in net benefits to Entergy Louisiana’s customers. These resources, all of which would be constructed in Louisiana, include (i) the Vacherie Facility, a 150 megawatt resource in St. James Parish; (ii) the Sunlight Road Facility, a 50 megawatt resource in Washington Parish; (iii) the St. Jacques Facility, a 150 megawatt resource in St. James Parish; and (iv) the Elizabeth Facility, a 125 megawatt resource in Allen Parish. The St. Jacques Facility would be acquired through a build-own-transfer agreement; the remaining resources involve power purchase agreements. The Sunlight Road Facility and the Elizabeth Facility have estimated in service dates in 2024, and the Vacherie Facility and the St. Jacques Facility have estimated in service dates in 2025. The filing proposed to recover the costs of the power purchase agreements through the fuel adjustment clause and the formula rate plan and the acquisition costs through the formula rate plan.
The proposed Rider GGO is a voluntary rate schedule that will enhance Entergy Louisiana’s ability to help customers meet their sustainability goals by allowing customers to align some or all of their electricity requirements with renewable energy from the resources. Because subscription fees from Rider GGO participants would help to offset the cost of the resources, the design of Rider GGO also preserves the benefits of the 2021 Solar Portfolio for non-participants by providing them with the reliability and capacity benefits of locally-sited solar generation at a discounted price.
In March 2022 direct testimony from Walmart, the Louisiana Energy Users Group (LEUG), and the LPSC staff was filed. Each party recommended that the LPSC approve the resources proposed in Entergy Louisiana’s application, and the LPSC staff witness indicated that the process through which Entergy Louisiana solicited or obtained the proposals for the resources complied with applicable LPSC orders. The LPSC staff and LEUG’s witnesses made recommendations to modify the proposed Rider GGO and Entergy Louisiana’s proposed rate relief. In April 2022 the LPSC staff and LEUG filed cross-answering testimony concerning each other’s proposed modifications to Rider GGO and the proposed rate recovery. Entergy Louisiana filed rebuttal testimony in June 2022. In August 2022 the parties reached a settlement certifying the 2021 Solar Portfolio and approving implementation of Rider GGO. In September 2022 the LPSC approved the settlement. Following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities until the later
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Lake Charles Power Station
System Resilience and Storm Hardening
In November 2016,December 2022, Entergy Louisiana filed an application with the LPSC seeking certification that the public convenience and necessity would be served by the construction of the Lake Charles Power Station, a nominal 994 megawatt combined-cycle generating unit in Westlake, Louisiana, on land adjacent to the existing Nelson plant in Calcasieu Parish. The current estimated cost of the Lake Charles Power Station is $872 million, including estimated costs of transmission interconnection and other related costs. In May 2017 the parties to the proceeding agreed to an uncontested stipulation finding that construction of the Lake Charles Power Station is in the public interest finding regarding Phase I of Entergy Louisiana’s Future Ready resilience plan and authorizing an in-service rate recovery plan. In July 2017 the LPSC issued an order unanimously approving the stipulation and approved certification of the unit. Construction is in progress and commercial operation is expected to occur by mid-2020.
Washington Parish Energy Center
In April 2017, Entergy Louisiana signed an agreement with a subsidiary of Calpine Corporation for the construction and purchaseapproval of a peaking plant. Calpine will constructrider mechanism to recover the plant, which will consistprogram’s costs. Phase I reflects the first five years of two natural gas-fired combustion turbine units with a total nominal capacity of approximately 361 MW. The plant, named the Washington Parish Energy Center, will be located in Bogalusa, Louisiana. Subject to regulatory approvals, Entergy Louisiana will purchase the plant once it is complete for an estimated totalten-year resilience plan and includes investment of approximately $261 million,$5 billion, including hardening investment, transmission dead-end structures, enhanced vegetation management, and other related costs. In May 2017, Entergy Louisiana filed an application with the LPSC seeking certification of the plant. In April 2018 the parties reached a settlement recommending certification and cost recovery through the additional capacity mechanism of the formula rate plan, consistent with prior LPSC precedent with respect to the certification and recovery of plants previously acquired by Entergy Louisiana. The LPSC issued an order approving the settlementtelecommunications improvement. A procedural schedule has not yet been adopted in May 2018. Construction is in progress and commercial operation is expected to occur by the end of 2020.this docket.
Sources of Capital
Entergy Louisiana’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•the Entergy System money pool;
•storm reserve escrow accounts;
•debt or preferred membership interest issuances;issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations, Entergy Louisiana may refinance, redeem, or otherwiseexpects to continue, when economically feasible, to retire higher-cost debt prior to maturity, to the extentand replace it with lower-cost debt if market conditions and interest rates are favorable.permit.
All debt and common and preferred membership interest issuances by Entergy Louisiana require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in its bond indentures and other agreements. Entergy Louisiana has sufficient capacity under these tests to meet its foreseeable capital needs.needs for the next twelve months and beyond.
Entergy Louisiana’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
| | | | | | | | | | | | | | | | | | | | |
| 2022 | | 2021 | | 2020 | | 2019 |
| (In Thousands) |
| ($226,114) | | $14,539 | | $13,426 | | ($82,826) |
|
| | | | | | |
| 2019 | | 2018 | | 2017 | | 2016 |
| (In Thousands) |
| ($82,826) | | $46,843 | | $11,173 | | $22,503 |
See Note 4 to the financial statements for a description of the money pool.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Louisiana has a credit facility in the amount of $350 million scheduled to expire in September 2024.June 2027. The credit facility includes fronting commitments for the issuance of letters of credit against $15 million of the borrowing capacity of the facility. As of December 31, 2019,2022, there were no$50 million of cash borrowings and no letters of credit outstanding under the credit facility. In addition, Entergy Louisiana is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2019, a $12.32022, $20 million letterin letters of credit waswere outstanding under Entergy Louisiana’s uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
The Entergy Louisiana nuclear fuel company variable interest entities have two separate credit facilities, each in the amount of $105 million and scheduled to expire in September 2021.June 2025. As of December 31, 2019, $70.32022, $13.1 million of loans were outstanding under the credit facility for the Entergy Louisiana River Bend nuclear fuel company variable interest entity. As of December 31, 2019, $49.92022, $60.8 million in loans were outstanding under the Entergy Louisiana Waterford nuclear fuel company variable interest entity credit facility. See Note 4 to the financial statements for additional discussion of the nuclear fuel company variable interest entity credit facilities.
Entergy Louisiana had $293.4 million in its storm reserve escrow account at December 31, 2022.
Entergy Louisiana obtained authorizations from the FERC through November 2020October 2023 for the following:
•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.
See Note 4 to the financial statements for further discussion of Entergy Louisiana’s short-term borrowing limits.
Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida
Hurricane Isaac
In June 2014August 2020 and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of Entergy Louisiana’s service area. The storms resulted in widespread outages, significant damage to distribution and transmission infrastructure, and the loss of sales during the outages. Additionally, as a result of Hurricane Laura’s extensive damage to the grid infrastructure serving the impacted area, large portions of the underlying transmission system required nearly a complete rebuild.
In October 2020, Entergy Louisiana filed an application at the LPSC votedseeking approval of certain ratemaking adjustments in connection with the issuance of shorter-term mortgage bonds to approve a series of orders which (i) quantified $290.8 million of Hurricane Isaac systemprovide interim financing for restoration costs as prudently incurred; (ii) determined $290 million asassociated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta. Subsequently, Entergy Louisiana and the levelLPSC staff filed a joint motion seeking approval to exclude from the derivation of storm reservesEntergy Louisiana’s capital structure and cost rate of debt for ratemaking purposes, including the allowance for funds used during construction, shorter-term debt up to be re-established; (iii) authorized$1.1 billion issued by Entergy Louisiana to utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs; and (iv) granted other requested relieffund costs associated with storm reservesHurricane Laura, Hurricane Delta, and Act 55 financing of Hurricane Isaac system restoration costs.Zeta costs on an interim basis. In November 2020 the LPSC issued an order approving the joint motion, and Entergy Louisiana committedissued $1.1 billion of 0.62% Series mortgage bonds due November 2023. Also in November 2020, Entergy Louisiana withdrew $257 million from its funded storm reserves.
In February 2021 two winter storms (collectively, Winter Storm Uri) brought freezing rain and ice to pass onLouisiana. Ice accumulation sagged or downed trees, limbs, and power lines, causing damage to customers a minimumEntergy Louisiana’s transmission and distribution systems. The additional weight of $30.8 millionice caused trees and limbs to fall into power lines and other electric equipment. When the ice melted, it affected vegetation and electrical equipment, causing additional outages. As discussed in the “Fuel and purchased power recovery” section 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 and the Louisiana State Bond Commission. See Note 2 to the financial statements, forEntergy Louisiana recovered the incremental fuel costs associated with Winter Storm Uri over a discussion of thefive-month period from April 2021 through August 2014 issuance of bonds under Act 55 of the Louisiana Legislature.2021.
Little Gypsy Repowering Project
In April 2007,2021, Entergy Louisiana announced that it intended to pursue the solid fuel repowering of a 538 MW unit at its Little Gypsy plant. In March 2009filed an application with the LPSC votedrelating to Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri restoration costs and in favor of a motion directing Entergy Louisiana to temporarily suspend the repowering project and, based upon an analysis of the project’s economic viability, to make a recommendation regarding whether to proceed with the project. This action was based upon a number of factors including the recent decline in natural gas prices, as well as environmental concerns, the unknown costs of carbon legislation and changes in the capital/financial markets. In April 2009, Entergy Louisiana complied with the LPSC’s directive and recommended that the project be suspended for an extended period of time of three years or more. In May 2009 the LPSC issued an order declaring that Entergy Louisiana’s decision to place the Little Gypsy project into a longer-term suspension of three years or more is in the public interest and prudent.
In October 2009,July 2021, Entergy Louisiana made a supplemental filing withupdating the total restoration costs. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by these storms were estimated to be approximately $2.06 billion, including approximately $1.68 billion in capital costs and approximately $380 million in non-capital costs. Including carrying costs through January 2022, Entergy Louisiana sought an LPSC determination that $2.11 billion was prudently incurred and, therefore, was eligible for recovery from customers. Additionally, Entergy Louisiana requested that the LPSC seeking permissiondetermine that re-establishment of a storm escrow account to cancel the Little Gypsy repowering project and seeking project cost recovery over a five-year period. In June 2010 and August 2010, the LPSC staff and intervenors filed testimony. The LPSC staff (1) agreed that it was prudent to move the project from long-term suspension to cancellation and that the timing of the decision to suspend on a longer-term basis was not imprudent; (2) indicated that, except for $0.8 million in compensation-related costs, the costs incurred should be deemed prudent;
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
(3) recommended recovery
In August 2021, Hurricane Ida caused extensive damage to Entergy Louisiana’s distribution and, to a lesser extent, transmission systems resulting in widespread power outages. In September 2021, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments in connection with the issuance of approximately $1 billion of shorter-term mortgage bonds to provide interim financing for restoration costs associated with Hurricane Ida, which bonds were issued in October 2021. Also in September 2021, Entergy Louisiana sought approval for the creation and funding of a $1 billion restricted escrow account for Hurricane Ida related restoration costs, subject to a subsequent prudence review.
After filing of testimony by the LPSC staff and intervenors, which generally supported or did not oppose Entergy Louisiana’s requests in regard to Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida, the parties negotiated and executed an uncontested stipulated settlement which was filed with the LPSC in February 2022. The settlement agreement contained the following key terms: $2.1 billion of restoration costs from Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri were prudently incurred and were eligible for recovery; carrying costs of $51 million were recoverable; a $290 million cash storm reserve should be re-established; a $1 billion reserve should be established to partially pay for Hurricane Ida restoration costs; and Entergy Louisiana was authorized to finance $3.186 billion utilizing the securitization process authorized by Act 55, as supplemented by Act 293. The LPSC issued an order approving the settlement in March 2022. As a result of the financing order, Entergy Louisiana reclassified $1.942 billion from utility plant to other regulatory assets.
In May 2022 the securitization financing closed, resulting in the issuance of $3.194 billion principal amount of bonds by Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA), a political subdivision of the State of Louisiana. The securitization was authorized pursuant to the Louisiana Utilities Restoration Corporation Act, Part VIII of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana legislature approved in 2021. The LCDA loaned the proceeds to the LURC. Pursuant to Act 293, the LURC contributed the net bond proceeds to a State legislatively authorized and LURC-sponsored trust, Restoration Law Trust I (the storm trust).
Pursuant to Act 293, the net proceeds of the bonds were used by the storm trust to purchase 31,635,718.7221 Class A preferred, non-voting membership interest units (the preferred membership interests) issued by Entergy Finance Company, LLC, a majority-owned indirect subsidiary of Entergy. Entergy Finance Company is required to make annual distributions (dividends) commencing on December 15, 2022 on the preferred membership interests issued to the storm trust. These annual dividends received by the storm trust will be distributed to Entergy Louisiana and the LURC, as beneficiaries of the storm trust. Specifically, 1% of the annual dividends received by the storm trust will be distributed to the LURC, for the benefit of customers, over ten years butand 99% will be distributed to Entergy Louisiana, net of storm trust expenses. The preferred membership interests have a stated annual cumulative cash dividend rate of 7% and a liquidation price of $100 per unit. The terms of the preferred membership interests include certain financial covenants to which Entergy Finance Company is subject.
Entergy and Entergy Louisiana do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA. The bonds are secured by system restoration property, which is the right granted by law to the LURC to collect a system restoration charge from customers. The system restoration charge is adjusted at least semi-annually to ensure that it is sufficient to service the bonds. Entergy Louisiana collects the system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee. Entergy Louisiana began collecting the system restoration charge effective with the first billing cycle of June 2022 and the system restoration charge is expected to remain in place up to 15 years. Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as a billing and collection agent for the LCDA and the LURC. In the remote possibility that the LPSC may want to consider 15 years; (4) allowed for recoverysystem restoration charge, as well as any funds in the
Entergy Louisiana, should be directed to securitize project costs, if legally feasibleLLC and Subsidiaries
Management’s Financial Discussion and Analysis
excess subaccount and funds in the public interest. Indebt service reserve account, are insufficient to service the third quarter 2010, in accordance with accounting standards, Entergy Louisiana determined that it was probable that the Little Gypsy repowering project would be abandoned and accordingly reclassified $199.8 million of project costs from construction work in progress to a regulatory asset. A hearing on the issues, except for cost allocation among customer classes, was held before the ALJ in November 2010. In January 2011 all parties participated in a mediation on the disputed issues,bonds resulting in a settlementpayment default, the storm trust is required to liquidate Entergy Finance Company preferred membership interests in an amount equal to what would be required to cure the default. The estimated value of all disputed issues, including cost recoverythis indirect guarantee is immaterial.
From the proceeds from the issuance of the preferred membership interests, Entergy Finance Company distributed $1.4 billion to its parent, Entergy Holdings Company, LLC, a company wholly-owned and cost allocation. The settlement provides forconsolidated by Entergy. Subsequently, Entergy Holdings Company liquidated, distributing the $1.4 billion it received from Entergy Finance Company to Entergy Louisiana to recover $200 million as holder of March 31, 2011,6,843,780.24 units of Class A, 4,126,940.15 units of Class B, and carrying costs on that amount on specified terms thereafter. The settlement also provides for2,935,152.69 units of Class C preferred membership interests. Entergy Louisiana had acquired these preferred membership interests with proceeds from previous securitizations of storm restoration costs. Entergy Finance Company loaned the remaining $1.7 billion from the preferred membership interests proceeds to recoverEntergy which used the approved project costscash to redeem $650 million of 4.00% Series senior notes due July 2022 and indirectly contributed $1 billion to Entergy Louisiana as a capital contribution.
Entergy Louisiana used the $1 billion capital contribution to fund its Hurricane Ida escrow account and subsequently withdrew the $1 billion from the escrow account. With a portion of the $1 billion withdrawn from the escrow account and the $1.4 billion from the Entergy Holdings Company liquidation, Entergy Louisiana deposited $290 million in a restricted escrow account as a storm damage reserve for future storms, used $1.2 billion to repay its unsecured term loan due June 2023, and used $435 million to redeem a portion of its 0.62% Series mortgage bonds due November 2023.
As discussed in Note 3 to the financial statements, the securitization resulted in recognition of a reduction of income tax expense of approximately $290 million by securitization. Entergy Louisiana. Entergy’s recognition of reduced income tax expense was partially offset by other tax charges resulting in a net reduction of income tax expense of $283 million. In recognition of obligations related to an LPSC ancillary order issued as part of the securitization regulatory proceeding, Entergy Louisiana recorded a $224 million ($165 million net-of-tax) regulatory charge and a corresponding regulatory liability to reflect its obligation to share the benefits of the securitization with customers.
As discussed in Note 17 to the financial statements, Entergy Louisiana consolidates the storm trust as a variable interest entity and the LURC’s 1% beneficial interest is shown as noncontrolling interest in the financial statements. In second quarter 2022, Entergy Louisiana recorded a charge of $31.6 million in other income to reflect the LURC’s beneficial interest in the trust.
In April 2011,2022, Entergy Louisiana filed an application with the LPSC relating to authorizeHurricane Ida restoration costs. Total restoration costs for the securitizationrepair and/or replacement of the investmentEntergy Louisiana’s electric facilities damaged by Hurricane Ida currently are estimated to be approximately $2.54 billion, including approximately $1.96 billion in capital costs and approximately $586 million in non-capital costs. Including carrying costs of $57 million through December 2022, Entergy Louisiana is seeking an LPSC determination that $2.60 billion was prudently incurred and, therefore, is eligible for recovery from customers. As part of this filing, Entergy Louisiana also is seeking an LPSC determination that an additional $32 million in costs associated with the projectrestoration of Entergy Louisiana’s electric facilities damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta as well as Winter Storm Uri was prudently incurred. This amount is exclusive of the requested $3 million in carrying costs through December 2022. In total, Entergy Louisiana is requesting an LPSC determination that $2.64 billion was prudently incurred and, therefore, is eligible for recovery from customers. As discussed above, in March 2022 the LPSC approved financing of a $1 billion storm escrow account from which funds were withdrawn to finance costs associated with Hurricane Ida restoration. In June 2022, Entergy Louisiana supplemented the application with a request regarding the financing and recovery of the recoverable storm restoration costs. Specifically, Entergy Louisiana requested approval to securitize its restoration costs pursuant to Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021. In October 2022 the LPSC staff recommended a finding that the requested storm restoration costs of $2.64 billion, including associated carrying costs of $59.1 million, were prudently incurred and are eligible for recovery from customers. The LPSC staff further recommended approval of
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Louisiana’s plans to securitize these costs, net of the $1 billion in funds withdrawn from the storm escrow account described above. The parties negotiated and executed an uncontested stipulated settlement which was filed with the LPSC in December 2022. The settlement agreement contains the following key terms: $2.57 billion of restoration costs from Hurricane Ida, Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri were prudently incurred and were eligible for recovery; carrying costs of $59.2 million were recoverable; and Entergy Louisiana was authorized to finance $1.657 billion utilizing the securitization process authorized by Act 55, as supplemented by Act 293. A procedural motion to consider the uncontested settlement at the December 2022 LPSC meeting did not pass and the settlement was not voted on. In January 2023 an ALJ with the LPSC conducted a settlement hearing to receive the uncontested settlement and supporting testimony into evidence and issued a report of proceedings, which allows the LPSC to consider the uncontested settlement without the procedural motion that did not pass in December. In January 2023, the LPSC staff approved the stipulated settlement subject to certain modifications. These modifications include the recognition of accumulated deferred income tax benefits related to damaged assets and system restoration costs as a reduction of the amount authorized to be financed utilizing the securitization process authorized by Act 55, as supplemented by Act 293, from $1.657 billion to $1.491 billion. These modifications do not affect the staff’s conclusion that all system restoration costs sought by Entergy Louisiana were reasonable and prudent. The LPSC order is not yet final and non-appealable due to the forty-five day appeal period. In February 2023 the Louisiana Bond Commission voted to authorize the LCDA to issue athe bonds authorized in the LPSC’s financing order by which Entergy Louisiana could accomplish such securitization. In August 2011order; the LPSC issued an order approving the settlementbond rating and also issued a financing order for the securitization. See Note 5marketing process has yet to the financial statements for a discussion of the September 2011 issuance of the securitization bonds.
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy Louisiana charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Louisiana is regulated, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the LPSC, is primarily responsible for approval of the rates charged to customers.
Retail Rates - Electric
FilingsRetail Rates - Gas
In accordance with the settlement of Entergy Gulf States Louisiana’s gas rate stabilization plan for the test year ended September 30, 2012, in August 2014, Entergy Gulf States Louisiana submitted for consideration a proposal for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment and relocation projects mandated by local governments. After review by the LPSC staff and inclusion of certain customer safeguards required by the LPSC staff, in December 2014, Entergy Gulf States Louisiana and the LPSC staff submitted a joint settlement for implementation of an accelerated gas pipe replacement program providing for the replacement of approximately 100 miles of pipe over the next ten years, as well as relocation of certain existing pipe resulting from local government-related infrastructure projects, and for a rider to recover the investment associated with these projects. The rider allows for recovery of approximately $65 million over ten years. The rider recovery will be adjusted on a quarterly basis to include actual investment incurred for the prior quarter and is subject to the following conditions, among others: a ten-year term; application of any earnings in excess of the upper end of the earnings band as an offset to the revenue requirement of the infrastructure rider; adherence to a specified spending plan, within plus or minus 20% annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding 10%; and an annual true-up. The joint settlement was approved by the LPSC in January 2015. Implementation of the infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2015. In April 2022 Entergy Louisiana submitted for consideration a proposal to extend the infrastructure rider to address replacement of an additional 187 miles of pipe. In December 2022 Entergy Louisiana and the LPSC staff submitted an uncontested settlement that extends the rider for an additional ten years beginning after the end of the current term of the rider in 2025. The extension is subject to the same customer safeguards and conditions as the original term of the rider. The extension allows for recovery of approximately $95 million over ten years. In February 2023, the uncontested settlement was approved by the LPSC.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Louisiana’s filings to recover storm-related costs.
Other
In March 2016 the LPSC opened two dockets to examine, on a generic basis, issues that it identified in connection with its review of Cleco Corporation’s acquisition by third party investors. The first docket is captioned “In re: Investigation of double leveraging issues for all LPSC-jurisdictional utilities,” and the second is captioned “In re: Investigation of tax structure issues for all LPSC-jurisdictional utilities.” In April 2016 the LPSC clarified that the concerns giving rise to the two dockets arose as a result of its review of the structure of the Cleco-Macquarie transaction and that the specific intent of the directives is to seek more information regarding intra-corporate debt financing of a utility’s capital structure as well as the use of investment tax credits to mitigate the tax
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obligation at the parent level of a consolidated entity. No schedule has been set for either docket, and limited discovery has occurred.
In December 2019 an LPSC commissioner issued an unopposed directive to staff to research customer-centered options for all customer classes, as well as other regulatory environments, and recommend a plan for how to ensure customers are the focus. There was no opposition to the directive from other commissioners but several remarked that the intent of the directive was not initiated to pursue retail open access. In furtherance of the directive, the LPSC issued a notice of the opening of a docket to conduct a rulemaking to research and evaluate customer-centered options for all electric customer classes as well as other regulatory environments in January 2020. To date, the LPSC staff has requested multiple rounds of comments from stakeholders and conducted one technical conference. Topics on which comments have been filed include full and limited retail access, demand response, sleeved power purchase agreements, and energy efficiency. Neither the LPSC or the LPSC staff have made recommendations or adopted any rules.
Entergy Mississippi
Formula Rate Plan
Since the conclusion in 2015 of Entergy Mississippi’s most recent base rate case, Entergy Mississippi has set electric base rates annually through a formula rate plan. Between base rate cases, Entergy Mississippi is able to adjust base rates annually, subject to certain caps, through formula rate plans that utilize forward-looking features. In addition, Entergy Mississippi is subject to an annual “look-back” evaluation. Entergy Mississippi is allowed a maximum rate increase of 4% of each test year’s retail revenue. Any increase above 4% requires a base rate case. If Entergy Mississippi’s formula rate plan were terminated without replacement, it would revert to the more traditional rate case environment or seek approval of a new formula rate plan.
In August 2012 the MPSC opened inquiries to review whether the then current formulaic methodology used to calculate the return on common equity in both Entergy Mississippi’s formula rate plan and Mississippi Power Company’s annual formula rate plan was still appropriate or could be improved to better serve the public interest. The intent of this inquiry and review was for informational purposes only; the evaluation of any recommendations for changes to the existing methodology would take place in a general rate case or in the existing formula rate plan proceeding. In March 2013 the Mississippi Public Utilities Staff filed its consultant’s report which noted the return on common equity estimation methods used by Entergy Mississippi and Mississippi Power Company are commonly used throughout the electric utility industry. The report suggested ways in which the methods used by Entergy Mississippi and Mississippi Power Company might be improved, but did not recommend specific changes in the return on common equity formulas or calculations at that time. In June 2014 the MPSC expanded the scope of the August 2012 inquiry to study the merits of adopting a uniform formula rate plan that could be applied, where possible in whole or in part, to both Entergy Mississippi and Mississippi Power Company in order to achieve greater consistency in the plans. The MPSC directed the Mississippi Public Utilities Staff to investigate and review Entergy Mississippi’s formula rate plan rider schedule and Mississippi Power Company’s Performance Evaluation Plan by considering the merits and deficiencies and possibilities for improvement of each and then to propose a uniform formula rate plan that, where possible, could be applicable to both companies. No procedural schedule has been set. In October 2014 the Mississippi Public Utilities Staff conducted a public technical conference to discuss performance benchmarking and its potential application to the electric utilities’ formula rate plans. The docket remains open.
In December 2019 the MPSC approved Entergy Mississippi’s proposed revisions to its formula rate plan to 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 as well as to allow similar cost recovery treatment for other capacity acquisitions that are approved by the MPSC. 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
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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.
Fuel Recovery
Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased power costs. The energy cost rate for each calendar year is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy costs as of the 12-month period ended September 30. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC. The energy cost recovery riders allow interim rate adjustments depending on the level of over- or under-recovery of fuel and purchased energy costs.
To help stabilize electricity costs, Entergy Mississippi received approval from the MPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Mississippi hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of recovery of Entergy Mississippi’s storm-related costs.
Entergy New Orleans
Formula Rate Plan
As part of its determination of rates in the base rate case filed by Entergy New Orleans in 2018, in November 2019, the City Council issued a resolution resolving the rate case, with rates to become effective retroactive to August 2019. The resolution allows Entergy New Orleans to implement a three-year formula rate plan, beginning with the 2019 test year as adjusted for forward-looking known and measurable changes, with the filing for the first test year to be made in 2020. As part of a settlement of Entergy New Orleans’ appeal of the Council’s decision in its 2018 base rate case, Entergy New Orleans agreed to postpone the filing of its first test year formula rate plan to 2021 and, in return, to be provided an additional test year for the three-year cycle. Accordingly, Entergy New Orleans will submit its final formula rate plan filing of the three-year cycle in April 2023 unless the formula rate plan is extended or renewed. See Note 2 to the financial statements for further discussion.
Fuel Recovery
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.
To help stabilize gas costs, Entergy New Orleans seeks approval annually from the City Council to continue implementation of its natural gas hedging program consistent with the City Council’s stated policy objectives. The program uses financial instruments to hedge exposure to volatility in the wholesale price of natural gas purchased to
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serve Entergy New Orleans gas customers. Entergy New Orleans hedges up to 25% of actual gas sales made during the winter months.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy New Orleans’s filings to recover storm-related costs.
Entergy Texas
Base Rates
The base rates of Entergy Texas are established largely in traditional base rate case proceedings. Between base rate proceedings, Entergy Texas has available rate riders to recover the revenue requirements associated with certain incremental costs. Entergy Texas is required to file full base rate case proceedings every four years and within eighteen months of utilizing its generation cost recovery rider for investments above $200 million.
Fuel Recovery
Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, that are not included 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 every three years, at a minimum. In the course of this reconciliation, the PUCT determines whether eligible fuel and fuel-related expenses and revenues are necessary and reasonable and makes a prudence finding for each of the fuel-related contracts entered into during the reconciliation period. The PUCT fuel cost proceedings are discussed in Note 2 to the financial statements.
At the PUCT’s April 2013 open meeting, the PUCT Commissioners discussed their view that a purchased power capacity rider was good public policy. The PUCT issued an order in May 2013 adopting the rule allowing for a purchased power capacity rider, subject to an offsetting adjustment for load growth. The rule, as adopted, also includes a process for obtaining pre-approval by the PUCT of purchased power agreements. No Texas utility, including Entergy Texas, has exercised the option to recover capacity costs under the new rider mechanism, but Entergy Texas will continue to evaluate the benefits of utilizing the rider to recover future capacity costs.
Other Cost Recovery
As discussed above, Entergy Texas has available rate riders to recover the revenue requirements associated with certain incremental costs. These riders include a transmission cost recovery factor rider mechanism for the recovery of transmission-related capital investments, a distribution cost recovery factor rider mechanism for the recovery of distribution-related capital investment, and a generation cost recovery rider mechanism for the recovery of generation-related capital investments.
In June 2009 a law was enacted in Texas containing provisions that allow Entergy Texas to take advantage of a cost recovery mechanism that permits annual filings for the recovery of reasonable and necessary expenditures for transmission infrastructure improvement and changes in wholesale transmission charges. This mechanism was previously available to other non-ERCOT Texas utility companies, but not to Entergy Texas.
In September 2011 the PUCT adopted a proposed rule implementing a distribution cost recovery factor to recover capital and capital-related costs related to distribution infrastructure. The distribution cost recovery factor permits utilities once per year to implement an increase or decrease in rates above or below amounts reflected in base rates to reflect distribution-related depreciation expense, federal income tax and other taxes, and return on
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investment. The distribution cost recovery factor rider may be changed a maximum of four times between base rate cases.
In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery rider rule, implementing legislation passed in the 2019 Texas legislative session intended to allow electric utilities to recover generation investments between base rate proceedings. The PUCT approved the final rule in July 2020.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Texas’s filings to recover storm-related costs.
Electric Industry Restructuring
In June 2009 a law was enacted in Texas that required Entergy Texas to cease all activities relating to Entergy Texas’s transition to competition. The law allows Entergy Texas to remain a part of the SERC Reliability Corporation (SERC) Region, although it does not prevent Entergy Texas from joining another power region. The law provides that proceedings to certify a power region that Entergy Texas belongs to as a qualified power region can be initiated by the PUCT, or on motion by another party, when the conditions supporting such a proceeding exist. Under the law, the PUCT may not approve a transition to competition plan for Entergy Texas until the expiration of four years from the PUCT’s certification of a qualified power region for Entergy Texas.
The law further amended already existing law that had required Entergy Texas to propose for PUCT approval a tariff to allow eligible customers the ability to contract for competitive generation. The amending language in the law provides, among other things, that: 1) the tariff shall not be implemented in a manner that harms the sustainability or competitiveness of manufacturers who choose not to participate in the tariff; 2) Entergy Texas shall “purchase competitive generation service, selected by the customer, and provide the generation at retail to the customer;” and 3) Entergy Texas shall provide and price transmission service and ancillary services under that tariff at a rate that is unbundled from its cost of service. The law directs that the PUCT may not issue an order on the tariff that is contrary to an applicable decision, rule, or policy statement of a federal regulatory agency having jurisdiction. The PUCT determined that unrecovered costs that may be recovered through the rider consist only of those costs necessary to implement and administer the competitive generation program and do not include lost revenues or embedded generation costs. The amount of customer load that may be included in the competitive generation service program is limited to 115 MW.
System Energy
Cost of Service
The rates of System Energy are established by the FERC, and the costs allowed to be charged pursuant to these rates are, in turn, passed through to the participating Utility operating companies through the Unit Power Sales Agreement, which has monthly billings that reflect the current operating costs of, and investment in, Grand Gulf. Retail regulators and other parties may seek to initiate proceedings at FERC to investigate the prudence of costs included in the rates charged under the Unit Power Sales Agreement and examine, among other things, the reasonableness or prudence of the operation and maintenance practices, level of expenditures, allowed rates of return and rate base, and previously incurred capital expenditures. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC, including a challenge with respect to System Energy’s uncertain tax positions, sale leaseback arrangement, authorized return on equity and capital structure, and a separate proceeding for a broader investigation of rates under the Unit Power Sales Agreement. In addition, certain of the Utility operating companies’ retail regulators have filed a complaint at FERC challenging the 2012 extended power uprate of Grand Gulf and the operation and management of the plant, particularly during the time period 2016 - 2020. Beginning in 2021, System Energy implemented billing protocols to provide retail regulators with
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information regarding rates billed under the Unit Power Sales Agreement. Entergy cannot predict the outcome of any of these proceedings, and an adverse outcome in any of them could have a material adverse effect on Entergy’s or System Energy’s results of operations, financial condition, or liquidity. See Note 2 to the financial statements for further discussion of the proceedings.
Franchises
Entergy Arkansas holds exclusive franchises to provide electric service in approximately 308 incorporated cities and towns in Arkansas. These franchises generally are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas, franchises are considered to be contracts and, therefore, are governed pursuant to the terms of the franchise agreement and applicable statutes.
Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 175 incorporated municipalities and in the unincorporated areas of approximately 59 parishes of Louisiana. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and in East Baton Rouge Parish. Municipal franchise agreement terms range from 25 to 60 years while parish franchise terms range from 25 to 99 years.
Entergy Mississippi has received from the MPSC certificates of public convenience and necessity to provide electric service to areas within 45 counties, including a number of municipalities, in western Mississippi. Under Mississippi statutory law, such certificates are exclusive. Entergy Mississippi may continue to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence.
Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city ordinances. These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans’s electric and gas utility properties.
Entergy Texas holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 27 counties in eastern Texas and holds non-exclusive franchises to provide electric service in approximately 70 incorporated municipalities. Entergy Texas typically obtains 25-year franchise agreements as existing agreements expire. Entergy Texas’s electric franchises expire over the period 2023-2058.
The business of System Energy is limited to wholesale power sales. It has no distribution franchises.
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Property and Other Generation Resources
Owned Generating Stations
The total capability of the generating stations owned and leased by the Utility operating companies and System Energy as of December 31, 2022 is indicated below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Owned and Leased Capability MW(a) |
| Company | | Total | | CT / CCGT (b) | | Legacy Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
| Entergy Arkansas | | 5,276 | | | 1,567 | | | 522 | | | 1,822 | | | 1,192 | | | 73 | | | 100 | |
| Entergy Louisiana | | 10,829 | | | 5,595 | | | 2,766 | | | 2,129 | | | 339 | | | — | | | — | |
| Entergy Mississippi | | 2,857 | | | 1,738 | | | 707 | | | — | | | 310 | | | — | | | 102 | |
| Entergy New Orleans | | 663 | | | 636 | | | — | | | — | | | — | | | — | | | 27 | |
| Entergy Texas | | 3,190 | | | 980 | | | 1,960 | | | — | | | 250 | | | — | | | — | |
| System Energy | | 1,260 | | | — | | | — | | | 1,260 | | | — | | | — | | | — | |
| Total | | 24,075 | | | 10,516 | | | 5,955 | | | 5,211 | | | 2,091 | | | 73 | | | 229 | |
(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.
(b)Represents Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.
Summer peak load for the Utility has averaged 21,602 MW over the previous decade.
The Utility operating companies’ load and capacity projections are reviewed periodically to assess the need and timing for additional generating capacity and interconnections. These reviews consider existing and projected demand, the availability and price of power, the location of new load, the economy, Entergy’s clean energy and other public policy goals, environmental regulations, and the age and condition of Entergy’s existing infrastructure.
The Utility operating companies’ long-term resource strategy (Portfolio Transformation Strategy) calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Over the past decade, the Portfolio Transformation Strategy has resulted in the addition of about 8,975 MW of new long-term resources and the deactivation of about 4,881 MW of legacy generation. As MISO market participants, the Utility operating companies also participate in MISO’s Day Ahead and Real Time Energy and Ancillary Services markets to economically dispatch generation and purchase energy to serve customers reliably and at the lowest reasonable cost.
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Other Generation Resources
RFP Procurements
The Utility operating companies from time to time issue requests for proposals (RFP) to procure supply-side resources from sources other than the spot market to meet the unique regional needs of the Utility operating companies. The RFPs issued by the Utility operating companies have sought resources needed to meet near-term MISO reliability requirements as well as long-term requirements through a broad range of wholesale power products, including long-term contractual products and asset acquisitions. The RFP process has resulted in selections or acquisitions, including, among other things:
•Entergy Louisiana’s construction of the 980 MW, combined-cycle, gas turbine J. Wayne Leonard Power Station (previously referred to as the St. Charles generating facility) at its existing Little Gypsy electric generating station. The facility began commercial operation in May 2019;
•Entergy Louisiana’s construction of the 994 MW, combined-cycle, gas turbine Lake Charles generating facility at its existing Nelson electric generating station site. The facility began commercial operation in March 2020;
•Entergy Texas’s construction of the 993 MW, combined-cycle, gas turbine Montgomery County Power Station at its existing Lewis Creek electric generating station. The facility began commercial operation in January 2021;
•Entergy New Orleans’s construction of the 20 MW solar photovoltaic facility, New Orleans Solar Station, located at the NASA Michoud Facility. The facility began commercial operation in December 2020;
•In December 2020, Entergy Texas selected the self-build alternative, Orange County Advanced Power Station, out of the 2020 Entergy Texas combined-cycle, gas turbine RFP. Regulatory approval was received in November 2022 and construction has commenced. The facility is expected to be in service by mid-2026;
•In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Searcy Solar facility, sited on approximately 800 acres in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the APSC in April 2020, and closed on the acquisition, through use of a tax equity partnership, in December 2021. The Searcy Solar facility was placed in service in January 2022;
•In November 2018, Entergy Mississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Sunflower Solar facility, sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and the Sunflower Solar facility began commercial operation in September 2022;
•In June 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Walnut Bend Solar facility, that will be sited on approximately 1,000 acres in Lee County, Arkansas. In July 2021 the APSC issued an order approving the acquisition of the Walnut Bend Solar facility. The counter-party notified Entergy Arkansas that it was terminating the project, though it was willing to consider an alternative for the site. Entergy Arkansas disputed the right of termination. Negotiations are ongoing, including with respect to cost and schedule and to updates arising as a result of the Inflation Reduction Act of 2022, and the updates would require additional APSC approval. At this time the project, if approved, is expected to achieve commercial operation in 2024;
•In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility, West Memphis Solar facility, that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In October 2021 the APSC issued an order approving the acquisition of the West Memphis Solar facility. The counter-party notified Entergy Arkansas that it was seeking changes to certain terms of the build-own-transfer agreement, including both cost and schedule. In January 2023, Entergy Arkansas made a supplemental filing with the APSC. Following APSC supplemental approval, full notice to proceed will be issued with closing expected to occur in 2024;
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•In November 2021, Entergy Louisiana signed an agreement for the purchase of an approximately 150 MW to-be-constructed solar photovoltaic energy facility, St. Jacques facility, that will be sited in St. James Parish near Vacherie, Louisiana. In September 2022 the LPSC voted to approve the order including the St. Jacques facility; however, project details could be adjusted pending a final St. James Parish ruling on land use permit requirements. Closing is expected to occur in 2025 dependent upon the final St. James Parish ruling; and
•In August 2022, Entergy Arkansas signed an agreement for the purchase of an approximately 250 MW to-be-constructed solar photovoltaic energy facility, Driver Solar facility, that will be sited near Osceola, Arkansas. Also in August 2022, Entergy Arkansas received necessary approvals for the Driver Solar facility, and Entergy Arkansas has issued the counter-party full notice to proceed to begin construction. The parties are evaluating the effects of certain matters related to the Inflation Reduction Act of 2022, including the viability of a tax equity partnership. Closing is expected to occur by the end of 2024.
The RFP process has also resulted in the selection, or confirmation of the economic merits of, long-term purchased power agreements (PPAs), including, among others:
•River Bend’s 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’s 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 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. In November 2019, LS Power sold and transferred the Carville Energy Center and facility to Argo Infrastructure Partners, which included the power purchase agreement;
•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 to-be-constructed solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and the PPA began in November 2020;
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•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 to-be-constructed solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the PPA began in October 2020;
•In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in the first half of 2023;
•In August 2018, Entergy Louisiana and South Alexander Development I, LLC executed a 5-year agreement for 5 MW from a solar photovoltaic electric generating facility located in Livingston Parish, Louisiana. The PPA began in December 2020 and received regulatory approval in January 2021;
•In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and achieved commercial operation in November 2022;
•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in Polk County, Texas. The PPA is expected to start when the facility reaches commercial operation in December 2023;
•In June 2021, Entergy Louisiana and Sunlight Road Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. In September 2022 the LPSC voted to approve the order including this project. The facility is expected to reach commercial operation in December 2024;
•In June 2021, Entergy Louisiana and Vacherie Solar Energy Center, LLC executed a 20-year PPA for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. In September 2022 the LPSC voted to approve the order including this project; however, project details could be adjusted pending a final St. James Parish ruling on land use permit requirements. The facility is expected to reach commercial operation in 2025;
•In November 2021, Entergy Louisiana signed a PPA for approximately 125 MW from a to-be-constructed solar photovoltaic energy facility located in Allen, Louisiana. In September 2022 the LPSC voted to approve the order including this project. The facility is expected to reach commercial operation in February 2024;
•In December 2022, Entergy Mississippi signed a PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Hinds County, Mississippi. Following execution of the agreement, Entergy Mississippi filed a petition with the MPSC requesting all necessary approvals. The facility is expected to reach commercial operation in June 2026;
•In October 2022, Entergy Mississippi signed a PPA for approximately 100 MW from a to-be-constructed solar photovoltaic energy facility located in Tallahatchie County, Mississippi. Following execution of the agreement, Entergy Mississippi filed a petition with the MPSC requesting all necessary approvals. The facility is expected to reach commercial operation as early as May 2026;
•In October 2022, Entergy Mississippi signed a PPA for approximately 170 MW from a to-be-constructed solar photovoltaic energy facility located in Washington County, Mississippi. Following execution of the agreement, Entergy Mississippi filed a petition with the MPSC requesting all necessary approvals. The facility is expected to reach commercial operation as early as May 2026;
•In October 2022, Entergy Arkansas signed a PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in St. Francis County, Arkansas. Following execution of the agreement, Entergy Arkansas filed a petition with the APSC requesting all necessary approvals. The facility is expected to reach commercial operation as early as May 2025;
•In October 2022, Entergy Arkansas signed a PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in Mississippi County, Arkansas. Following execution of the agreement, Entergy Arkansas filed a petition with the APSC requesting all necessary approvals. The facility is expected to reach commercial operation as early as May 2025; and
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•In January 2023, Entergy Texas signed a PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Walker County, Texas. The facility is expected to reach commercial operation as early as June 2026.
In March 2021, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic resources. Entergy Louisiana selected a combination of PPA and build-own-transfer resources by March 2022, some of which have been executed and are noted above and the remainder are in progress working through definitive agreements.
In July 2021, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar generation resources. Entergy Texas selected a combination of PPA and build-own-transfer resources in March 2022. One PPA was executed in January 2023 as noted above, and definitive agreements for the remaining resources are in progress.
In August 2021, Entergy Services, on behalf of Entergy Arkansas, issued an RFP for solar photovoltaic and wind resources. Entergy Arkansas selected a combination of PPA and build-own-transfer resources in February 2022, some of which have been executed and are noted above and the remainder are in progress working through definitive agreements.
In January 2022, Entergy Services, on behalf of Entergy Mississippi, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 500 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Mississippi customers.
In June 2022, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 1500 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Louisiana customers.
In April 2022, Entergy Services, on behalf of Entergy Arkansas, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 1000 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Arkansas customers.
In October 2022, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 2000 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Texas customers.
In November 2022, Entergy Services, on behalf of Entergy Mississippi, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 500 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Mississippi customers.
Other Procurements From Third Parties
The Utility operating companies have also made resource acquisitions outside of the RFP process, including Entergy Arkansas’s (Power Block 2), Entergy Louisiana’s (Power Blocks 3 and 4), and Entergy New Orleans’s (Power Block 1) March 2016 acquisitions of the 1,980 MW (summer rating), natural gas-fired, combined-cycle gas turbine Union Power Station power blocks, each rated at 495 MW (summer rating); and Entergy Mississippi’s October 2019 acquisition of the 810 MW, combined-cycle, natural gas-fired Choctaw Generating Station. The
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Utility operating companies have also entered into various limited- and long-term contracts in recent years as a result of bilateral negotiations.
The Washington Parish Energy Center is a 361 MW natural gas-fired peaking power plant approximately 60 miles north of New Orleans on a site Entergy Louisiana purchased from Calpine in 2019. In May 2018, Entergy Louisiana received LPSC approval of its certification application for this simple-cycle power plant to be developed pursuant to an agreement between Calpine and Entergy Louisiana. Calpine began construction on the plant in early 2019 and Entergy Louisiana purchased the plant upon completion in November 2020.
The Hardin County Peaking Facility, an existing 147 MW simple-cycle gas-fired peaking power plant in Kountze, Texas, previously owned by East Texas Electric Cooperative, was acquired by Entergy Texas in June 2021. The facility has been in operation since January 2010.
Power Through Programs
In December 2020, Entergy Texas filed an application with the PUCT to amend its certificate of convenience and necessity to own and operate up to 75 MW of natural gas-fired distributed generation to be installed at commercial and industrial customer premises. Under this proposal, Entergy Texas would own and operate a fleet of generators ranging from 100 kW to 10 MW that would supply a portion of Entergy Texas’s long-term resource needs and enhance the resiliency of Entergy Texas’s electric grid. This fleet of generators would also be available to customers during outages to supply backup electric service as part of a program known as “Power Through.” In its 2021 session, the Texas legislature modified the Texas Utilities Code to exempt generators under 10 megawatts from the requirement to obtain a certificate of convenience and necessity. In addition, the PUCT announced an intent to conduct a broad rulemaking related to distributed generation and recommended that utilities with pending applications addressing distributed generation withdraw them. Accordingly, Entergy Texas withdrew its application for a certificate of convenience and necessity and associated tariff from the PUCT without prejudice to refiling. Entergy Texas continues to deploy certain customer-sited distributed generators under an existing PUCT-approved tariff. In August 2022, Entergy Texas filed an application for PUCT approval of voluntary Rate Schedule Utility Owned Distributed Generation (UODG) through which it would charge host customers for back-up service from customer-sited Power Through generators. Based on the exemption enacted by the Texas legislature in 2021, Entergy Texas’s application was not required to, and did not, seek an amendment to its certificate of convenience and necessity in order to continue deploying Power Through generators. In October 2022 two intervenors filed requests for a hearing on Entergy Texas’s application. In October 2022 the PUCT staff filed a request that the proceeding be referred to the State Office of Administrative Hearings. In January 2023 the PUCT announced an intent to develop certain broadly applicable reliability metrics against which to measure distributed generation resources and directed Entergy Texas to withdraw its application. However, the PUCT did allow Entergy Texas to continue its pilot program for Power Through generators. Entergy Texas has withdrawn its application and is considering next steps.
In August 2021, Entergy Arkansas filed with the APSC an application for authority to deploy natural gas-fired distributed generation. The application was supported by a number of letters of interest from Entergy Arkansas customers. In December 2021 the APSC general staff requested briefing, which Entergy Arkansas opposed. In January 2022, Entergy Arkansas filed to support the establishment of a procedural schedule with a hearing in April 2022. Also in January 2022, the APSC granted the general staff’s request for briefing but on an expedited schedule; briefing concluded in February 2022. Based on testimony filed to date the APSC general staff, Arkansas Electric Energy Consumers, Sierra Club, and Audubon oppose Entergy Arkansas’s proposed “Power Through” offering, which has been demonstrated to be in high demand by interested customers, some of which directly have filed public comments encouraging the APSC to approve the application. A paper hearing was held in August and September 2022 with Entergy Arkansas responding to several written commissioner questions. The parties are awaiting a decision from the APSC.
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In July 2021, Entergy Louisiana filed with the LPSC an application for authority to deploy natural gas-fired distributed generation. The application was supported by a number of letters of interest from Entergy Louisiana customers. In October 2021, a procedural schedule was established with a hearing in April 2022. Staff and certain intervenors filed direct testimony in December 2021, and cross-answering testimony was filed in January 2022. Entergy Louisiana filed rebuttal testimony in February 2022. The parties reached an uncontested settlement which, among other things, recommended approval of 120 MW of natural gas fired distributed generation and an additional 30 MW of solar and battery distributed generation, for a total distributed generation program of 150 MW. Pursuant to the terms of the settlement agreement, Entergy Louisiana may seek to expand the distributed generation program following the earlier of two years after issuance of an order approving the settlement or the installation of 60 MW of distributed generation pursuant to this program. The settlement was approved by the LPSC in November 2022.
Interconnections
The Utility operating companies’ generating units are interconnected to a transmission system operating at various voltages up to 500 kV. These generating units consist of steam-turbine generators fueled by natural gas and coal, combustion-turbine generators, and reciprocating internal combustion engine generators that are fueled by natural gas, generators powered by pressurized and boiling water nuclear reactors and inverter-based resources interconnecting both solar photovoltaic systems and energy storage devices that operate in the MISO wholesale electric market. Additionally, some of the Utility operating companies also offer customer services and products that include resources interconnected to both the distribution and transmission systems that also participate in the wholesale market. Entergy’s Utility operating companies are MISO market participants and the companies’ transmission systems are interconnected with those of many neighboring utilities. MISO is an essential link in the safe, cost-effective delivery of electric power across all or parts of 15 U.S. states and the Canadian province of Manitoba. In addition, the Utility operating companies are members of SERC Reliability Corporation (SERC), the Regional Entity with delegated authority from the North American Electric Reliability Corporation (NERC) for the purpose of proposing and enforcing Bulk Electric System reliability standards within 16 central and southeastern states.
Gas Property
As of December 31, 2022, Entergy New Orleans distributed and transported natural gas for distribution within New Orleans, Louisiana, through approximately 2,600 miles of gas pipeline. As of December 31, 2022, the gas properties of Entergy Louisiana, which are located in and around Baton Rouge, Louisiana, were not material to Entergy Louisiana’s financial position.
Title
The Utility operating companies’ generating stations are generally located on properties owned in fee simple. Most of the substations and transmission and distribution lines are constructed on private property or public rights-of-way pursuant to easements, servitudes, or appropriate franchises. Some substation properties are owned in fee simple. The Utility operating companies generally have the right of eminent domain, whereby they may perfect title to, or secure easements or servitudes on, private property for their utility operations.
Substantially all of the physical properties and assets owned by Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are subject to the liens of mortgages securing bonds issued by those companies. The Lewis Creek generating station of Entergy Texas was acquired by merger with a subsidiary of Entergy Texas and is currently not subject to the lien of the Entergy Texas indenture.
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Fuel Supply
The average fuel cost per kWh for the Utility operating companies and System Energy for the years 2020-2022 were:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year | | Natural Gas | | Nuclear | | Coal | | Renewables (a) | | Purchased Power | | MISO Purchases (b) |
| 2022 | | (Cents Per kWh) |
| Entergy Arkansas | | 4.98 | | | 0.52 | | | 2.93 | | | 2.11 | | | 10.90 | | | (2.65) | |
| Entergy Louisiana | | 5.50 | | | 0.57 | | | 2.84 | | | 10.70 | | | 6.95 | | | 6.45 | |
| Entergy Mississippi | | 4.38 | | | — | | | 2.85 | | | 0.04 | | | 6.53 | | | 6.68 | |
| Entergy New Orleans (c) | | 5.10 | | | — | | | — | | | (5.16) | | | — | | | 7.21 | |
| Entergy Texas | | 5.77 | | | — | | | 2.83 | | | 6.26 | | | 5.61 | | | 6.68 | |
| System Energy | | — | | | 0.65 | | | — | | | — | | | — | | | — | |
| Utility | | 5.27 | | | 0.57 | | | 2.89 | | | 7.00 | | | 6.54 | | | 5.95 | |
| | | | | | | | | | | | |
| 2021 | | | | | | | | | | | | |
| Entergy Arkansas | | 4.11 | | | 0.56 | | | 2.43 | | | 2.85 | | | 2.53 | | | 3.87 | |
| Entergy Louisiana | | 3.77 | | | 0.56 | | | 2.62 | | | 10.87 | | | 5.52 | | | 4.04 | |
| Entergy Mississippi | | 2.71 | | | — | | | 2.53 | | | 1.22 | | | 2.70 | | | 4.16 | |
| Entergy New Orleans (c) | | 3.47 | | | — | | | — | | | (2.82) | | | — | | | 4.50 | |
| Entergy Texas | | 4.65 | | | — | | | 2.60 | | | 3.97 | | | 4.53 | | | 4.10 | |
| System Energy | | — | | | 0.55 | | | — | | | — | | | — | | | — | |
| Utility | | 3.75 | | | 0.56 | | | 2.48 | | | 9.07 | | | 4.76 | | | 4.08 | |
| | | | | | | | | | | | |
| 2020 | | | | | | | | | | | | |
| Entergy Arkansas | | 1.78 | | | 0.62 | | | 2.35 | | | 2.28 | | | 7.39 | | | 0.63 | |
| Entergy Louisiana | | 1.98 | | | 0.58 | | | 3.27 | | | 9.99 | | | 3.48 | | | 2.65 | |
| Entergy Mississippi | | 1.73 | | | — | | | 2.52 | | | 0.25 | | | 3.23 | | | 2.26 | |
| Entergy New Orleans | | 1.56 | | | — | | | — | | | 0.02 | | | — | | | 2.99 | |
| Entergy Texas | | 2.23 | | | — | | | 3.17 | | | 3.61 | | | 3.29 | | | 2.71 | |
| System Energy | | — | | | 0.39 | | | — | | | — | | | — | | | — | |
| Utility | | 1.92 | | | 0.57 | | | 2.54 | | | 8.28 | | | 3.35 | | | 2.48 | |
(a)Includes average fuel costs from both owned and purchased power resources.
(b)Includes activity from financial transmission rights. See Note 15 to the financial statements for discussion of financial transmission rights.
(c)Entergy New Orleans’s renewables include liquidated damage payments of $2.9 million in 2022 and $1 million in 2021 due to the delay of in-service dates related to purchased power agreements.
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Actual 2022 and projected 2023 sources of generation for the Utility operating companies and System Energy, including certain power purchases from affiliates under life of unit power purchase agreements, including the Unit Power Sales Agreement, are:
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| 2022 |
| | CT / CCGT (b) | | Legacy Gas | | Nuclear | | Coal | | Renewables (c) | | Purchased Power (d) | | MISO Purchases (e) |
| Entergy Arkansas | 30 | % | | 1 | % | | 50 | % | | 12 | % | | 3 | % | | — | % | | 4 | % |
| Entergy Louisiana | 44 | % | | 9 | % | | 23 | % | | 3 | % | | 2 | % | | 8 | % | | 11 | % |
| Entergy Mississippi | 59 | % | | 6 | % | | 18 | % | | 7 | % | | 1 | % | | — | % | | 9 | % |
| Entergy New Orleans | 54 | % | | 1 | % | | 35 | % | | 1 | % | | 1 | % | | 1 | % | | 7 | % |
| Entergy Texas | 31 | % | | 20 | % | | 11 | % | | 5 | % | | — | % | | 9 | % | | 24 | % |
| System Energy (a) | — | % | | — | % | | 100 | % | | — | % | | — | % | | — | % | | — | % |
| Utility | 42 | % | | 8 | % | | 27 | % | | 5 | % | | 2 | % | | 5 | % | | 11 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2023 |
| | CT / CCGT (b) | | Legacy Gas | | Nuclear | | Coal | | Renewables (c) | | Purchased Power (d) | | MISO Purchases (e) |
| Entergy Arkansas | 26 | % | | — | % | | 58 | % | | 13 | % | | 3 | % | | — | % | | — | % |
| Entergy Louisiana | 47 | % | | 5 | % | | 30 | % | | 3 | % | | 3 | % | | 12 | % | | — | % |
| Entergy Mississippi | 63 | % | | — | % | | 26 | % | | 10 | % | | 1 | % | | — | % | | — | % |
| Entergy New Orleans | 48 | % | | 1 | % | | 45 | % | | 2 | % | | 3 | % | | 1 | % | | — | % |
| Entergy Texas | 44 | % | | 31 | % | | 15 | % | | 9 | % | | — | % | | 1 | % | | — | % |
| System Energy (a) | — | % | | — | % | | 100 | % | | — | % | | — | % | | — | % | | — | % |
| Utility | 44 | % | | 6 | % | | 36 | % | | 7 | % | | 2 | % | | 5 | % | | — | % |
(a)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.
(b)Represents natural gas sourced for Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.
(c)Includes generation from both owned and purchased power resources.
(d)Excludes MISO purchases and renewables purchased through purchased power agreements.
(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 2022 is not projected for 2023.
Some of the Utility’s gas-fired plants are also capable of using fuel oil, if necessary. Although based on current economics the Utility does not expect fuel oil use in 2023, it is possible that various operational events including weather or pipeline maintenance may require the use of fuel oil.
Natural Gas
The Utility operating companies have long-term firm and short-term interruptible gas contracts for both supply and transportation. Over 50% of the Utility operating companies’ power plants maintain some level of long-term firm transportation. Short-term contracts and spot-market purchases satisfy additional gas requirements.
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Entergy Texas owns a gas storage facility and Entergy Louisiana has a firm storage service agreement that provide reliable and flexible natural gas service to certain generating stations.
Many factors, including wellhead deliverability, storage, pipeline capacity, and demand requirements of end users, influence the availability and price of natural gas supplies for power plants. Demand is primarily tied to weather conditions as well as to the prices and availability of other energy sources. Pursuant to federal and state regulations, gas supplies to power plants may be interrupted during periods of shortage. To the extent natural gas supplies are disrupted or natural gas prices significantly increase, the Utility operating companies may in some instances use alternate fuels, such as oil when available, or rely to a larger extent on coal, nuclear generation, and purchased power.
Coal
Entergy Arkansas has committed to six two- to three-year contracts that will supply approximately 85% of the total coal supply needs in 2023. These contracts are staggered in term so that not all contracts have to be renewed the same year. If needed, additional Powder River Basin (PRB) coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. Based on the high cost of alternate sources, modes of transportation, and infrastructure improvements necessary for its delivery, no alternative coal consumption is expected at Entergy Arkansas during 2023. Coal will be transported to Arkansas via an existing Union Pacific transportation agreement that is expected to provide all of Entergy Arkansas’s rail transportation requirements for 2023.
Entergy Louisiana has committed to four two- to three-year contracts that will supply approximately 90% of Nelson Unit 6 coal needs in 2023. If needed, additional PRB coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. For the same reasons as the Entergy Arkansas plants, no alternative coal consumption is expected at Nelson Unit 6 during 2023. Coal will be transported to Nelson via an existing transportation agreement that is expected to provide all of Entergy Louisiana’s rail transportation requirements for 2023.
Coal transportation delivery rates to Entergy Arkansas- and Entergy Louisiana-operated coal-fired units became constrained and were unable to fully meet supply needs and obligations beginning in August 2021. Deliveries remained constrained through 2022 with modest improvement expected later in 2023. Both Entergy Arkansas and Entergy Louisiana control enough railcars to satisfy the rail transportation requirement.
The operator of Big Cajun 2 - Unit 3, Louisiana Generating, LLC, has advised Entergy Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2023, but is also currently experiencing delivery constraints. Entergy Louisiana’s and Entergy Texas’s coal nomination requests to Big Cajun 2 - Unit 3 are made on an annual basis.
Nuclear Fuel
The nuclear fuel cycle consists of the following:
•mining and milling of uranium ore to produce a concentrate;
•conversion of the concentrate to uranium hexafluoride gas;
•enrichment of the uranium hexafluoride gas;
•fabrication of nuclear fuel assemblies for use in fueling nuclear reactors; and
•disposal of spent fuel.
The Registrant Subsidiaries that own nuclear plants, Entergy Arkansas, Entergy Louisiana, and System Energy, are responsible through a shared regulated uranium pool for contracts to acquire nuclear material to be used in fueling Entergy’s Utility nuclear units. These companies own the materials and services in this shared regulated
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uranium pool on a pro rata fractional basis determined by the nuclear generation capability of each company. Any liabilities for obligations of the pooled contracts are on a several but not joint basis. The shared regulated uranium pool maintains inventories of nuclear materials during the various stages of processing. The Registrant Subsidiaries purchase enriched uranium hexafluoride for their nuclear plant reload requirements at the average inventory cost from the shared regulated uranium pool. Entergy Operations, Inc. contracts separately for the fabrication of nuclear fuel as agent on behalf of each of the Registrant Subsidiaries that owns a nuclear plant. All contracts for the disposal of spent nuclear fuel are between the DOE and the owner of a nuclear power plant.
Based upon currently planned fuel cycles, the Utility nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable or fixed prices through most of 2027. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners, including their ability to work through supply disruptions caused by global events, such as the COVID-19 pandemic, or national events, such as political disruption. There are a number of possible supply alternatives that may be accessed to mitigate any supplier performance failure, including potentially drawing upon Entergy’s inventory intended for later generation periods depending upon its risk management strategy at that time, although the pricing of any alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. In addition, some nuclear fuel contracts are on a non-fixed price basis subject to prevailing prices at the time of delivery.
The effects of market price changes may be reduced and deferred by risk management strategies, such as negotiation of floor and ceiling amounts for long-term contracts, buying for inventory or entering into forward physical contracts at fixed prices when Entergy believes it is appropriate and useful. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S.
Entergy’s ability to assure nuclear fuel supply also depends upon the performance reliability of conversion, enrichment, and fabrication services providers. There are fewer of these providers than for uranium. For conversion and enrichment services, like uranium, Entergy diversifies its supply by supplier and country and may take special measures as needed to ensure supply of enriched uranium for the reliable fabrication of nuclear fuel. For fabrication services, each plant is dependent upon the effective performance of the fabricator of that plant’s nuclear fuel, therefore, Entergy provides additional monitoring, inspection, and oversight for the fabrication process to assure reliability and quality.
Entergy Arkansas, Entergy Louisiana, and System Energy each have made arrangements to lease nuclear fuel and related equipment and services. The lessors, which are consolidated in the financial statements of Entergy and the applicable Registrant Subsidiary, finance the acquisition and ownership of nuclear fuel through credit agreements and the issuance of notes. These credit facilities are subject to periodic renewal, and the notes are issued periodically, typically for terms between three and seven years.
Natural Gas Purchased for Resale
Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with one interstate and three intrastate pipelines. Entergy New Orleans has a “no-notice” service gas purchase contract with Symmetry Energy Solutions which guarantees Entergy New Orleans gas delivery at specific delivery points and at any volume within the minimum and maximum set forth in the contract amounts. The Symmetry Energy Solutions gas supply is transported to Entergy New Orleans pursuant to a transportation service agreement with Gulf South Pipeline Co. This service is subject to FERC-approved rates. Entergy New Orleans also makes interruptible spot market purchases.
Entergy Louisiana purchased natural gas for resale in 2022 under a firm contract from Sequent Energy Management L.P. The gas is delivered through a combination of intrastate and interstate pipelines.
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As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy Louisiana’s or Entergy New Orleans’s suppliers failed to perform their obligations to deliver gas under their supply agreements. Gulf South Pipeline Co. could curtail transportation capacity only in the event of pipeline system constraints.
Federal Regulation of the Utility
State or local regulatory authorities, as described above, regulate the retail rates of the Utility operating companies. The FERC regulates wholesale sales of electricity rates and interstate transmission of electricity, including System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. See Note 2 to the financial statements for further discussion of federal regulation proceedings.
Transmission and MISO Markets
In December 2013 the Utility operating companies integrated into the MISO RTO. Although becoming a member of MISO did not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities, MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. MISO also exercises functional control of transmission planning and congestion management and provides schedules and pricing for the commitment and dispatch of generation that is offered into MISO’s markets, as well as pricing for load that bids into the markets. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their generating facilities into the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. Each Utility operating company has its own transmission pricing zone and a formula rate template (included as Attachment O to the MISO tariff) used to establish transmission rates within MISO. The terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets and the allocation of transmission upgrade costs, are subject to regulation by the FERC.
System Energy and Related Agreements
System Energy recovers costs related to its interest in Grand Gulf through rates charged to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans for capacity and energy under the Unit Power Sales Agreement (described below). In 1998 the FERC approved requests by Entergy Arkansas and Entergy Mississippi to accelerate a portion of their Grand Gulf purchased power obligations. Entergy Arkansas’s and Entergy Mississippi’s acceleration of Grand Gulf purchased power obligations ceased effective July 2001 and July 2003, respectively, as approved by the FERC. See Note 2 to the financial statements for discussion of proceedings at the FERC related to System Energy.
Unit Power Sales Agreement
The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System Energy’s ownership and leasehold interests in Grand Gulf to Entergy Arkansas (36%), Entergy Louisiana (14%), Entergy Mississippi (33%), and Entergy New Orleans (17%). Each of these companies is obligated to make payments to System Energy for its entitlement of capacity and energy on a full cost-of-service basis regardless of the quantity of energy delivered. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenue. The financial condition of System Energy depends upon the continued commercial operation of Grand Gulf and the receipt of such payments. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans generally recover payments made under the Unit Power Sales Agreement through rates charged to their customers.
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In the case of Entergy Arkansas and Entergy Louisiana, payments are also recovered through sales of electricity from their respective retained shares of Grand Gulf. Under a settlement agreement entered into with the APSC in 1985 and amended in 1988, Entergy Arkansas retains 22% of its 36% share of Grand Gulf-related costs and recovers the remaining 78% of its share in rates. In the event that Entergy Arkansas is not able to sell its retained share to third parties, it may sell such energy to its retail customers at a price equal to its avoided cost, which is currently less than Entergy Arkansas’s cost from its retained share. Entergy Arkansas has life-of-resources purchased power agreements with Entergy Louisiana and Entergy New Orleans that sell a portion of the output of Entergy Arkansas’s retained share of Grand Gulf to those companies, with the remainder of the retained share being sold to Entergy Mississippi through a separate life-of-resources purchased power agreement. In a series of LPSC orders, court decisions, and agreements from late 1985 to mid-1988, Entergy Louisiana was granted cost recovery with respect to costs associated with Entergy Louisiana’s share of capacity and energy from Grand Gulf, subject to certain terms and conditions. Entergy Louisiana retains and does not recover from retail ratepayers 18% of its 14% share of the costs of Grand Gulf capacity and energy and recovers the remaining 82% of its share in rates. Entergy Louisiana is allowed to recover through the fuel adjustment clause at 4.6 cents per kWh for the energy related to its retained portion of these costs. Alternatively, Entergy Louisiana may sell such energy to non-affiliated parties at prices above the fuel adjustment clause recovery amount, subject to the LPSC’s approval. Entergy Arkansas also has a life-of-resources purchased power agreement with Entergy Mississippi to sell a portion of the output of Entergy Arkansas’s non-retained share of Grand Gulf. Entergy Mississippi was granted cost recovery for those purchases by the MPSC through its annual unit power cost rate mechanism.
Availability Agreement
The Availability Agreement among System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans was entered into in 1974 in connection with the original financing by System Energy of Grand Gulf. The Availability Agreement provides that System Energy make available to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans all capacity and energy available from System Energy’s share of Grand Gulf.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans also agreed severally to pay System Energy monthly for the right to receive capacity and energy from Grand Gulf in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement) would at least equal System Energy’s total operating expenses for Grand Gulf (including depreciation at a specified rate and expenses incurred in a permanent shutdown of Grand Gulf) and interest charges.
The allocation percentages under the Availability Agreement are fixed as follows: Entergy Arkansas - 17.1%; Entergy Louisiana - 26.9%; Entergy Mississippi - 31.3%; and Entergy New Orleans - 24.7%. The allocation percentages under the Availability Agreement would remain in effect and would govern payments made under such agreement in the event of a shortfall of operating expense funds available to System Energy from other sources, including payments under the Unit Power Sales Agreement.
System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for all of its outstanding series of first mortgage bonds, as well as for its outstanding term loan and the pollution control revenue refunding bonds issued on its behalf. In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they were prohibited by governmental action from making payments under the Availability Agreement (for example, if the FERC reduced or disallowed such payments as constituting excessive rates), they would then make subordinated advances to System Energy in the same amounts and at the same times as the prohibited payments. System Energy would not be allowed to repay these subordinated advances so long as it remained in default under the related indebtedness or in other similar circumstances.
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Each of the assignment agreements relating to the Availability Agreement provides that Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans will make payments directly to System Energy. However, if there is an event of default, those payments must be made directly to the holders of indebtedness that are the beneficiaries of such assignment agreements. The payments must be made pro rata according to the amount of the respective obligations secured.
The obligations of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans to make payments under the Availability Agreement are subject to the receipt and continued effectiveness of all necessary regulatory approvals. Sales of capacity and energy under the Availability Agreement would require that the Availability Agreement be submitted to the FERC for approval with respect to the terms of such sale. No such filing with the FERC has been made because sales of capacity and energy from Grand Gulf are being made pursuant to the Unit Power Sales Agreement. If, for any reason, sales of capacity and energy are made in the future pursuant to the Availability Agreement, the jurisdictional portions of the Availability Agreement would be submitted to the FERC for approval.
Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement to System Energy have exceeded the amounts payable under the Availability Agreement and, therefore, 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 certain of 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 because their Availability Agreement obligations exceed their Unit Power Sales Agreement obligations.
The Availability Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, without further consent of any assignees or other creditors.
Service Companies
Entergy Services, a limited liability company wholly-owned by Entergy Corporation, provides management, administrative, accounting, legal, engineering, and other services primarily to the Utility operating companies, but also provides services to Entergy Wholesale Commodities. Entergy Operations is also wholly-owned by Entergy Corporation and provides nuclear management, operations and maintenance services under contract for ANO, River Bend, Waterford 3, and Grand Gulf, subject to the owner oversight of Entergy Arkansas, Entergy Louisiana, and System Energy, respectively. Entergy Services and Entergy Operations provide their services to the Utility operating companies and System Energy on an “at cost” basis, pursuant to cost allocation methodologies for these service agreements that were approved by the FERC.
Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas
Effective December 31, 2007, Entergy Gulf States, Inc. completed a jurisdictional separation into two vertically integrated utility companies, one operating under the sole retail jurisdiction of the PUCT, Entergy Texas, and the other operating under the sole retail jurisdiction of the LPSC, Entergy Gulf States Louisiana. Entergy Texas owns all Entergy Gulf States, Inc. distribution and transmission assets located in Texas, the gas-fired generating plants located in Texas, undivided 42.5% ownership shares of Entergy Gulf States, Inc.’s 70% ownership interest in Nelson Unit 6 and 42% ownership interest in Big Cajun 2, Unit 3, which are coal-fired generating plants located in Louisiana, and other assets and contract rights to the extent related to utility operations in Texas. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, owns all of the remaining assets that were owned by Entergy Gulf States, Inc. On a book value basis, approximately 58.1% of the Entergy Gulf States, Inc. assets were allocated to Entergy Gulf States Louisiana and approximately 41.9% were allocated to Entergy Texas.
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Entergy Texas purchases from Entergy Louisiana pursuant to a life-of-unit purchased power agreement a 42.5% share of capacity and energy from the 70% of River Bend subject to retail regulation. Entergy Texas was allocated a share of River Bend’s nuclear and environmental liabilities that is identical to the share of the plant’s output purchased by Entergy Texas under the purchased power agreement. In connection with the termination of the System Agreement effective August 31, 2016, the purchased power agreements that were put in place for certain legacy units at the time of the jurisdictional separation were also terminated at that time. See Note 2 to the financial statements for additional discussion of the purchased power agreements.
Entergy Louisiana and Entergy Gulf States Louisiana Business Combination
On October 1, 2015, the businesses formerly conducted by Entergy Louisiana (Old Entergy Louisiana) and Entergy Gulf States Louisiana (Old Entergy Gulf States Louisiana) were combined into a single public utility. In order to effect the business combination, under the Texas Business Organizations Code (TXBOC), Old Entergy Louisiana allocated substantially all of its assets to a new subsidiary, Entergy Louisiana Power, LLC, a Texas limited liability company (New Entergy Louisiana), and New Entergy Louisiana assumed the liabilities of Old Entergy Louisiana, in a transaction regarded as a merger under the TXBOC. Under the TXBOC, Old Entergy Gulf States Louisiana allocated substantially all of its assets to a new subsidiary (New Entergy Gulf States Louisiana) and New Entergy Gulf States Louisiana assumed the liabilities of Old Entergy Gulf States Louisiana, in a transaction regarded as a merger under the TXBOC. New Entergy Gulf States Louisiana then merged into New Entergy Louisiana with New Entergy Louisiana surviving the merger. Thereupon, Old Entergy Louisiana changed its name from “Entergy Louisiana, LLC” to “EL Investment Company, LLC” and New Entergy Louisiana changed its name from “Entergy Louisiana Power, LLC” to “Entergy Louisiana, LLC” (Entergy Louisiana). With the completion of the business combination, Entergy Louisiana holds substantially all of the assets, and has assumed the liabilities, of Old Entergy Louisiana and Old Entergy Gulf States Louisiana.
Entergy New Orleans Internal Restructuring
In November 2017, pursuant to the agreement in principle, Entergy New Orleans, Inc. undertook a multi-step restructuring, including the following:
•Entergy New Orleans, Inc. redeemed its outstanding preferred stock at a price of approximately $21 million, which included a call premium of approximately $819,000, plus any accumulated and unpaid dividends.
•Entergy New Orleans, Inc. converted from a Louisiana corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy New Orleans, Inc. allocated substantially all of its assets to a new subsidiary, Entergy New Orleans Power, LLC, a Texas limited liability company (Entergy New Orleans Power), and Entergy New Orleans Power assumed substantially all of the liabilities of Entergy New Orleans, Inc. in a transaction regarded as a merger under the TXBOC. Entergy New Orleans, Inc. remained in existence and held the membership interests in Entergy New Orleans Power.
•Entergy New Orleans, Inc. contributed the membership interests in Entergy New Orleans Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy New Orleans Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2017, Entergy New Orleans, Inc. changed its name to Entergy Utility Group, Inc., and Entergy New Orleans Power then changed its name to Entergy New Orleans, LLC. Entergy New Orleans, LLC holds substantially all of the assets, and has assumed substantially all of the liabilities, of Entergy New Orleans, Inc. The restructuring was accounted for as a transaction between entities under common control.
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Entergy Arkansas Internal Restructuring
In November 2018, Entergy Arkansas undertook a multi-step restructuring, including the following:
•Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.
•Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Arkansas Power, LLC, a Texas limited liability company (Entergy Arkansas Power), and Entergy Arkansas Power assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.
•Entergy Arkansas, Inc. contributed the membership interests in Entergy Arkansas Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Arkansas Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Arkansas, Inc. changed its name to Entergy Utility Property, Inc., and Entergy Arkansas Power then changed its name to Entergy Arkansas, LLC. Entergy Arkansas, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Arkansas, Inc. The transaction was accounted for as a transaction between entities under common control.
Entergy Mississippi Internal Restructuring
In November 2018, Entergy Mississippi undertook a multi-step restructuring, including the following:
•Entergy Mississippi, Inc. redeemed its outstanding preferred stock, at the aggregate redemption price of approximately $21.2 million.
•Entergy Mississippi, Inc. converted from a Mississippi corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Mississippi, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Mississippi Power and Light, LLC, a Texas limited liability company (Entergy Mississippi Power and Light), and Entergy Mississippi Power and Light assumed substantially all of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Mississippi, Inc. remained in existence and held the membership interests in Entergy Mississippi Power and Light.
•Entergy Mississippi, Inc. contributed the membership interests in Entergy Mississippi Power and Light to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Mississippi Power and Light is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Mississippi, Inc. changed its name to Entergy Utility Enterprises, Inc., and Entergy Mississippi Power and Light then changed its name to Entergy Mississippi, LLC. Entergy Mississippi, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Mississippi, Inc. The restructuring was accounted for as a transaction between entities under common control.
Entergy Wholesale Commodities
See “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the shutdown and sale of each of the Entergy Wholesale Commodities nuclear power plants. With the sale of Palisades in June 2022, Entergy completed its multi-year strategy to exit the merchant power business.
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Entergy Wholesale Commodities includes the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. Entergy Wholesale Commodities also provides decommissioning-related services to nuclear power plants owned by non-affiliated entities in the United States.
Property
Entergy Wholesale Commodities includes ownership in the following non-nuclear power plants:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Plant | | Location | | Ownership | | Net Owned Capacity (a) | | Type |
| Independence Unit 2; 842 MW | | Newark, AR | | 14% | | 121 MW(b) | | Coal |
| Nelson Unit 6; 550 MW | | Westlake, LA | | 11% | | 60 MW(b) | | Coal |
(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.
All of Entergy Wholesale Commodities’ owned generation falls under the authority of MISO. Entergy Wholesale Commodities’ customers for the sale of both energy and capacity from its owned generation and its contracted power purchases include retail power providers, utilities, electric power co-operatives, power trading organizations, and other power generation companies. The majority of Entergy Wholesale Commodities’ owned generation and contracted power purchases are sold under cost-based contract.
Other Business Activities
TLG Services, a subsidiary in the Entergy Wholesale Commodities segment, offers decommissioning, engineering, and related services to nuclear power plant owners.
Regulation of Entergy’s Business
Federal Power Act
The Federal Power Act provides the FERC the authority to regulate:
•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.
The Federal Power Act gives the FERC jurisdiction over the rates charged by System Energy for Grand Gulf capacity and energy provided to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans and over the rates charged by Entergy Arkansas and Entergy Louisiana to unaffiliated wholesale customers. The FERC also regulates wholesale power sales between the Utility operating companies. In addition, the FERC regulates the MISO RTO, an independent entity that maintains functional control over the combined transmission systems of its members and administers wholesale energy, capacity, and ancillary services markets for market participants in the MISO region, including the Utility operating companies. FERC regulation of the MISO RTO includes regulation of the design and implementation of the wholesale markets administered by the MISO RTO, as
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well as the rates, terms, and conditions of open access transmission service over the member systems and the allocation of costs associated with transmission upgrades.
Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 65 MW of capacity.
State Regulation
Utility
Entergy Arkansas is subject to regulation by the APSC as to the following:
•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 non-exempt 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.
Additionally, Entergy Arkansas serves a limited number of retail customers in Tennessee. Pursuant to legislation enacted in Tennessee, Entergy Arkansas is subject to complaints before the Tennessee Regulatory Authority only if it fails to treat its retail customers in Tennessee in the same manner as its retail customers in Arkansas. Additionally, Entergy Arkansas maintains limited facilities in Missouri but does not provide retail electric service to customers in Missouri. Although Entergy Arkansas obtained a certificate with respect to its Missouri facilities, Entergy Arkansas is not subject to retail ratemaking jurisdiction in Missouri.
Entergy Louisiana’s electric and gas business is subject to regulation by the LPSC as to the following:
•utility service;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment clause, environmental adjustment charge, 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 for purchase power contracts that exceed either 5 MW or one year in term;
•procurement process to acquire capacity over 50 MW;
•audits of the energy efficiency rider;
•avoided cost payment to non-exempt Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers and acquisitions and other changes of control.
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Entergy Mississippi is subject to regulation by the MPSC as to the following:
•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;
•certification of generating facilities and certain transmission projects;
•avoided cost payments to non-exempt Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers, acquisitions, and other changes of control.
Entergy Mississippi is also subject to regulation by the APSC as to the certificate of environmental compatibility and public need for the Independence Station, which is located in Arkansas.
Entergy New Orleans is subject to regulation by the City Council as to the following:
•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;
•avoided cost payments to non-exempt Qualifying Facilities;
•issuance and sale of certain securities; and
•utility mergers and acquisitions and other changes of control.
To the extent authorized by governing legislation, Entergy Texas is subject to the original jurisdiction of the municipal authorities of a number of incorporated cities in Texas with appellate jurisdiction over such matters residing in the PUCT. Entergy Texas is also subject to regulation by the PUCT as to the following:
•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 non-exempt Qualifying Facilities;
•net energy metering; 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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Regulation of the Nuclear Power Industry
Atomic Energy Act of 1954 and Energy Reorganization Act of 1974
Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose civil penalties or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, Entergy Louisiana, and System Energy, as owners of all or portions of ANO, River Bend and Waterford 3, and Grand Gulf, respectively, and Entergy Operations, as the licensee and operator of these units, are subject to the jurisdiction of the NRC.
Nuclear Waste Policy Act of 1982
Spent Nuclear Fuel
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 Arkansas is the only one of the Utility operating companies that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 2022 of $195.0 million for the one-time fee. The fees payable to the DOE may be adjusted in the future to assure full recovery. 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. Entergy’s total spent fuel fees to date, including the one-time fee liability of Entergy Arkansas, have surpassed $1.7 billion (exclusive of amounts relating to Entergy plants that were paid or are owed by prior owners of those plants).
The permanent spent fuel repository in the U.S. has been legislated to be Yucca Mountain, Nevada. The DOE is required by law to proceed with the licensing (the DOE filed the license application in June 2008) and, after the license is granted by the NRC, proceed with the repository construction and commencement of receipt of spent fuel. 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. The DOE continues to delay meeting its obligation. Specific steps were taken to discontinue the Yucca Mountain project, including a motion to the NRC to withdraw the license application with prejudice and the establishment of a commission to develop recommendations for alternative spent fuel storage solutions. In August 2013 the U.S. Court of Appeals for the D.C. Circuit ordered the NRC to continue with the Yucca Mountain license review, but only to the extent of funds previously appropriated by Congress for that purpose and not yet used. Although the NRC completed the safety evaluation report for the license review in 2015, the previously appropriated funds are not sufficient to complete the review, including required hearings. The government has taken no effective action to date related to the recommendations of the appointed spent fuel study commission. Accordingly, large uncertainty remains regarding the time frame under which the DOE will begin to accept spent fuel from Entergy’s facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at Entergy’s nuclear sites.
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 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
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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.
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. These subsidiaries have been, and continue to be, involved in litigation to recover the damages caused by the DOE’s delay in performance. See Note 8 to the financial statements for discussion of final judgments recorded by Entergy in 2020, 2021, and 2022 related to Entergy’s nuclear owner licensee subsidiaries’ litigation with the DOE. Through 2022, Entergy’s subsidiaries have won and collected on judgments against the government totaling approximately $1 billion.
Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are providing their own spent fuel storage. Storage capability additions using dry casks began operations at ANO in 1996, at River Bend in 2005, at Grand Gulf in 2006, and at Waterford 3 in 2011. These facilities will be expanded as needed.
Nuclear Plant Decommissioning
Entergy Arkansas, Entergy Louisiana, and System Energy are entitled to recover from customers through electric rates the estimated decommissioning costs for ANO, Waterford 3, and Grand Gulf, respectively. In addition, Entergy Louisiana and Entergy Texas are entitled to recover from customers through electric rates the estimated decommissioning costs for the portion of River Bend subject to retail rate regulation. The collections are deposited in trust funds that can only be used in accordance with NRC and other applicable regulatory requirements. Entergy periodically reviews and updates the estimated decommissioning costs to reflect inflation and changes in regulatory requirements and technology, and then makes applications to the regulatory authorities to reflect, in rates, the changes in projected decommissioning costs.
In December 2018 the APSC ordered collections in rates for decommissioning ANO 2 and found that ANO 1’s decommissioning was adequately funded without additional collections. In November 2021, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that both ANO 1 and 2 decommissioning trusts were adequately funded without further collections, and in December 2021 the APSC ordered zero collections for ANO 1 and 2 decommissioning. In November 2022, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that ANO 1’s decommissioning trust was adequately funded, but that ANO 2’s fund had a projected shortage as a result of a decline in decommissioning trust fund investment values over the past year. The filing proposes a reinstatement of decommissioning cost recovery for ANO 2. Management cannot predict the outcome of this filing.
In July 2010 the LPSC approved increased decommissioning collections for Waterford 3 and the Louisiana regulated share of River Bend to address previously identified funding shortfalls. This LPSC decision contemplated that the level of decommissioning collections could be revisited should the NRC grant license extensions for both Waterford 3 and River Bend. In July 2019, following the NRC approval of license extensions for Waterford 3 and River Bend, Entergy Louisiana made a filing with the LPSC seeking to adjust decommissioning and depreciation rates for those plants, including one proposed scenario that would adjust Louisiana-jurisdictional decommissioning collections to zero for both plants (including an offsetting increase in depreciation rates). Because of the ongoing public health emergency arising from the COVID-19 pandemic and accompanying economic uncertainty, Entergy Louisiana determined that the relief sought in the filing was no longer appropriate, and in November 2020, filed an unopposed motion to dismiss the proceeding. Following that filing, in a December 2020 order, the LPSC dismissed the proceeding without prejudice. In July 2021, Entergy Louisiana made a filing with the LPSC to adjust Waterford 3 and River Bend decommissioning collections based on the latest site-specific decommissioning cost estimates for those plants. The filing seeks to increase Waterford 3 decommissioning collections and decrease River Bend decommissioning collections. The procedural schedule in the case has been suspended pending settlement negotiations. Management cannot predict the outcome of this filing.
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In December 2010 the PUCT approved increased decommissioning collections for the Texas share of River Bend to address previously identified funding shortfalls. In December 2018 the PUCT approved a settlement that eliminated River Bend decommissioning collections for the Texas jurisdictional share of the plant based on a determination by Entergy Texas that the existing decommissioning fund was adequate following license renewal. In July 2022, Entergy Texas filed a rate case that proposed continuation of the cessation of River Bend decommissioning collections. In December 2022, Entergy Texas filed on behalf of the parties a motion to abate the hearing on the merits to give parties additional time to finalize a settlement, which was approved by the presiding ALJ along with an order for the parties to file monthly settlement status reports. Management cannot predict the outcome of this filing.
In December 2016 the NRC issued a 20-year operating license renewal for Grand Gulf. In a 2017 filing at the FERC, System Energy stated that with the renewed operating license, Grand Gulf’s decommissioning trust was sufficiently funded, and proposed, among other things, to cease decommissioning collections for Grand Gulf effective October 1, 2017. The FERC accepted a settlement including the proposed decommissioning revenue requirement by letter order in August 2018.
Entergy currently believes its decommissioning funding will be sufficient for its nuclear plants subject to retail rate regulation, although decommissioning cost inflation and trust fund performance will ultimately determine the adequacy of the funding amounts.
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. In March 2021 filings with the NRC were made reporting on decommissioning funding for all of Entergy’s subsidiaries’ nuclear plants. Those reports showed that decommissioning funding for each of the nuclear plants met the NRC’s financial assurance requirements.
Additional information with respect to Entergy’s decommissioning costs and decommissioning trust funds is found in Note 9 and Note 16 to the financial statements.
Price-Anderson Act
The Price-Anderson Act requires that reactor licensees purchase and maintain the maximum amount of nuclear liability insurance available and participate in an industry assessment program called Secondary Financial Protection in order to protect 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 limits the contingent liability for a single nuclear incident to a maximum assessment of approximately $137.6 million per reactor (with 96 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, Entergy Louisiana, or System Energy is liable, protection is afforded through a combination of private insurance and the Secondary Financial Protection program. In addition to this, insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units is also purchased. The Price-Anderson Act and insurance applicable to the nuclear programs of Entergy are discussed in more detail in Note 8 to the financial statements.
NRC Reactor Oversight Process
The NRC’s Reactor Oversight Process is a program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response. The NRC evaluates plant performance by analyzing two distinct inputs: inspection findings resulting from the NRC’s inspection program and performance indicators reported by the licensee. The evaluations result in the placement of
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each plant in one of the NRC’s Reactor Oversight Process Action Matrix columns: “licensee response column,” or Column 1, “regulatory response column,” or Column 2, “degraded cornerstone column,” or Column 3, and “multiple/repetitive degraded cornerstone column,” or Column 4, and “unacceptable performance,” or Column 5. Plants in Column 1 are subject to normal NRC inspection activities. Plants in Column 2, Column 3, or Column 4 are subject to progressively increasing levels of inspection by the NRC. Continued plant operation is not permitted for plants in Column 5. All of the nuclear generating plants owned and operated by Entergy’s Utility business are currently in Column 1, except Waterford 3, which is in Column 2.
In September 2022 the NRC placed Waterford 3 in Column 2 based on an error associated with a radiation monitor calibration. Entergy corrected the issue with the radiation monitor in February 2022; however, Waterford 3 is expected to remain in Column 2 until third quarter 2023 based on a subsequent radiation monitor calibration issue.
Environmental Regulation
Entergy’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy’s businesses are in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted below. Because environmental regulations are subject to change, future compliance requirements and costs cannot be precisely estimated. Except to the extent discussed below, at this time compliance with federal, state, and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of Entergy’s businesses and is not expected to have a material effect on their competitive position, results of operations, cash flows, or financial position.
Clean Air Act and Subsequent Amendments
The Clean Air Act and its amendments establish several programs that currently or in the future may affect Entergy’s fossil-fueled generation facilities and, to a lesser extent, certain operations at nuclear and other facilities. Individual states also operate similar independent state programs or delegated federal programs that may include requirements more stringent than federal regulatory requirements. These programs include:
•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.
National Ambient Air Quality Standards
The Clean Air Act requires the EPA to set National Ambient Air Quality Standards (NAAQS) for ozone, carbon monoxide, lead, nitrogen dioxide, particulate matter, and sulfur dioxide, and requires periodic review of those standards. When an area fails to meet an ambient standard, it is considered to be in nonattainment and is classified as “marginal,” “moderate,” “serious,” or “severe.” When an area fails to meet the ambient air standard, the EPA requires state regulatory authorities to prepare state implementation plans meant to cause progress toward bringing the area into attainment with applicable standards.
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Ozone Nonattainment
Entergy Texas operates two fossil-fueled generating facilities (Lewis Creek and Montgomery County Power Station) in a geographic area that is not in attainment with the applicable NAAQS for ozone. The ozone nonattainment area that affects Entergy Texas is the Houston-Galveston-Brazoria area. Both Lewis Creek and the Montgomery County Power Station hold all necessary permits for operation and comply with applicable air quality program regulations. Measures enacted to return the area to ozone attainment could make these program regulations more stringent. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and nonattainment with the ozone NAAQS.
Potential SO2Nonattainment
The EPA issued a final rule in June 2010 adopting an SO2 1-hour national ambient air quality standard of 75 parts per billion. In Entergy’s utility service territory, only St. Bernard Parish and Evangeline Parish in Louisiana are designated as nonattainment. In August 2017 the EPA issued a letter indicating that East Baton Rouge and St. Charles parishes would be designated by December 31, 2020, as monitors were installed to determine compliance. In March 2021 the EPA published a final rule designating East Baton Rouge, St. Charles, St. James, and West Baton Rouge parishes in Louisiana as attainment/unclassifiable, and, in Texas, Jefferson County as attainment/unclassifiable and Orange County as unclassifiable. No challenges to these final designations were filed within the 60 day deadline. Entergy continues to monitor this situation.
Hazardous Air Pollutants
The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011, which had a compliance date, with a widely granted one-year extension, of April 2016. The required controls have been installed and are operational at all affected Entergy units. In May 2020 the EPA finalized a rule that finds that it is not “appropriate and necessary” to regulate hazardous air pollutants from electric steam generating units under the provisions of section 112(n) of the Clean Air Act. This is a reversal of the EPA’s previous finding requiring such regulation. The final appropriate and necessary finding does not revise the underlying MATS rule. Several lawsuits have been filed challenging the appropriate and necessary finding. In February 2021 the D.C. Circuit granted the EPA’s motion to hold the litigation in abeyance pending the agency’s review of the appropriate and necessary rule. In February 2022 the EPA issued a proposed rule revoking the 2020 rule and determining, again, that it is “appropriate and necessary” to regulate hazardous air pollutants. The EPA is seeking additional information, which it could use to further tighten the standard. Entergy will continue to monitor this situation.
Cross-State Air Pollution
In March 2005 the EPA finalized the Clean Air Interstate Rule (CAIR), which was intended to reduce SO2 and NOx emissions from electric generation plants in order to improve air quality in twenty-nine eastern states. The rule required a combination of capital investment to install pollution control equipment and increased operating costs through the purchase of emission allowances. Entergy began implementation in 2007, including installation of controls at several facilities and the development of an emission allowance procurement strategy. Based on several court challenges, CAIR and its subsequent versions, now known as the Cross-State Air Pollution Rule (CSAPR), have been remanded to and modified by the EPA on multiple occasions.
In April 2022 the EPA published a rule to address interstate transport for the 2015 ozone NAAQS which will increase the stringency of the CSAPR program in all four of the states where the Utility operating companies operate. If finalized as proposed, the rule will significantly reduce emission allowances and would likely require the installation of post-combustion nitrogen oxides (NOx) emissions controls on any coal or large legacy gas units that will operate beyond 2026 and are not currently equipped with such controls. Fifteen Entergy-owned units, totaling approximately 9,370 MW of total unit capacity, are identified by the EPA for selective catalytic reduction retrofits.
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Based on the EPA estimates, Entergy’s share of the capital costs would be approximately $1.6 billion if all the identified units were in fact retrofitted. Additionally, the EPA is proposing controls on certain non-electric generating NOx sources. Since releasing the proposed rule, the price for Group 3 NOx sources allowances has increased significantly, peaking at over $45,000 per allowance in late August 2022 before stabilizing in the range of $15,000 to $18,000 per allowance since September 2022. Comments on the proposed rule were due in June 2022. MISO, other impacted regional transmission organizations, and various state public service commissions all filed comments expressing reliability concerns if the rule is finalized as proposed. Entergy filed individual comments which assert, in addition to other issues, that the EPA’s proposal represents over-control of the Entergy units in Arkansas and Mississippi; the EPA should consider an alternative approach or provide flexibility for units with a limited remaining useful life; the EPA should consult with regional transmission organizations to determine the reliability impacts of the proposed rule; and the EPA should consider and incorporate current economic trends, including inflation, into any benefit-costs analysis supporting the rule.
Regional Haze
In June 2005 the EPA issued its final Clean Air Visibility Rule (CAVR) regulations that potentially could result in a requirement to install SO2 and NOx pollution control technology as Best Available Retrofit Control Technology to continue operating certain of Entergy’s fossil generation units. The rule leaves certain CAVR determinations to the states. This rule establishes a series of 10-year planning periods, with states required to develop State Implementation Plans (SIPs) for each planning period, with each SIP including such air pollution control measures as may be necessary to achieve the ultimate goal of the CAVR by the year 2064. The various states are currently in the process of developing SIPs to implement the second planning period of the CAVR, which addresses the 2018-2028 planning period.
In January and February 2018, Entergy Arkansas, Entergy Mississippi, Entergy Power, and other co-owners received 60-day notice of intent to sue letters from the Sierra Club and the National Parks Conservation Association concerning allegations of violations of new source review and permitting provisions of the Clean Air Act at the Independence and White Bluff coal-burning units, respectively. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims and reducing the risk that Entergy Arkansas, as operator of Independence and White Bluff, might be compelled under the Clean Air Act’s regional haze program to install costly emissions control technologies. Consistent with the terms of the settlement, Entergy Arkansas, along with co-owners, agreed to begin using only low-sulfur coal at Independence and White Bluff by mid-2021; agreed to cease using coal at White Bluff and Independence by the end of 2028 and 2030, respectively; agreed to cease operation of the remaining gas unit at Lake Catherine by the end of 2027; reserved the option to develop new generating sources at each plant site; and committed to installing or proposing to regulators at least 800 MWs of renewable generation by the end of 2027, with at least half installed or proposed by the end of 2022 (which includes two existing Entergy Arkansas projects) and with all qualifying co-owner projects counting toward satisfaction of the obligation. Under the settlement, the Sierra Club and the National Parks Conservation Association also waived certain potential existing claims under federal and state environmental law with respect to specified generating plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the National Parks Conservation Association, was subject to approval by the U.S. District Court for the Eastern District of Arkansas. In November 2020 the court denied motions by the Arkansas Attorney General and the Arkansas Affordable Energy Coalition to intervene and to stay the proceedings. The proposed intervenors did not appeal the ruling. The District Court approved and entered the proposed settlement in March 2021. Entergy met the settlement deadline to use low-sulfur coal and is on target to meet the other requirements of the settlement. See “Remaining Useful Lives Review” in the “State and Local Rate Regulation and Fuel-Cost Recovery” section of Entergy Arkansas, LLC and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the APSC’s proceeding related to Entergy Arkansas’s utility generation units.
The second planning period (2018-2028) for the regional haze program requires states to examine sources for impacts on visibility and to prepare SIPs by July 31, 2021 to ensure reasonable progress is being made to attain
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visibility improvements. Entergy received information collection requests from the Arkansas and Louisiana Departments of Environmental Quality requesting an evaluation of technical and economic feasibility of various NOx and SO2 control technologies for Independence, Nelson 6, Nelson Industrial Steam Company (NISCO), and Ninemile. Responses to the information collection requests have been submitted to the respective state agencies. Louisiana has issued its draft SIP which, at this time, does not propose any additional air emissions controls for the affected Entergy units in Louisiana. Some public commenters, however, believe additional air controls are cost-effective. It is not yet clear how the Louisiana Department of Environmental Quality (LDEQ) will respond in its final SIP, and the agency, like many other state agencies, did not meet the July 31, 2021 deadline to submit a SIP to the EPA for review.
Similar to the LDEQ, the Arkansas Department of Energy and Environment, Division of Environmental Quality (ADEQ) did not meet the July 31, 2021 SIP submission deadline, but subsequently submitted it to the EPA for review. The ADEQ reviewed Entergy’s Independence plant, but determined that additional air emission controls would not be cost-effective considering the facility’s commitment to cease coal-fired combustion by December 31, 2030.
The Texas Commission on Environmental Quality has completed its second-planning period SIP and submitted it to the EPA for review. There were no Entergy sources selected for additional emission controls. The Mississippi Department of Environmental Quality continues to develop its SIP, but there are no Entergy sources that are expected to be impacted.
In August 2022 the EPA issued findings of failure to submit regional haze SIPs to 15 states, including Louisiana and Mississippi. These findings were effective September 2022 and start the two-year period for the EPA to either approve a SIP submitted by the state or issue a final federal plan.
Greenhouse Gas Emissions
In July 2019 the EPA released the Affordable Clean Energy Rule (ACE), which applies only to existing coal-fired electric generating units. The ACE determines that heat rate improvements are the best system of emission reductions and lists six candidate technologies for consideration by states at each coal unit. The rule and associated rulemakings by the EPA replace the Obama administration’s Clean Power Plan, which established national emissions performance rates for existing fossil-fuel fired steam electric generating units and combustion turbines. The ACE rule provides states discretion in determining how the best system for emission reductions applies to individual units, including through the consideration of technical feasibility and the remaining useful life of the facility. The ADEQ and the LDEQ have issued information collection requests to Entergy facilities to help the states collect the information needed to determine the best system of emission reductions for each facility. Entergy responded to the requests. In January 2021 the U.S. Court of Appeals for the D.C. Circuit vacated ACE. The court held that ACE relied on an incorrect interpretation of the Clean Air Act that the statute expressly forecloses emission reduction approaches, such as emissions trading and generating shifting, that cannot be applied at and to the individual source. The court remanded ACE to the EPA for further consideration and also vacated the repeal of the Clean Power Plan. In March 2021 the D.C. Circuit issued a partial mandate vacating the ACE rule, but withheld the mandate vacating the repeal of the Clean Power Plan pending the EPA’s new rulemaking to regulate greenhouse gas emissions. Thus, there currently is no regulation in place with respect to greenhouse gas emissions from existing electric generating units and states are not expected to take further action to develop and submit plans at this time. In October 2021 the United States Supreme Court agreed to hear a challenge to the already vacated ACE rule. In June 2022 the United States Supreme Court held that the EPA could not use generation shifting as the best system of emission reduction under Section 111(d) of the Clean Air Act. The EPA does still have the authority to regulate greenhouse gas emissions, but those emissions reductions must be technology based. The EPA has announced its intent to propose a rule for existing power plants pursuant to the Clean Air Act by March 2023. The ultimate impact of the United States Supreme Court's decision cannot be determined at this time.
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In April 2021, President Biden announced a target for the United States in connection with the United Nations’ “Paris Agreement” on climate change. The target consists of a 50-52 percent reduction in economy-wide net greenhouse gas emissions from 2005 levels by 2030. President Biden has also stated that a goal of his administration is for the electric power industry to decarbonize fully by 2035. The details surrounding implementation of these targets are not finalized, and the impacts to Entergy of any potential related legislation cannot be predicted.
Entergy continues to support national legislation that would most efficiently reduce economy-wide greenhouse gas emissions and increase planning certainty for electric utilities. By virtue of its proportionally large investment in low-emitting generation technologies, Entergy has a low overall carbon dioxide emission “intensity,” or rate of carbon dioxide emitted per megawatt-hour of electricity generated. In anticipation of the imposition of carbon dioxide emission limits on the electric industry, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included a formal program to stabilize owned power plant carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in reducing emissions below 2000 levels. In 2006, Entergy started including emissions from controllable power purchases in addition to its ownership share of generation and established a second formal voluntary program to stabilize power plant carbon dioxide emissions and emissions from controllable power purchases, cumulatively over the period, at 20% below 2000 levels through 2010. In 2011, Entergy extended this commitment through 2020, which it ultimately outperformed by approximately 8% both cumulatively and on an annual basis. In 2019, in connection with a climate scenario analysis following the recommendations of the Task Force on Climate-related Financial Disclosures describing climate-related governance, strategy, risk management, and metrics and targets, Entergy announced a 2030 carbon dioxide emission rate goal focused on a 50% reduction from Entergy’s base year - 2000. Entergy now anticipates achieving this reduction several years early. In September 2020, Entergy announced a commitment to achieve net-zero greenhouse gas emissions by 2050 inclusive of all businesses, all applicable gases, and all emission scopes. In 2022, Entergy enhanced its commitment to include an interim goal of 50% carbon-free energy generating capacity by 2030 and expanded its interim emission rate goal to include all purchased power. See “Risk Factors” in Part I Item 1A for discussion of the risks associated with achieving these climate goals. Entergy’s comprehensive, third-party verified greenhouse gas inventory and progress against its voluntary goals are published on its website.
Entergy participates in the M.J. Bradley & Associates’ Annual Benchmarking Air Emissions Report, an annual analysis of the 100 largest U.S. electric power producers. The report is available on the M.J. Bradley website. Entergy participates annually in the Dow Jones Sustainability Index and in 2022 was listed on the North American Index. Entergy has been listed on the World or North American Index, or both, for 21 consecutive years. Entergy also participated in the 2022 CDP Climate Change and CDP Water Security evaluations, receiving a ‘B’ for both responses.
Potential Legislative, Regulatory, and Judicial Developments
In addition to the specific instances described above, there are a number of legislative and regulatory initiatives that are under consideration at the federal, state, and local level. Because of the nature of Entergy’s business, the imposition of any of these initiatives could affect Entergy’s operations. Entergy continues to monitor these initiatives and activities in order to analyze their potential operational and cost implications. These initiatives include:
•reconsideration and revision of ambient air quality standards downward which could lead to additional areas of nonattainment;
•designation by the EPA and state environmental agencies of areas that are not in attainment with national ambient air quality standards;
•introduction of bills in Congress and development of regulations by the EPA proposing further limits on SO2, mercury, carbon dioxide, and other air emissions. New legislation or regulations applicable to
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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 cap and trade programs to limit carbon dioxide and other greenhouse gases;
•efforts on the local, 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 polychlorinated biphenyls (PCBs);
•efforts by certain external groups to encourage reporting and disclosure of environmental, social, and governance 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;
•the regulation of the management, disposal, and beneficial reuse of coal combustion residuals; and
•the regulation of the management and disposal and recycling of equipment associated with renewable and clean energy sources such as used solar panels, wind turbine blades, hydrogen usage, or battery storage.
Clean Water Act
The 1972 amendments to the Federal Water Pollution Control Act (known as the Clean Water Act) provide the statutory basis for the National Pollutant Discharge Elimination System permit program, section 402, and the basic structure for regulating the discharge of pollutants from point sources to waters of the United States. The Clean Water Act requires virtually all discharges of pollutants to waters of the United States to be permitted. Section 316(b) of the Clean Water Act regulates cooling water intake structures, section 401 of the Clean Water Act requires a water quality certification from the state in support of certain federal actions and approvals, and section 404 regulates the dredge and fill of waters of the United States, including jurisdictional wetlands.
Federal Jurisdiction of Waters of the United States
In June 2020 the EPA’s revised definition of waters of the United States in the Navigable Waters Protection Rule (NWPR) became effective, narrowing the scope of Clean Water Act jurisdiction, as compared to a 2015 definition which had been stayed by several federal courts. In August 2021 a federal district court vacated and remanded the NWPR for further consideration. The EPA and the U.S. Army Corps of Engineers (Corps) subsequently issued a statement that the agencies would revert to pre-2015 regulations pending a new rulemaking. In December 2022 the EPA and the Corps released a final definition of waters of the United States that replaces the NWPR with a definition that is consistent with the pre-2015 regulatory regime as interpreted by several United States Supreme Court decisions. Most notably, the exclusion for waste treatment systems is retained.
Comprehensive Environmental Response, Compensation, and Liability Act of 1980
The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), authorizes the EPA to mandate clean-up by, or to collect reimbursement of clean-up costs from, owners or operators of sites at which hazardous substances may be or have been released. Certain private parties also may use CERCLA to recover response costs. Parties that transported hazardous substances to these sites or arranged for the disposal of the substances are also deemed liable by CERCLA. CERCLA has been interpreted to impose strict, joint, and several liability on responsible parties. Many states have adopted programs similar to CERCLA. Entergy subsidiaries in the Utility and Entergy Wholesale Commodities businesses have sent waste materials to various
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disposal sites over the years, and releases have occurred at Entergy facilities including nuclear facilities that have been or will be sold to decommissioning companies. In addition, environmental laws now regulate certain of Entergy’s operating procedures and maintenance practices that historically were not subject to regulation. Some disposal sites used by Entergy subsidiaries have been the subject of governmental action under CERCLA or similar state programs, resulting in site clean-up activities. Entergy subsidiaries have participated to various degrees in accordance with their respective potential liabilities in such site clean-ups and have developed experience with clean-up costs. The affected Entergy subsidiaries have established provisions for the liabilities for such environmental clean-up and restoration activities. Details of potentially material CERCLA and similar state program liabilities are discussed in the “Other Environmental Matters” section below.
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. As of December 31, 2022, Entergy has recorded asset retirement obligations related to CCR management of $27 million.
Pursuant to the EPA Rule, Entergy operates groundwater monitoring systems surrounding its coal combustion residual landfills located at White Bluff, Independence, and Nelson. Monitoring to date has detected concentrations of certain listed constituents in the area, but has not indicated that these constituents originated at the active landfill cells. Reporting has occurred as required, and detection monitoring will continue as the rule requires. In late-2017, Entergy determined that certain in-ground wastewater treatment system recycle ponds at its White Bluff and Independence facilities require management under the new EPA regulations. Consequently, in order to move away from using the recycle ponds, White Bluff and Independence each have installed a new permanent bottom ash handling system that does not fall under the CCR rule. As of November 2020, both sites are operating the new system and no longer are sending waste to the recycle ponds. Each site has commenced closure of its two recycle ponds (four ponds total), prior to the April 11, 2021 deadline under the finalized CCR rule for unlined recycle ponds. Any potential requirements for corrective action or operational changes under the new CCR rule continue to be assessed. Notably, ongoing litigation has resulted in the EPA’s continuing review of the rule. Consequently, the nature and cost of additional corrective action requirements may depend, in part, on the outcome of the EPA’s review.
Other Environmental Matters
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas
The EPA notified Entergy that the EPA believes Entergy is a PRP concerning PCB contamination at the F.J. Doyle Salvage facility in Leonard, Texas. The facility operated as a scrap salvage business during the 1970s to the 1990s. In May 2018 the EPA investigated the site surface and sub-surface soils and, in November 2018 the EPA conducted a removal action, including disposal of PCB contaminated soils. Entergy responded to the EPA’s information requests in May and July 2019. In November 2020 the EPA sent Entergy and other PRPs a demand letter seeking reimbursement for response costs totaling $4 million expended at the site. Liability and PRP
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allocation of response costs are yet to be determined. In December 2020, Entergy responded to the demand letter, without admitting liability or waiving any rights, indicating that it would engage in good faith negotiations with the EPA with respect to the demand. An initial meeting between the EPA and the PRPs took place in June 2021. Negotiations between the PRPs and the EPA are ongoing.
Litigation
Entergy uses legal and appropriate means to contest litigation threatened or filed against it, but certain states in which Entergy operates have proven to be unusually litigious environments. Judges and juries in Louisiana, Mississippi, and Texas have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. The litigation environment in these states poses a significant business risk to Entergy.
Asbestos Litigation(Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas)
See Note 8 to the financial statements for a discussion of this litigation.
Employment and Labor-related Proceedings (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
See Note 8 to the financial statements for a discussion of these proceedings.
Human Capital
Employees
Employees are an integral part of Entergy’s commitment to serving customers. As of December 31, 2022, Entergy subsidiaries employed 11,707 people.
| | | | | |
| Utility: | |
| Entergy Arkansas | 1,227 | |
| Entergy Louisiana | 1,597 | |
| Entergy Mississippi | 716 | |
| Entergy New Orleans | 296 | |
| Entergy Texas | 648 | |
| System Energy | — | |
| Entergy Operations | 3,317 | |
| Entergy Services | 3,870 | |
| Entergy Nuclear Operations | 13 | |
| Other subsidiaries | 23 | |
| Total Entergy | 11,707 | |
Approximately 3,084 employees are represented by the International Brotherhood of Electrical Workers, the United Government Security Officers of America, and the International Union, Security, Police, and Fire Professionals of America.
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Below is the breakdown of Entergy’s employees by gender and race/ethnicity:
| | | | | | | | | | | |
| Gender (%) | 2022 | | 2021 |
| Female | 22.2 | | 21.4 |
| Male | 77.8 | | 78.6 |
| | | | | | | | | | | |
| Race/Ethnicity (%) | 2022 | | 2021 |
| White | 74.8 | | 76.4 |
| Black/African American | 17.3 | | 16.4 |
| Hispanic/Latino | 3.0 | | 2.7 |
| Asian | 2.3 | | 2.0 |
| Other | 2.6 | | 2.5 |
Entergy’s Approach to Human Resources
Entergy’s people and culture enable its success; that is why acquiring, retaining, and developing talent are important components of Entergy’s human resources strategy. Entergy focuses on an approach that includes, among other things, governance and oversight; safety; organizational health, including diversity, inclusion, and belonging; and talent management.
Governance and Oversight
Ensuring that workplace processes support the desired culture and strategy begins with the Board of Directors and the Office of the Chief Executive. The Talent and Compensation Committee (formerly Personnel Committee) establishes priorities and each quarter reviews strategies and results on a range of topics covering the workforce, the workplace, and the marketplace. It oversees Entergy’s incentive plan design and administers its executive compensation plans to incentivize the behaviors and outcomes that support achievement of Entergy’s corporate objectives. Annually, it reviews executive performance, development, succession plans, and talent pipeline to align a high performing executive team with Entergy’s priorities. The Talent and Compensation Committee also oversees Entergy’s performance through regular briefings on a wide variety of human resources topics including Entergy’s safety culture and performance; organizational health; and diversity, inclusion, and belonging initiatives and performance.
The Talent and Compensation Committee’s Charter was revised in 2021 to acknowledge the committee’s responsibility for overseeing and monitoring the effectiveness of Entergy’s human capital strategies, including its workforce diversity, inclusion, and organizational health and safety strategies, programs, and initiatives. In recognition of the importance that organizational health and diversity, inclusion, and belonging play in enabling Entergy to achieve its business strategies, the committee receives periodic reports on Entergy’s organization health and diversity, inclusion, and belonging programs, strategies, and performance, including briefings at each of its regular meetings. The committee also receives updates on Entergy’s performance to date on key workforce, workplace, and marketplace measures, including progress in the representation of women and underrepresented minorities, both in the total workforce and in director level and above placements, progress in key diversity, inclusion, and belonging initiatives and diverse supplier spend.
Other committees of the Board oversee other key aspects of Entergy’s culture. For example, the Audit Committee reviews reports on enterprise risks, ethics, and compliance training and performance, as well as regular reports on calls made to Entergy’s ethics line and related investigations. To maximize the sharing of information and facilitate the participation of all Board members in these discussions, the Board schedules its regular committee meetings in a manner such that all directors can attend.
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The Office of the Chief Executive, which includes the Senior Vice President and Chief Human Resources Officer, ensures annual business plans are designed to support Entergy’s talent objectives, reviews workforce-related metrics, and regularly discusses the development, succession planning, and performance of their direct reports and other company officers.
Safety
Entergy’s safety objective is: Everyone Safe. All Day. Every Day. The continuation of the COVID-19 pandemic and another historic hurricane season presented significant challenges. Entergy employees achieved a total recordable incident rate of 0.51 in 2022, compared to 0.46 in 2021, and 0.40 in 2020. The results of 2021 unfortunately included an employee fatality. Entergy has enhanced dramatically leadership efforts and field presence to further its objective of zero fatalities, which it achieved in 2022. Also in 2022, there was a significant decrease in the number of serious injuries. The recordable incident rate equals the number of recordable incidents per 100 full-time equivalents. Recordable incidents include fatalities, lost-time accidents, restricted-duty accidents, and medical attentions and is not inclusive of potential work-related COVID-19 cases.
Organizational Health, including Diversity, Inclusion and Belonging (DIB)
Entergy believes that organizational health fosters an engaged and productive culture that positions Entergy to deliver sustainable value to its stakeholders. Entergy measures its progress through an organizational health survey coordinated by an external third party. Since initially administering the survey in 2014, Entergy improved from an initial score of 49 (fourth quartile) to a score in 2020 of 72 (second quartile), in 2021 of 63 (third quartile), and in 2022 of 61 (third quartile). Although the score declined slightly in 2022 as compared to 2021, it improved from the 2014 baseline. Management uses the results of the annual survey to design and implement strategies to positively influence organizational health. Initial employee participation of 66 percent in 2014 rose to and remains at approximately 90 percent in 2019-2022.
Entergy believes that creating a culture of diversity, inclusion, and belonging drives foundational engagement. Entergy is committed to developing and retaining a workforce that reflects the rich diversity of the communities it serves. In 2019, Entergy embarked on a three-year phased approach to enhance inclusion for individuals and teams. In 2022, Entergy continued to focus its actions to engage a diverse workforce, infusing DIB into hiring policies, practices and procedures, aligning Employee Resource Group goals to DIB goals, growing its DIB Champion network, integrating DIB into Entergy’s leadership development programs, and facilitating training from the executive leadership ranks down to the frontline. Through these efforts, Entergy aspires to create greater understanding and accountability regarding the behaviors and outcomes that are indicative of a premier utility.
Talent Management
Entergy’s focus on talent management is organized in three areas: developing and attracting a diverse pool of talent, equipping its leaders to develop the organization, and building premier utility capability through employee performance management and succession programs. Entergy believes that developing a diverse pool of local talent equipped with the skills needed, today and in the future, and reflecting the communities Entergy serves will give it a long-term competitive advantage. The focus of Entergy’s leadership development programs is to equip managers with the skills needed to effectively develop their teams and improve the leader-employee relationship. Entergy’s talent development infrastructure, which includes a combination of business function-specific and enterprise-wide learning and development programs, is designed to ensure Entergy has qualified staff with the skills, experiences, and behaviors needed to perform today and prepare for the future. Entergy strives to achieve its strategic priorities by aligning and enhancing team and individual performance with business objectives, effectively deploying talent through succession planning, and managing workforce transitions.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Availability of SEC filings and other information on Entergy’s website
Entergy electronically files reports with the SEC, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxies, and amendments to such reports. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding registrants that file electronically with the SEC at http://www.sec.gov. Copies of the reports that Entergy files with the SEC can be obtained at the SEC’s website.
Entergy uses its website, http://www.entergy.com, as a routine channel for distribution of important information, including news releases, analyst presentations and financial information. Filings made with the SEC are posted and available without charge on Entergy’s website as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. These filings include annual and quarterly reports on Forms 10-K and 10-Q and current reports on Form 8-K (including related filings in XBRL format); proxy statements; and any amendments to those reports or statements. All such postings and filings are available on Entergy’s Investor Relations website free of charge. Entergy is providing the address to its internet site solely for the information of investors and does not intend the address to be an active link. The contents of the website are not incorporated into this report.
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
Item 1A. RISK FACTORS
See “RISK FACTORS SUMMARY” in Part I Item 1 for a summary of Entergy’s and the Registrant Subsidiaries’ risk factors.
Investors should review carefully the following risk factors and the other information in this Form 10-K. The risks that Entergy faces are not limited to those in this section. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely affect Entergy’s financial condition, results of operations, and liquidity. See “FORWARD-LOOKING INFORMATION.”
Utility Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The terms and conditions of service, including electric and gas rates, of the Utility operating companies and System Energy are determined through regulatory approval proceedings that can be lengthy and subject to appeal, potentially resulting in delays in effecting rate changes, lengthy litigation, the risk of disallowance of recovery of certain costs, and uncertainty as to ultimate results.
The Utility operating companies are regulated on a cost-of-service and rate of return basis and are subject to statutes and regulatory commission rules and procedures. The rates that the Utility operating companies and System Energy charge reflect their capital expenditures, operations and maintenance costs, allowed rates of return, financing costs, and related costs of service. These rates significantly influence the financial condition, results of operations, and liquidity of Entergy and each of the Utility operating companies and System Energy. These rates are determined in regulatory proceedings and are subject to periodic regulatory review and adjustment, including adjustment upon the initiative of a regulator or, in some cases, affected stakeholders. Regulators in a future rate proceeding may alter the timing or amount of certain costs for which recovery is allowed or modify the current authorized rate of return. Rate refunds may also be required, subject to applicable law.
In addition, regulators have initiated and may initiate additional proceedings to investigate the prudence of costs in the Utility operating companies’ and System Energy’s base rates and examine, among other things, the reasonableness or prudence of the companies’ operation and maintenance practices, level of expenditures (including storm costs and costs associated with capital projects), allowed rates of return and rate base, proposed resource acquisitions, and previously incurred capital expenditures that the operating companies seek to place in rates. The regulators may disallow costs subject to their jurisdiction found not to have been prudently incurred or found not to have been incurred in compliance with applicable tariffs, creating some risk to the ultimate recovery of those costs. Regulatory proceedings relating to rates and other matters typically involve multiple parties seeking to limit or reduce rates. Traditional base rate proceedings, as opposed to formula rate plans, generally have long timelines, are primarily based on historical costs, and may or may not be limited in scope or duration by statute. The length of these base rate proceedings can cause the Utility operating companies and System Energy to experience regulatory lag in recovering costs through rates, such that the Utility operating companies may not fully recover all costs during the rate effective period and may, therefore, earn less than their allowed returns. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with rate case proceedings. For a discussion of such appeals and related litigation for both the Utility operating companies and System Energy, see Note 2 to the financial statements.
The Utility operating companies have large customer and stakeholder bases and, as a result, could be the subject of public criticism or adverse publicity focused on issues including the operation and maintenance of their assets and infrastructure, their preparedness for major storms or other extreme weather events and/or the time it takes to restore service after such events, or the quality of their service or the reasonableness of the cost of their
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service. Criticism or adverse publicity of this nature could render legislatures and other governing bodies, public service commissions and other regulatory authorities, and government officials less likely to view the applicable operating company in a favorable light and could potentially negatively affect legislative or regulatory processes or outcomes, as well as lead to increased regulatory oversight or more stringent legislative or regulatory requirements or other legislation or regulatory actions that adversely affect the Utility operating companies.
The Utility operating companies and System Energy, and the energy industry as a whole, have experienced a period of rising costs and investments and an upward trend in spending, especially with respect to infrastructure investments, which is likely to continue in the foreseeable future and could result in more frequent rate cases and requests for, and the continuation of, cost recovery mechanisms, all of which could face resistance from customers and other stakeholders especially in a rising cost environment, whether due to inflation or high fuel prices or otherwise, and/or in periods of economic decline or hardship. Significant increases in costs could increase financing needs and otherwise adversely affect Entergy, the Utility operating companies, and System Energy’s business, financial position, results of operation, or cash flows. For information regarding rate case proceedings and formula rate plans applicable to the Utility operating companies, see Note 2 to the financial statements.
Changes to state or federal legislation or regulation affecting electric generation, electric and natural gas transmission, distribution, and related activities could adversely affect Entergy and the Utility operating companies’ financial position, results of operations, or cash flows and their utility businesses.
If legislative and regulatory structures evolve in a manner that erodes the Utility operating companies’ exclusive rights to serve their regulated customers, they could lose customers and sales and their results of operations, financial position, or cash flows could be materially affected. Additionally, technological advances in energy efficiency and distributed energy resources are reducing the costs of these technologies and, together with ongoing state and federal subsidies, the increasing penetration of these technologies could result in reduced sales by the Utility operating companies. Such loss of sales, due to the methodology used to determine cost of service rates or otherwise, could put upward pressure on rates, possibly resulting in adverse regulatory actions to mitigate such effects on rates. Further, the failure of regulatory structures to evolve to accommodate the changing needs and desires of customers with respect to the sourcing and use of electricity also could diminish sales by the operating companies. Entergy and the Utility operating companies cannot predict if or when they may be subject to changes in legislation or regulation, or the extent and timing of reductions of the cost of distributed energy resources, nor can they predict the impact of these changes on their results of operations, financial position, or cash flows.
The Utility operating companies recover fuel, purchased power, and associated costs through rate mechanisms that are subject to risks of delay or disallowance in regulatory proceedings, and sudden or prolonged increases in fuel and purchased power costs could lead to increased customer arrearages or bad debt expenses.
The Utility operating companies recover their fuel, purchased power, and associated costs from their customers through rate mechanisms subject to periodic regulatory review and adjustment. Because regulatory review can result in the disallowance of incurred costs found not to have been prudently incurred or not reflected in rates as permitted by approved rate schedules and accounting rules, including the cost of replacement power purchased when generators experience outages or when planned outages are extended, with the possibility of refunds to ratepayers, there exists some risk to the ultimate recovery of those costs, particularly when there are substantial or sudden increases in such costs. Regulators also may initiate proceedings to investigate the continued usage or the adequacy and operation of the fuel and purchased power recovery clauses of the Utility operating companies and, therefore, there can be no assurance that existing recovery mechanisms will remain unchanged or in effect at all.
The Utility operating companies’ cash flows can be negatively affected by the time delays between when gas, power, or other commodities are purchased and the ultimate recovery from customers of the costs in rates. On occasion, when the level of incurred costs for fuel and purchased power rises very dramatically, some
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of the Utility operating companies may agree to defer recovery of a portion of that period’s fuel and purchased power costs for recovery at a later date, which could increase the near-term working capital and borrowing requirements of those companies. The Utility operating companies also may experience, and in some instances have experienced, an increase in customer bill arrearages and bad debt expenses due to, among other reasons, increases in fuel and purchased power costs, especially in periods of economic decline or hardship. For a description of fuel and purchased power recovery mechanisms and information regarding the regulatory proceedings for fuel and purchased power cost recovery, see Note 2 to the financial statements.
The Utility operating companies are subject to economic risks associated with participation in the MISO markets and the allocation of transmission upgrade costs. The operation of the Utility operating companies’ transmission system pursuant to the MISO RTO tariff and their participation in the MISO RTO’s wholesale markets may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
On December 19, 2013, the Utility operating companies integrated into the MISO RTO. MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their owned and controlled generating facilities into the MISO resource adequacy construct (the annual Planning Resource Auction, discussed below), as well as the day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. The Utility operating companies are subject to economic risks associated with participation in the MISO markets and resource adequacy construct. MISO tariff rules and system conditions, including transmission congestion, could affect the Utility operating companies’ ability to sell capacity, energy, and/or ancillary services in certain regions and/or the economic value of such sales, or the cost of serving the Utility operating companies’ respective loads. MISO market rules may change or be interpreted in ways that cause additional cost and risk, including compliance risk.
The Utility operating companies participate in the MISO regional transmission planning process and are subject to risks associated with planning decisions that MISO makes in the exercise of control over the planning of the Utility operating companies’ transmission assets that are under MISO’s functional control. The Utility operating companies pay transmission rates that reflect the cost of transmission projects that the Utility operating companies do not own, which could increase cash or financing needs. Further, FERC policies and regulation addressing cost responsibility for transmission projects, including transmission projects to interconnect new generation facilities, may potentially give rise to cash and financing-related risks as well as result in upward pressure on the retail rates of the Utility operating companies, which, in turn, may result in adverse actions by the Utility operating companies’ retail regulators. In addition to the cash and financing-related risks arising from the potential additional cost allocation to the Utility operating companies from transmission projects of others or changes in FERC policies or regulation related to cost responsibility for transmission projects, there is a risk that the Utility operating companies’ business and financial position could be harmed as a result of lost investment opportunities and other effects that flow from an increased number of competitive projects being approved and constructed that are interconnected with their transmission systems.
Further, the terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets, the allocation of transmission upgrade costs, the MISO-wide allowed base rate of return on equity, and any required MISO-related charges and credits are subject to regulation by the FERC. The operation of the Utility operating companies’ transmission system pursuant to the MISO tariff and their participation in the MISO wholesale markets, and the resulting costs, may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
Moreover, the resource adequacy construct provided under the MISO tariff confers certain rights and imposes certain obligations upon load-serving entities, including the Utility operating companies, that are served
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from the transmission systems subject to MISO’s functional control, including the transmission facilities of the Utility operating companies. The MISO tariff provisions governing these rights and obligations are subject to change and have recently undergone significant changes, some of which are the subject of pending litigation and/or appeals. Due to their magnitude and the speed with which they have been implemented, these changes carry risk, including compliance risk, and may result in material additional costs being passed through to the Utility operating companies’ customers in retail rates, including but not limited to additional capacity costs incurred in the annual MISO Planning Resource Auction. Also, by virtue of the Utility operating companies’ participation in MISO and the design and terms of the MISO resource adequacy construct, other load-serving entities served by the Utility operating companies’ transmission assets, which are under MISO’s functional control, may be able to circumvent reasonable resource planning obligations and avoid, in whole or in part, the full cost of procuring the resources reasonably needed to reliably supply their respective loads. In particular, the design of the current MISO resource adequacy construct and the absence of a minimum capacity obligation in MISO create a risk of other load-serving entities engaging in “free ridership” through their strategy for participation in the MISO resource adequacy construct and energy and ancillary services markets – specifically, by using energy and ancillary services available from the Utility operating companies’ owned and controlled generating units without paying a reasonable share of the cost of the capacity required to provide such energy and ancillary services. As a result, there are a variety of risks to the Utility operating companies and their customers, including the risk of bearing additional costs for resources needed to ensure reliable service, the risk of reduced reliability and the enhanced risk of outages and lost sales which, because of the methodology for establishing cost of service rates, presents the risk of upward pressure on the Utility operating companies’ rates.
In addition, orders from each of the Utility operating companies’ respective retail regulators generally require that the Utility operating companies make periodic filings, or generally allow the retail regulator to direct the making of such filings, setting forth the results of analysis of the costs and benefits realized from MISO membership as well as the projected costs and benefits of continued membership in MISO and/or requesting approval of their continued membership in MISO. These filings have been submitted periodically by each of the Utility operating companies as required by their respective retail regulators, and the outcome of the resulting proceedings may affect the Utility operating companies’ continued membership in MISO.
The continued impacts of the COVID-19 pandemic and responsive measures taken on Entergy’s and its Utility operating companies’ business, results of operations, and financial condition are highly uncertain and cannot be predicted.
The global 2019 novel coronavirus pandemic continues to be an evolving situation and could lead to further disruption of the general economy, impacts on the customers of Entergy’s Utility operating companies, and disruption of the operations of Entergy’s subsidiaries, whether due to, among other things, the emergence or spread of new variants of COVID-19, precautionary or reactionary measures, market reactions or impacts, or supply chain constraints.
Entergy and its Utility operating companies experienced an increase in arrearages and bad debt expense due to non-payment by customers. The arrearages due to COVID-19 have begun to decline, although management cannot predict the timing of the completion of collections of such arrearages. While the Utility operating companies are working with regulators to ensure ultimate recovery for those and other COVID-19 related costs, the amount, method, and timing of such recovery is subject to approval by the retail regulators.
Entergy and its Registrant Subsidiaries also could experience, and in some cases have experienced, among other challenges that originated during or have been exacerbated by the COVID-19 pandemic: supply chain, vendor, and contractor disruptions, including shortages or delays in the availability of key components, parts, and supplies such as electronic components and solar panels; delays in completion of capital or other construction projects, maintenance, and other operations activities, including prolonged or delayed refueling and maintenance outages; delays in regulatory proceedings; workforce availability challenges, including from COVID-19 infections, health, or safety issues; increased storm recovery costs; increased cybersecurity risks as a result of many employees
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telecommuting; volatility in the credit or capital markets (and any related increased cost of capital or any inability to access the capital markets or draw on available credit facilities); or other adverse impacts on their ability to execute on business strategies and initiatives.
Although the economy has been recovering, another economic decline could adversely impact Entergy’s and the Utility operating companies’ liquidity and cash flows, including through declining sales, reduced revenues, delays in receipts of customer payments, or increased bad debt expense. The Utility operating companies also may experience regulatory outcomes that require them to postpone planned investment and otherwise reduce costs due to the impact of the COVID-19 pandemic on their customers, especially in an environment of higher inflation. In addition, if the COVID-19 pandemic or related impacts create additional disruptions or turmoil in the credit or financial markets, or adversely impact Entergy’s credit metrics or ratings, such developments could adversely affect its ability to access capital on favorable terms and continue to meet its liquidity needs or cause a decrease in the value of its defined benefit pension trust funds, as well as its nuclear decommissioning trust funds, all of which are highly uncertain and cannot be predicted.
Entergy cannot predict the extent or duration of the ongoing COVID-19 pandemic, the impact of new or existing variants of COVID-19, the effectiveness of mitigation efforts, further governmental responsive measures, or the extent of the effects or ultimate impacts on the global, national or local economy, the capital markets, or its customers, suppliers, operations, financial condition, results of operations, or cash flows.
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather, the impact on customer bills of permitted storm cost recovery, or the inability to securitize future storm restoration costs could have material effects on Entergy and its Utility operating companies.
Entergy’s and its Utility operating companies’ results of operations, liquidity, and financial condition can be materially affected by the destructive effects of severe weather. Severe weather can also result in significant outages for the customers of the Utility operating companies and, therefore, reduced revenues for the Utility operating companies during the period of the outages. A delay or failure in recovering amounts for storm restoration costs incurred, inability to securitize future storm restoration costs, or loss of revenues as a result of severe weather could have a material effect on Entergy and those Utility operating companies affected by severe weather, including lower credit ratings and, thus, higher costs for future debt issuances. The inability to recover losses either excluded by insurance or in excess of the insurance limits that can be secured economically also could have a material effect on Entergy and its Utility operating companies. In addition, the recovery of major storm restoration costs from customers could effectively limit our ability to make planned capital or other investments due to the impact of such storm cost recovery on customer bills, especially in a rising cost environment.
In August 2021, Hurricane Ida caused extensive damage to the Entergy distribution and, to a lesser extent, transmission systems across Louisiana, resulting in storm costs of $2.5 billion. Entergy Louisiana began recovering a portion of these costs through securitization financings in 2022. In January 2023 the LPSC issued orders finding prudent the costs incurred by Entergy Louisiana in responding to Hurricane Ida and allowing Entergy Louisiana to securitize the remaining $1.491 billion in such costs. Because such orders are not yet final and non-appealable (due to the forty-five day appeal period) and, further, because the bond rating and marketing process has yet to occur, there is an element of risk, and Entergy Louisiana is unable to predict with certainty the ultimate success of its recovery initiatives or the timing of such recovery.
Part I Item 1A and 1B
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Weather, economic conditions, technological developments, and other factors may have a material impact on electricity and gas sales and otherwise materially affect the Utility operating companies’ results of operations and system reliability.
Temperatures above normal levels in the summer tend to increase electric cooling demand and revenues, and temperatures below normal levels in the winter tend to increase electric and gas heating demand and revenues. As a corollary, mild temperatures in either season tend to decrease energy usage and resulting revenues. Higher consumption levels coupled with seasonal pricing differentials typically cause the Utility operating companies to report higher revenues in the third quarter of the fiscal year than in the other quarters. Changing weather patterns and extreme weather conditions, including hurricanes or tropical storms, flooding events, or ice storms, the frequency or intensity of which may be exacerbated by climate change, may stress the Utility operating companies’ generation facilities and transmission and distribution systems, resulting in increased maintenance and capital costs (and potential increased financing needs), limits on their ability to meet peak customer demand, increased regulatory oversight, criticism or adverse publicity, and reduced customer satisfaction. These extreme conditions could have a material effect on the Utility operating companies’ financial condition, results of operations, and liquidity.
Entergy’s electricity sales volumes are affected by a number of factors including weather and economic conditions, trends in energy efficiency, new technologies, and self-generation alternatives, including the willingness and ability of large industrial customers to develop co-generation facilities that greatly reduce their grid demand. In addition, changes to regulatory policies, such as those that allow customers to directly access the market to procure wholesale energy or those that incentivize development and utilization of new, developing, or alternative sources of generation, could, and in some instances, have reduced sales, and other non-traditional procurements, such as virtual purchase power agreements, could, and in some instances have limited growth opportunities or reduced sales at the Utility operating companies. Some of these factors are inherently cyclical or temporary in nature, such as the weather or economic conditions, and rarely have a long-lasting effect on Entergy’s operating results. Others, such as the organic turnover of appliances and lighting and their replacement with more efficient ones and adoption of newer technologies, including smart thermostats, new building codes, distributed energy resources, energy storage, demand side management, and rooftop solar, are having a more permanent effect by reducing sales growth rates from historical norms. As a result of these emerging efficiencies and technologies, the Utility operating companies may lose customers or experience lower average use per customer in the residential and commercial classes, and continuing advances have the potential to further limit sales or sales growth in the future.
The Utility operating companies also may face competition from other companies offering products and services to Entergy’s customers. Electricity sales to industrial customers, in particular, benefit from steady economic growth and favorable commodity markets; however, industrial sales are sensitive to changes in conditions in the markets in which its customers operate. Negative changes in any of these or other factors, particularly sustained economic downturns or sluggishness, have the potential to result in slower sales growth or sales declines and increased bad debt expense, which could materially affect Entergy’s and the Utility operating companies’ results of operations, financial condition, and liquidity. The Utility operating companies also may not realize anticipated or expected growth in industrial sales from electrification opportunities to help such customers achieve their environmental and sustainability goals. This could occur because of changes in customers’ goals or business priorities, competition from other companies, or decisions by such customers to seek to achieve such goals through methods not offered by Entergy.
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Nuclear Operating, Shutdown, and Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)
Certain of the Utility operating companies and System Energy are expected to consistently operate their nuclear power plants at high capacity factors in order to be successful, and lower capacity factors could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Nuclear capacity factors significantly affect the results of operations of certain Utility operating companies and System Energy. Nuclear plant operations involve substantial fixed operating costs. Consequently, there is pressure on plant owners to operate nuclear power plants at higher capacity factors, though such operations always must be consistent with safety, reliability, and nuclear regulatory requirements. For the Utility operating companies that own nuclear plants, lower nuclear plant capacity factors can increase production costs by requiring the affected companies to generate additional energy, sometimes at higher costs, from their owned or contractually controlled facilities or purchase additional energy in the spot or forward markets in order to satisfy their supply needs.
Certain of the Utility operating companies and System Energy periodically shut down their nuclear power plants to replenish fuel. Plant maintenance and upgrades are often scheduled during such refueling outages. If refueling outages last longer than anticipated or if unplanned outages arise, Entergy’s and their results of operations, financial condition, and liquidity could be materially affected.
Outages at nuclear power plants to replenish fuel require the plant to be “turned off.” Refueling outages generally are planned to occur once every 18 to 24 months. Plant maintenance and upgrades are often scheduled during such planned outages, which may extend the planned outage duration beyond that required for only refueling activities. When refueling outages last longer than anticipated or a plant experiences unplanned outages, capacity factors decrease, and maintenance costs may increase.
Certain of the Utility operating companies and System Energy face risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication). These risks could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Based upon currently planned fuel cycles, Entergy’s nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable prices through most of 2027. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners. While there are a number of possible alternate suppliers that may be accessed to mitigate any supplier performance failure, the pricing of any such alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S. Market prices for nuclear fuel have been extremely volatile from time to time in the past and may be subject to increased volatility due to the imposition of tariffs, domestic purchase requirements or limitations on importation of uranium or uranium products from foreign countries, geopolitical conditions, or shifting trade arrangements between countries. Although Entergy’s nuclear fuel contract portfolio provides a degree of hedging against market risks for several years, costs for nuclear fuel in the future cannot be predicted with certainty due to normal inherent market uncertainties, and price changes could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.
Entergy’s ability to assure nuclear fuel supply also depends upon the performance and reliability of conversion, enrichment, and fabrication services providers. These service providers are fewer in number than uranium suppliers. For conversion and enrichment services, Entergy diversifies its supply by supplier and country and may take special measures to ensure a reliable supply of enriched uranium for fabrication into nuclear fuel. For fabrication services, each plant is dependent upon the performance of the fabricator of that plant’s nuclear fuel;
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therefore, Entergy relies upon additional monitoring, inspection, and oversight of the fabrication process to assure reliability and quality of its nuclear fuel. Certain of the suppliers and service providers are located in or dependent upon foreign countries, such as Russia, and international sanctions or tariffs impacting trade with such countries could further restrict the ability of such suppliers or service providers to continue to supply fuel or provide such services at acceptable prices or at all. The inability of such suppliers or service providers to perform such obligations could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.
Certain of the Utility operating companies and System Energy face the risk that the NRC will change or modify its regulations, suspend or revoke their licenses, or increase oversight of their nuclear plants, which could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Under the Atomic Energy Act and Energy Reorganization Act, the NRC regulates the operation of nuclear power plants. The NRC may modify, suspend, or revoke licenses, shut down a nuclear facility and impose civil penalties for failure to comply with the Atomic Energy Act, related regulations, or the terms of the licenses for nuclear facilities. Interested parties may also intervene which could result in prolonged proceedings. A change in the Atomic Energy Act, other applicable statutes, or the applicable regulations or licenses, or the NRC’s interpretation thereof, may require a substantial increase in capital expenditures or may result in increased operating or decommissioning costs and could materially affect the results of operations, liquidity, or financial condition of Entergy, certain of the Utility operating companies, or System Energy. A change in the classification of a plant owned by one of these companies under the NRC’s Reactor Oversight Process, which is the NRC’s program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response, also could cause the owner of the plant to incur material additional costs as a result of the increased oversight activity and potential response costs associated with the change in classification. For additional information concerning the current classification of the plants owned by Entergy Arkansas, Entergy Louisiana, and System Energy, see “Regulation of Entergy’s Business- Regulation of the Nuclear Power Industry - NRC Reactor Oversight Process” in Part I, Item 1.
Events at nuclear plants owned by one of these companies, as well as those owned by others, may lead to a change in laws or regulations or the terms of the applicable licenses, or the NRC’s interpretation thereof, or may cause the NRC to increase oversight activity or initiate actions to modify, suspend, or revoke licenses, shut down a nuclear facility, or impose civil penalties. As a result, if an incident were to occur at any nuclear generating unit, whether an Entergy nuclear generating unit or not, it could materially affect the financial condition, results of operations, and liquidity of Entergy, certain of the Utility operating companies, or System Energy.
Certain of the Utility operating companies and System Energy are exposed to risks and costs related to operating and maintaining their nuclear power plants, and their failure to maintain operational efficiency at their nuclear power plants could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
The nuclear generating units owned by certain of the Utility operating companies and System Energy began commercial operations in the 1970s-1980s. Older equipment may require more capital expenditures to keep each of these nuclear power plants operating safely and efficiently. This equipment is also likely to require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages, or any unanticipated capital expenditures, could result in increased costs, some of which costs may not be fully recoverable by these Utility operating companies and System Energy in regulatory proceedings should there be a determination of imprudence. Operations at any of the nuclear generating units owned and operated by Entergy’s subsidiaries could degrade to the point where the affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. A decision may be made to close a unit rather than incur the expense of restarting it or returning the unit to full capacity. For these Utility operating companies and System Energy, this could result in certain costs being stranded
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and potentially not fully recoverable in regulatory proceedings. In addition, the operation and maintenance of Entergy’s nuclear facilities require the commitment of substantial human resources that can result in increased costs.
Moreover, Entergy is becoming more dependent on fewer suppliers for key parts of Entergy’s nuclear power plants that may need to be replaced or refurbished, and in some cases, parts are no longer available and have to be reverse-engineered for replacement. In addition, certain major parts have long lead-times to manufacture if an unplanned replacement is needed. This dependence on a reduced number of suppliers and long lead-times on certain major parts for unplanned replacements could result in delays in obtaining qualified replacement parts and, therefore, greater expense for Entergy, certain of the Utility operating companies, and System Energy.
The costs associated with the storage of the spent nuclear fuel of certain of the Utility operating companies and System Energy, as well as the costs of and their ability to fully decommission their nuclear power plants, could be significantly affected by the timing of the opening of a spent nuclear fuel disposal facility, as well as interim storage and transportation requirements.
Certain of the Utility operating companies and System Energy incur costs for the on-site storage of spent nuclear fuel. The approval of a license for a national repository for the disposal of spent nuclear fuel, such as the one proposed for Yucca Mountain, Nevada, or any interim storage facility, and the timing of such facility opening, will significantly affect the costs associated with on-site storage of spent nuclear fuel. For example, while the DOE is required by law to proceed with the licensing of Yucca Mountain and, after the license is granted by the NRC, to construct the repository and commence the receipt of spent fuel, the NRC licensing of the Yucca Mountain repository is effectively at a standstill. These actions are prolonging the time before spent fuel is removed from Entergy’s plant sites. Because the DOE has not accomplished its objectives, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts, and Entergy has sued the DOE for such breach. Furthermore, Entergy is uncertain as to when the DOE will commence acceptance of spent fuel from its facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at the companies’ nuclear sites and maintenance costs on existing storage facilities, including aging management of fuel storage casks, may increase. The costs of on-site storage are also affected by regulatory requirements for such storage. In addition, the availability of a repository or other off-site storage facility for spent nuclear fuel may affect the ability to fully decommission the nuclear units and the costs relating to decommissioning. For further information regarding spent fuel storage, see the “Critical Accounting Estimates – Nuclear Decommissioning Costs – Spent Fuel Disposal” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy and Note 8 to the financial statements.
Certain of the Utility operating companies and System Energy may be required to pay substantial retrospective premiums imposed under the Price-Anderson Act and/or by Nuclear Electric Insurance Limited (NEIL) in the event of a nuclear incident, and losses not covered by insurance could have a material effect on Entergy’s and their results of operations, financial condition, or liquidity.
Accidents and other unforeseen problems at nuclear power plants have occurred both in the United States and elsewhere. As required by the Price-Anderson Act, the Utility operating companies and System Energy carry the maximum available amount of primary nuclear off-site liability insurance with American Nuclear Insurers, which is $450 million for each operating site. Claims for any nuclear incident exceeding that amount are covered under Secondary Financial Protection. The Price-Anderson Act limits each reactor owner’s public liability (off-site) for a single nuclear incident to the payment of retrospective premiums into a secondary insurance pool, which is referred to as Secondary Financial Protection, up to approximately $137.6 million per reactor. With 96 reactors currently participating, this translates to a total public liability cap of approximately $13 billion per incident. The limit is subject to change to account for the effects of inflation, a change in the primary limit of insurance coverage, and changes in the number of licensed reactors. As a result, in the event of a nuclear incident that causes damages (off-site) in excess of the primary insurance coverage, each owner of a nuclear plant reactor, including Entergy’s Utility operating companies and System Energy, regardless of fault or proximity to the incident, will be required to
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pay a retrospective premium, equal to its proportionate share of the loss in excess of the primary insurance level, up to a maximum of approximately $137.6 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $688 million). The retrospective premium payment is currently limited to approximately $21 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $137.6 million cap.
NEIL is a utility industry mutual insurance company, owned by its members, including the Utility operating companies and System Energy. NEIL provides onsite property and decontamination coverage. All member plants could be subject to an annual assessment (retrospective premium of up to 10 times current annual premium for all policies) should the NEIL surplus (reserve) be significantly depleted due toinsured losses. As of January 1, 2023, the maximum annual assessment amounts total approximately $70 million for the Utility plants. Retrospective premium insurance available through NEIL’s reinsurance treaty can cover the potential assessments.
As mentioned above, as an owner of nuclear power plants, Entergy participates in industry self-insurance programs and could be liable to fund claims should a plant owned by a different company experience a major event. Any resulting liability from a nuclear accident may exceed the applicable primary insurance coverage and require contribution of additional funds through the industry-wide program that could significantly affect the results of operations, financial condition, or liquidity of Entergy, certain of the Utility operating companies, or System Energy.
The decommissioning trust fund assets for the nuclear power plants owned by certain of the Utility operating companies and System Energy may not be adequate to meet decommissioning obligations if market performance and other changes decrease the value of assets in the decommissioning trusts, if one or more of Entergy’s nuclear power plants is retired earlier than the anticipated shutdown date, if the plants cost more to decommission than estimated, or if current regulatory requirements change, which then could require significant additional funding.
Owners of nuclear generating plants have an obligation to decommission those plants. Certain of the Utility operating companies and System Energy maintain decommissioning trust funds for this purpose. Certain of the Utility operating companies and System Energy collect funds from their customers, which are deposited into the trusts covering the units operated for or on behalf of those companies. Those rate collections, as adjusted from time to time by rate regulators, are generally based upon operating license lives and trust fund balances as well as estimated trust fund earnings and decommissioning costs. Assets in these trust funds are subject to market fluctuations, will yield uncertain returns that may fall below projected return rates, and may result in losses resulting from the recognition of impairments of the value of certain securities held in these trust funds.
Under NRC regulations, nuclear plant owners are permitted to project the NRC-required decommissioning amount, based on an NRC formula or a site-specific estimate, and the amount that will be available in each nuclear power plant’s decommissioning trusts combined with any other decommissioning financial assurances in place. The projections are made based on the operating license expiration date and the mid-point of the subsequent decommissioning process, or the anticipated actual completion of decommissioning if a site-specific estimate is used. If the projected amount of each individual plant’s decommissioning trusts exceeds the NRC-required decommissioning amount, then its NRC license termination decommissioning obligations are considered to be funded in accordance with NRC regulations. If the projected costs do not sufficiently reflect the actual costs required to decommission these nuclear power plants, or funding is otherwise inadequate, or if the formula, formula inputs, or site-specific estimate is changed to require increased funding, additional resources or commitments would be required. Furthermore, depending upon the level of funding available in the trust funds, the NRC may not permit the trust funds to be used to pay for related costs such as the management of spent nuclear fuel that are not included in the NRC’s formula. The NRC may also require a plan for the provision of separate funding for spent fuel management costs.
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Further, federal or state regulatory changes, including mandated increases in decommissioning funding or changes in the methods or standards for decommissioning operations, may also increase the funding requirements of, or accelerate the timing for funding of, the obligations related to the decommissioning of the nuclear generating plant owned by certain of the Utility operating companies or System Energy or may restrict the decommissioning-related costs that can be paid from the decommissioning trusts. Such changes also could result in the need for additional contributions to decommissioning trusts, or the posting of parent guarantees, letters of credit, or other surety mechanisms. As a result, under any of these circumstances, the results of operations, liquidity, and financial condition of Entergy, certain of the Utility operating companies, or System Energy could be materially affected.
An early plant shutdown (either generally or relative to current expectations), poor investment results, or higher than anticipated decommissioning costs (including as a result of changing regulatory requirements) could cause trust fund assets to be insufficient to meet the decommissioning obligations, with the result that certain of the Utility operating companies or System Energy may be required to provide significant additional funds or credit support to satisfy regulatory requirements for decommissioning, which, with respect to these Utility operating companies or System Energy, may not be recoverable from customers in a timely fashion or at all.
For further information regarding nuclear decommissioning costs, management’s decision to exit the merchant power business, and the impairment charges that resulted from such decision, see the “Critical Accounting Estimates- Nuclear Decommissioning Costs” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy, the “Entergy Wholesale Commodities Exit from the Merchant Power Business” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries, and Notes 9, 14, and 16 to the financial statements.
New or existing safety concerns regarding operating nuclear power plants and nuclear fuel could lead to restrictions upon the operation and decommissioning of Entergy’s nuclear power plants.
New and existing concerns are being expressed in public forums about the safety of nuclear generating units and nuclear fuel. These concerns have led to, and may continue to lead to, various proposals to federal regulators and governing bodies in some localities where Entergy’s subsidiaries own nuclear generating units for legislative and regulatory changes that might lead to the shutdown of nuclear units, additional requirements or restrictions related to spent nuclear fuel on-site storage and eventual disposal, or other adverse effects on owning, operating, and decommissioning nuclear generating units. Entergy vigorously responds to these concerns and proposals. If any of the existing proposals, or any proposals that may arise in the future with respect to legislative and regulatory changes, become effective, they could have a material effect on Entergy’s results of operations and financial condition.
General Business
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Entergy and its Registrant Subsidiaries depend on access to the capital markets and, at times, may face potential liquidity constraints, which could make it more difficult to handle future contingencies such as natural disasters or substantial increases in gas and fuel prices. Disruptions in the capital and credit markets may adversely affect Entergy’s and its subsidiaries’ ability to meet liquidity needs, access capital and operate and grow their businesses, and the cost of capital.
Entergy’s business is capital intensive and dependent upon its ability to access capital at reasonable rates and other terms. At times there are also spikes in the price for natural gas and other commodities that increase the liquidity requirements of the Utility operating companies. In addition, Entergy’s and the Registrant Subsidiaries’ liquidity needs could significantly increase in the event of a hurricane or other weather-related or unforeseen disaster similar to that experienced in Entergy’s service area with Hurricane Katrina and Hurricane Rita in 2005,
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Hurricane Gustav and Hurricane Ike in 2008, Hurricane Isaac in 2012, Hurricane Laura, Hurricane Delta, and Hurricane Zeta in 2020, and Winter Storm Uri and Hurricane Ida in 2021. The occurrence of one or more contingencies, including an adverse decision or a delay in regulatory recovery of fuel or purchased power costs or storm restoration costs, an acceleration of payments or decreased credit lines, less cash flow from operations than expected, changes in regulation or governmental policy (including tax and trade policy), or other unknown events, could cause the financing needs of Entergy and its subsidiaries to increase. In addition, accessing the debt capital markets more frequently in these situations may result in an increase in leverage. Material leverage increases could negatively affect the credit ratings of Entergy, the Utility operating companies, and System Energy, which in turn could negatively affect access to the capital markets.
The inability to raise capital on favorable terms, particularly during times of high interest rates, and uncertainty or reduced liquidity in the capital markets, could negatively affect Entergy and its subsidiaries’ ability to maintain and to expand their businesses. Access to capital markets could be restricted and/or borrowing costs could be increased due to certain sources of debt and equity capital being unwilling to invest in offerings to fund fossil fuel projects or companies that are impacted by extreme weather events, that rely on fossil fuels, or that are impacted by risks related to climate change. Factors beyond Entergy’s control may create uncertainty that could increase its cost of capital or impair its ability to access the capital markets, including the ability to draw on its bank credit facilities. These factors include depressed economic conditions, a recession, increasing interest rates, inflation, sanctions, trade restrictions, political instability, war, terrorism, and extreme volatility in the debt, equity, or credit markets. Entergy and its subsidiaries are unable to predict the degree of success they will have in renewing or replacing their credit facilities as they come up for renewal. Moreover, the size, terms, and covenants of any new credit facilities may not be comparable to, and may be more restrictive than, existing facilities. If Entergy and its subsidiaries are unable to access the credit and capital markets on terms that are reasonable, they may have to delay raising capital, issue shorter-term securities, and/or bear an unfavorable cost of capital, which, in turn, could impact their ability to grow their businesses, decrease earnings, significantly reduce financial flexibility, and/or limit Entergy Corporation’s ability to sustain its current common stock dividend level.
A downgrade in Entergy’s or its Registrant Subsidiaries’ credit ratings could negatively affect Entergy’s and its Registrant Subsidiaries’ ability to access capital or the cost of such capital and/or could require Entergy or its subsidiaries to post collateral, accelerate certain payments, or repay certain indebtedness.
There are a number of factors that rating agencies evaluate to arrive at credit ratings for each of Entergy and the Registrant Subsidiaries, including each Registrant Subsidiary’s regulatory framework, ability to recover costs and earn returns, storm risk exposure, diversification, and financial strength and liquidity. If one or more rating agencies downgrade Entergy’s or any of the Registrant Subsidiaries’ ratings, particularly below investment grade, borrowing costs would increase, the potential pool of investors and funding sources would likely decrease, and cash or letter of credit collateral demands may be triggered by the terms of a number of commodity contracts, leases, and other agreements.
Most of Entergy’s and its subsidiaries’ suppliers and counterparties require sufficient creditworthiness to enter into transactions. If Entergy’s or the Registrant Subsidiaries’ ratings decline, particularly below investment grade, or if certain counterparties believe Entergy or the Utility operating companies are losing creditworthiness and demand adequate assurance under fuel, gas, and purchased power contracts, the counterparties may require posting of collateral in cash or letters of credit, prepayment for fuel, gas or purchased power or accelerated payment, or counterparties may decline business with Entergy or its subsidiaries.
Entergy or its Registrant Subsidiaries may be materially adversely affected by negative publicity or the inability to meet its stated goals or commitments, among other potential causes.
As with any company, Entergy’s and its Registrant Subsidiaries’ reputations are an important element of their ability to effectively conduct their business. Entergy’s and its Registrant Subsidiaries’ reputations could be harmed by a variety of factors, including: failure of a generating asset or supporting infrastructure; failure to restore
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power after a hurricane or other severe weather event in a manner perceived as timely by regulators or customers; the incurrence of storm restoration costs perceived as excessive by regulators or customers; failure to effectively manage land and other natural resources; real or perceived violations of environmental regulations, including those related to climate change; real or perceived issues with Entergy’s safety culture or work environment; inability to meet their climate or human capital strategy goals; inability to keep their electricity rates stable; involvement in a class-action or other high-profile lawsuit; significant delays in construction projects; occurrence of or responses to cyber attacks or security vulnerabilities; acts or omissions of Entergy management or acts or omissions of a contractor or other third-party working with or for Entergy or its Registrant Subsidiaries, which actually or perceivably reflect negatively on Entergy or its Registrant Subsidiaries; measures taken to offset reductions in demand or to supply rising demand; a significant dispute with one of Entergy’s or its Registrant Subsidiaries’ customers or other stakeholders; or negative political and public sentiment resulting in a significant amount of adverse press coverage and other adverse statements affecting Entergy or its Registrant Subsidiaries.
Addressing any adverse publicity or regulatory scrutiny is time consuming and expensive and, regardless of the factual basis for the assertions being made (or lack thereof), can have a negative impact on the reputations of Entergy or its Registrant Subsidiaries, on the morale and performance of their employees, and on their relationships with their respective regulators, customers, and commercial counterparties. Adverse publicity or regulatory scrutiny may also have a negative impact on Entergy or its Registrant Subsidiaries’ ability to take timely advantage of various business or market opportunities.
Deterioration in Entergy’s or its Registrant Subsidiaries’ reputations may harm Entergy’s or its Registrant Subsidiaries’ relationships with their customers, regulators, and other stakeholders, may increase their cost of doing business, may interfere with its ability to attract and retain a qualified, inclusive, and diverse workforce, may impact Entergy’s or its Registrant Subsidiaries’ ability to raise debt capital, and may potentially lead to the enactment of new laws and regulations, or the modification of existing laws and regulations, that negatively affect the way Entergy or its Registrant Subsidiaries conduct their business, or may have a material adverse effect on their financial condition and results of operations.
Recent U.S. tax legislation may materially adversely affect Entergy’s financial condition, results of operations, and cash flows.
The Tax Cuts and Jobs Act of 2017 and CARES Act of 2020 significantly changed the U.S. Internal Revenue Code, including taxation of U.S. corporations, by, among other things, reducing the federal corporate income tax rate, limiting interest deductions, and altering the expensing of capital expenditures. The Inflation Reduction Act of 2022 further significantly changed the U.S. Internal Revenue Code by, among other things, enacting a new corporate alternative minimum tax and expanding federal tax credits for clean energy production. The interpretive guidance issued by the IRS and state tax authorities may be inconsistent with Entergy’s own interpretation and the legislation could be subject to amendments, which could lessen or increase certain impacts of the legislation. Further, changes in tax legislation or guidance, or uncertainties regarding interpretation of such tax legislation or guidance, could impact interpretation of and negotiations around certain contractual arrangements with counterparties, which could result in unfavorable changes to such arrangements or delays. In addition, the retail regulatory treatment of the expanded tax credits and corporate alternative minimum tax included in the Inflation Reduction Act of 2022 could materially impact Entergy’s future cash flows, and this legislation could result in unintended consequences not yet identified that could have a material adverse impact on Entergy’s financial results and future cash flows.
Based on initial IRS guidance and current internal forecasts, Entergy and the Registrant Subsidiaries may become subject to the corporate alternative minimum tax included in the Inflation Reduction Act of 2022 beginning in the next two to three years.
The tax rate decrease included in the Tax Cuts and Jobs Act required Entergy to record a regulatory liability for income taxes payable to customers. Such regulatory liability for income taxes is described in Note 3 to the
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financial statements. Depending on the outcome of IRS examinations or tax positions and elections that Entergy may make, Entergy and the Registrant Subsidiaries may be required to record additional charges or credits to income tax expense.
See Note 3 to the financial statements for discussion of the effects of the Tax Cuts and Jobs Act on 2022, 2021, and 2020 results of operations and financial condition, the provisions of the Tax Cuts and Jobs Act, and the uncertainties associated with accounting for the Tax Cuts and Jobs Act, and Note 2 to the financial statements for discussion of the regulatory proceedings that have considered the effects of the Tax Cuts and Jobs Act. For further discussion of the effects of the Inflation Reduction Act of 2022, see the “Income Tax Legislation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 3 to the financial statements.
Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy’s and the Registrant Subsidiaries’ results of operations, financial condition, and liquidity.
Entergy and its subsidiaries make judgments regarding the potential tax effects of various transactions and results of operations to estimate their obligations to taxing authorities. These tax obligations include income, franchise, real estate, sales and use, and employment-related taxes. These judgments include provisions for potential adverse outcomes regarding tax positions that have been taken. Entergy and its subsidiaries also estimate their ability to utilize tax benefits, including those in the form of carryforwards for which the benefits have already been reflected in the financial statements. Changes in federal, state, or local tax laws or interpretive guidance relating thereto, adverse tax audit results or adverse tax rulings on positions taken by Entergy and its subsidiaries could negatively affect Entergy’s and the Registrant Subsidiaries’ results of operations, financial condition, and liquidity. The intended and unintended consequences of recently enacted legislation could have a material adverse impact on Entergy’s financial results and future cash flows. For further information regarding Entergy’s income taxes, see Note 3 to the financial statements.
Entergy and its subsidiaries’ ability to successfully execute on their business strategies, including their ability to complete strategic transactions, is subject to significant risks, and, as a result, they may be unable to achieve some or all of the anticipated results of such strategies, which could materially affect their future prospects, results of operations, and benefits that they anticipate from such transactions.
Entergy and its subsidiaries’ future prospects and results of operations significantly depend on their ability to successfully implement their business strategies, including achieving Entergy’s climate goals and commitments, which are subject to business, regulatory, economic, and other risks and uncertainties, many of which are beyond their control. As a result, Entergy and its subsidiaries may be unable to fully achieve the anticipated results of such strategies.
Additionally, Entergy and its subsidiaries have pursued and may continue to pursue strategic transactions including merger, acquisition, divestiture, joint venture, restructuring, or other strategic transactions. For example, a significant portion of Entergy’s utility business plan over the next several years includes the construction and/or purchase of a variety of solar facilities. These or other transactions and plans are or may become subject to regulatory approval and other material conditions or contingencies, including increased costs or delays resulting from supply chain issues. The failure to complete these transactions or plans or any future strategic transaction successfully or on a timely basis could have an adverse effect on Entergy’s or its subsidiaries’ financial condition or results of operations and the market’s perception of Entergy’s ability to execute its strategy. Further, these transactions, and any completed or future strategic transactions, involve substantial risks, including the following:
•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;
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•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 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, 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.
Entergy and its subsidiaries may not be successful in managing these or any other significant risks that they may encounter in acquiring or divesting a business, or engaging in other strategic transactions, which could have a material effect on their business, financial condition, or results of operations.
The completion of capital projects, including the construction of power generation facilities, and other capital improvements, involve substantial risks. Should such efforts be unsuccessful, the financial condition, results of operations, or liquidity of Entergy and the Utility operating companies could be materially affected.
Entergy’s and the Utility operating companies’ ability to complete capital projects, including the construction of power generation facilities, or make other capital improvements, such as transmission and distribution infrastructure replacements or upgrades, in a timely manner and within budget is contingent upon many variables and subject to substantial risks. These variables include, but are not limited to, project management expertise, escalating costs for materials, labor, and environmental compliance, reliance on suppliers for timely and satisfactory performance, continued pandemic-related delays and cost increases, and supply chains and material constraints, including those that may result from major storm events, both within and outside of Entergy’s service area. Delays in obtaining permits, challenges in securing sufficient land for the siting of solar panels, shortages in materials and qualified labor, levels of public support or opposition, suppliers and contractors not performing as expected or required under their contracts and/or experiencing financial problems that inhibit their ability to fulfill their obligations under contracts, changes in the scope and timing of projects, poor quality initial cost estimates from contractors, the inability to raise capital on favorable terms, changes in commodity prices affecting revenue, fuel costs, or materials costs, downward changes in the economy, changes in law or regulation, including environmental compliance requirements, further direct and indirect trade and tariff issues, including those associated with imported solar panels, supply chain delays or disruptions, and other events beyond the control of the Utility operating companies may occur that may materially affect the schedule, cost, and performance of these projects. If these projects or other capital improvements are significantly delayed or become subject to cost overruns or cancellation, Entergy and the Utility operating companies could incur additional costs and termination payments or face increased risk of potential write-off of the investment in the project. In addition, the Utility operating companies could be exposed to higher costs and market volatility, which could affect cash flow and cost recovery, should their respective regulators decline to approve the construction of the project or new generation needed to meet the reliability needs of customers at the lowest reasonable cost.
For further information regarding capital expenditure plans and other uses of capital in connection with capital projects, including the potential construction and/or purchase of additional generation supply sources within the Utility operating companies’ service areas, see the “Capital Expenditure Plans and Other Uses of Capital” section of Management’s Financial Discussion and Analysis for Entergy and each of the Registrant Subsidiaries.
Failure to attract, retain and manage an appropriately qualified workforce could negatively affect Entergy or its subsidiaries’ results of operations.
Entergy relies on a large and changing workforce of team members, including employees, contractors, and temporary staffing. Certain factors, such as an aging workforce, mismatching of skill sets, failing to appropriately
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anticipate future workforce needs, workforce impacts from public health concerns such as the COVID-19 pandemic and responsive measures, challenges competing with other employers offering fully remote work options, rising salary and other labor costs, or the unavailability of contract resources, may lead to operating challenges and increased costs. The challenges include inability to attract or retain talent, lack of resources, loss of knowledge base, and the time required for skill development. In this case, costs, including costs for contractors to replace employees, productivity costs, and safety costs, may increase. Failure to hire and adequately train replacement employees, or the future availability and cost of contract labor, may adversely affect the ability to manage and operate the business, especially considering the workforce needs associated with nuclear generation facilities and new skills required to develop and operate a modernized, technology-enabled, and lower carbon power grid. If Entergy and its subsidiaries are unable to successfully attract, retain, and manage an appropriately qualified workforce, their results of operations, financial position, and cash flows could be negatively affected.
Entergy and Entergy’s subsidiaries, including the Utility operating companies and System Energy, may incur substantial costs to fulfill their obligations related to environmental and other matters.
The businesses in which Entergy’s subsidiaries, including the Utility operating companies and System Energy, operate are subject to extensive environmental regulation by local, state, and federal authorities. These laws and regulations affect the manner in which the Utility operating companies and System Energy conduct their operations and make capital expenditures. These laws and regulations also affect how Entergy’s subsidiaries, including the Utility operating companies and System Energy, manage air emissions, discharges to water, wetlands impacts, solid and hazardous waste storage and disposal, cooling and service water intake, the protection of threatened and endangered species, certain migratory birds and eagles, hazardous materials transportation, and similar matters. Federal, state, and local authorities continually revise these laws and regulations, and the laws and regulations are subject to judicial interpretation and to the permitting and enforcement discretion vested in the implementing agencies. Developing and implementing plans for facility compliance with these requirements can lead to capital, personnel, and operation and maintenance expenditures. Violations of these requirements can subject the Utility operating companies and System Energy to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, remediation and clean-up costs, civil penalties, and exposure to third parties’ claims for alleged health or property damages or for violations of applicable permits or standards. In addition, Entergy and its subsidiaries, including the Utility operating companies and System Energy, are subject to potential liability under these laws for the costs of remediation of environmental contamination of property now or formerly owned or operated by the Utility operating companies and System Energy and of property potentially contaminated by hazardous substances they generate. The Utility operating companies currently are involved in proceedings relating to sites where hazardous substances have been released and may be subject to additional proceedings in the future. Entergy’s subsidiaries, including the Utility operating companies and System Energy, have incurred and expect to incur significant costs related to environmental compliance.
Emissions of nitrogen and sulfur oxides, mercury, particulates, greenhouse gases, and other regulated emissions from generating plants potentially are subject to increased regulation, controls, and mitigation expenses. In addition, existing environmental regulations and programs promulgated by the EPA often are challenged legally, or are revised or withdrawn by the EPA, sometimes resulting in large-scale changes to anticipated regulatory regimes and the resulting need to shift course, both operationally and economically, depending on the nature of the changes. Risks relating to global climate change, initiatives to regulate, or otherwise compel reductions of greenhouse gas emissions, and water availability issues are discussed below.
Entergy and its subsidiaries may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals, or if Entergy and its subsidiaries fail to obtain, maintain, or comply with any such approval, the operation of its facilities could be stopped or become subject to additional costs. For further information regarding environmental regulation and environmental matters, including Entergy’s response to climate change, see the “Regulation of Entergy’s Business– Environmental Regulation” section of Part I, Item 1.
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The Utility operating companies, System Energy, and Entergy’s non-regulated operations may incur substantial costs related to reliability standards.
Entergy’s business is subject to extensive and mandatory reliability standards. Such standards, which are established by the NERC, the SERC, and other regional enforcement entities, are approved by the FERC and frequently are reviewed, amended, and supplemented. Failure to comply with such standards could result in the imposition of fines or civil penalties, and potential exposure to third party claims for alleged violations of such standards. The standards, as well as the laws and regulations that govern them, are subject to judicial interpretation and to the enforcement discretion vested in the implementing agencies. In addition to exposure to civil penalties and fines, the Utility operating companies have incurred and expect to incur significant costs related to compliance with new and existing reliability standards, including costs associated with the Utility operating companies’ transmission system and generation assets. In addition, the retail regulators of the Utility operating companies possess the jurisdiction, and in some cases have exercised such jurisdiction, to impose standards governing the reliable operation of the Utility operating companies’ distribution systems, including penalties if these standards are not met. The changes to the reliability standards applicable to the electric power industry are ongoing, and Entergy cannot predict the ultimate effect that the reliability standards will have on its Utility and Entergy’s non-regulated operations.
Environmental and regulatory obligations intended to combat the effects of climate change, including by compelling greenhouse gas emission reductions or reporting, increasing clean or renewable energy requirements, or placing a price on greenhouse gas emissions, or the achievement of voluntary climate commitments could materially affect the financial condition, results of operations, and liquidity of Entergy and Entergy’s subsidiaries, including the Utility operating companies and System Energy.
In an effort to address climate change concerns, some federal, state, and local authorities are calling for additional laws and regulations aimed at known or suspected causes of climate change. For example, the EPA, various environmental interest groups, and other organizations have focused considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. The EPA has promulgated regulations controlling greenhouse gas emissions from certain vehicles, and from new, existing, and significantly modified stationary sources of emissions, including electric generating units. Such regulations continue to evolve. As examples of state action, in the Northeast, the Regional Greenhouse Gas Initiative establishes a cap on CO2 emissions from electric power plants and requires generators to purchase emission permits to cover their CO2 emissions, and a similar program has been developed in California. In Louisiana, the Office of the Governor announced the creation of a Climate Initiatives Task Force and issued an executive order that established a path to net-zero emissions by 2050 while the City Council of New Orleans passed a renewable and clean portfolio standard that sets a goal of net-zero emissions by 2040 and absolute zero emissions by 2050. The impact that continued changes in the governmental response to climate change risk and any judicial interpretation thereof will have on existing and pending environmental laws and regulations related to greenhouse gas emissions currently is unclear.
Developing and implementing plans for compliance with greenhouse gas emissions reduction or reporting or clean/renewable energy requirements, or for achieving voluntary climate commitments can lead to additional capital, personnel, and operation and maintenance expenditures and could significantly affect the economic position of existing facilities and proposed projects. The operations of low or non-emitting generating units (such as nuclear units) at lower than expected capacity factors could require increased generation from higher emitting units, thus increasing Entergy’s greenhouse gas emission rate. Moreover, long-term planning to meet environmental requirements can be negatively impacted and costs may increase to the extent laws and regulations change prior to full implementation. These requirements could, in turn, lead to changes in the planning or operations of balancing authorities or organized markets in areas where Entergy’s subsidiaries, including the Utility operating companies or System Energy, do business. Violations of such requirements may subject the Utility operating companies to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, civil penalties, and exposure to third parties’ claims for alleged health
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
or property damages or for violations of applicable permits or standards. Further, real or perceived violations of environmental regulations, including those related to climate change, or inability to meet Entergy’s voluntary climate commitments, could adversely impact Entergy’s reputation or inhibit Entergy’s ability to pursue its decarbonization objectives. To the extent Entergy believes any of these costs are recoverable in rates, however, additional material rate increases for customers could be resisted by Entergy’s regulators and, in extreme cases, Entergy’s regulators might attempt to deny or defer timely recovery of these costs.
Future changes in regulation or policies governing the reporting or emission of CO2 and other greenhouse gases or mix of generation sources could (i) result in significant additional costs to Entergy’s Utility operating companies, their suppliers, or customers, (ii) make some of Entergy’s electric generating units uneconomical to maintain or operate, (iii) result in the early retirement of generation facilities and stranded costs if Entergy’s Utility operating companies are unable to fully recover the costs and investment in generation, and (iv) increase the difficulty that Entergy and its Utility operating companies have with obtaining or maintaining required environmental regulatory approvals, each of which could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries. In addition, lawsuits have occurred or are reasonably expected against emitters of greenhouse gases alleging that these companies are liable for personal injuries and property damage caused by climate change. These lawsuits may seek injunctive relief, monetary compensation, and punitive damages.
In March 2019, Entergy voluntarily set a climate goal to achieve a 50 percent reduction in its carbon emission rate from the year 2000 by 2030. In September 2020, Entergy voluntarily committed to achieving net zero carbon emissions by 2050. In November 2022, Entergy voluntarily set a climate goal to achieve 50 percent carbon-free energy capacity by 2030. Risks to achieving the 2030 and 2050 goals include, among other things, the ability to execute on renewable resource plans, regulatory approvals, customer demand for carbon-free energy, potential tariffs, carbon policy and regulation, and supply chain costs and constraints. Technology research and development, innovation, and advancements in carbon-free generation are also critical to Entergy’s ability to achieve its 2050 commitment. Entergy cannot predict the ultimate impact of achieving these objectives, or the various implementation aspects, on its system reliability, or its results of operations, financial condition, or liquidity.
The physical effects of climate change could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries.
Potential physical risks from climate change include an increase in sea level, wind and storm surge damages, more frequent or intense hurricanes and wildfires, wetland and barrier island erosion, flooding and changes in weather conditions (such as increases in precipitation, drought, or changes in average temperatures), and potential increased impacts of extreme weather conditions or storms. Entergy’s subsidiaries own assets in, and serve, communities that are at risk from sea level rise, changes in weather conditions, storms, and loss of the protection offered by coastal wetlands. A significant portion of the nation’s oil and gas infrastructure is located in these areas and susceptible to storm damage that could be aggravated by the physical impacts of climate change, which could give rise to fuel supply interruptions and price spikes. Entergy and its subsidiaries also face the risk that climate change could impact the availability and quality of water supplies necessary for operations.
These and other physical changes could result in changes in customer demand, increased costs associated with repairing and maintaining generation facilities and transmission and distribution systems resulting in increased maintenance and capital costs (and potential increased financing needs), limits on the Entergy system’s ability to meet peak customer demand, more frequent and longer lasting outages, increased regulatory oversight, criticism or adverse publicity, and lower customer satisfaction. Also, to the extent that climate change adversely impacts the economic health of a region or results in energy conservation or demand side management programs, it may adversely impact customer demand and revenues. Such physical or operational risks could have a material effect on Entergy’s and its subsidiaries’ financial condition, results of operations, and liquidity.
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
Due in part to the recent increase in frequency and intensity of major storm activity along the Gulf Coast, Entergy is developing plans to accelerate investments that would enhance the resilience of the electric systems of the Utility operating companies to enable them to better withstand major storms or other adverse weather events, to enable more rapid restoration of electricity after major storm or other adverse events, and to deliver electricity to critical customers more immediately after such events. The need for this investment and these expenditures could give rise to liquidity, capital or other financing-related risks as well as result in upward pressure on the retail rates of the Utility operating companies, which, particularly when combined with upward pressure resulting from the recovery of the costs of recent and future storms, may result in adverse actions by the Utility operating companies’ retail regulators or effectively limit the ability to make other planned capital or other investments.
Continued and future availability and quality of water for cooling, process, and sanitary uses could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries.
Water is a vital natural resource that is also critical to Entergy and its subsidiaries. Entergy’s and its subsidiaries’ facilities use water for cooling, boiler make-up, sanitary uses, potable supply, and many other uses. Entergy’s Utility operating companies also own and/or operate hydroelectric facilities. Accordingly, water availability and quality are critical to Entergy’s and its subsidiaries’ business operations. Impacts to water availability or quality could negatively impact both operations and revenues.
Entergy and its subsidiaries secure water through various mechanisms (ground water wells, surface waters intakes, municipal supply, etc.) and operate under the provisions and conditions set forth by the provider and/or regulatory authorities. Entergy and its subsidiaries also obtain and operate in substantial compliance with water discharge permits issued under various provisions of the Clean Water Act and/or state water pollution control provisions. Regulations and authorizations for both water intake and use and for waste discharge can become more stringent in times of water shortages, low flows in rivers, low lake levels, low groundwater aquifer volumes, and similar conditions. The increased use of water by industry, agriculture, and the population at large, population growth, and the potential impacts of climate change on water resources may cause water use restrictions that affect Entergy and its subsidiaries.
Entergy and its subsidiaries may not be adequately hedged against changes in commodity prices, which could materially affect Entergy’s and its subsidiaries’ results of operations, financial condition, and liquidity.
To manage near-term and medium-term financial exposure related to commodity price fluctuations, Entergy and its subsidiaries, including the Utility operating companies, may enter into contracts to hedge portions of their purchase and sale commitments, fuel requirements, and inventories of natural gas, uranium and its conversion and enrichment, coal, refined products, and other commodities, within established risk management guidelines. As part of this strategy, Entergy and its subsidiaries may utilize fixed- and variable-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. However, Entergy and its subsidiaries normally cover only a portion of the exposure of their assets and positions to market price volatility, and the coverage will vary over time. In addition, Entergy also elects to leave certain volumes during certain years unhedged. To the extent Entergy and its subsidiaries have unhedged positions, fluctuating commodity prices can materially affect Entergy’s and its subsidiaries’ results of operations and financial position.
Although Entergy and its subsidiaries devote a considerable effort to these risk management strategies, they cannot eliminate all the risks associated with these activities. As a result of these and other factors, Entergy and its subsidiaries cannot predict with precision the impact that risk management decisions may have on their business, results of operations, or financial position.
Entergy’s over-the-counter financial derivatives are subject to rules implementing the Dodd-Frank Wall Street Reform and Consumer Protection Act that are designed to promote transparency, mitigate systemic risk, and protect against market abuse. Entergy cannot predict the impact any proposed or not fully-implemented final rules
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
will have on its ability to hedge its commodity price risk or on over-the-counter derivatives markets as a whole, but such rules and regulations could have a material effect on Entergy's risk exposure, as well as reduce market liquidity and further increase the cost of hedging activities.
Entergy has guaranteed or indemnified the performance of a portion of the obligations relating to hedging and risk management activities. Reductions in Entergy’s or its subsidiaries’ credit quality or changes in the market prices of energy commodities could increase the cash or letter of credit collateral required to be posted in connection with hedging and risk management activities, which could materially affect Entergy’s or its subsidiaries’ liquidity and financial position.
The Utility operating companies and Entergy’s non-regulated operations are exposed to the risk that counterparties may not meet their obligations, which may materially affect the Utility operating companies and Entergy’s non-regulated operations.
The hedging and risk management practices of the Utility operating companies and Entergy's non-regulated operations are exposed to the risk that counterparties that owe Entergy and its subsidiaries money, energy, or other commodities will not perform their obligations. Currently, some hedging agreements contain provisions that require the counterparties to provide credit support to secure all or part of their obligations to Entergy or its subsidiaries. If the counterparties to these arrangements fail to perform, Entergy or its subsidiaries may enforce and recover the proceeds from the credit support provided and acquire alternative hedging arrangements, which credit support may not always be adequate to cover the related obligations. In such event, Entergy and its subsidiaries might incur losses in addition to amounts, if any, already paid to the counterparties. In addition, the credit commitments of Entergy’s lenders under its bank facilities may not be honored for a variety of reasons, including unexpected periods of financial distress affecting such lenders, which could materially affect the adequacy of its liquidity sources.
Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding and result in increased benefit plan costs.
The performance of the capital markets affects the values of the assets held in trust under Entergy’s pension and postretirement benefit plans. A decline in the market value of the assets may increase the funding requirements relating to Entergy’s benefit plan liabilities and also result in higher benefit costs. As the value of the assets decreases, the “expected return on assets” component of benefit costs decreases, resulting in higher benefits costs. Additionally, asset losses are incorporated into benefit costs over time, thus increasing benefits costs. Volatility in the capital markets has affected the market value of these assets, which may affect Entergy’s planned levels of contributions in the future. Additionally, changes in interest rates affect the liabilities under Entergy’s pension and postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding and recognition of higher liability carrying costs. The funding requirements of the obligations related to the pension benefit plans can also increase as a result of changes in, among other factors, retirement rates, life expectancy assumptions, or federal regulations. For further information regarding Entergy’s pension and other postretirement benefit plans, refer to the “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” section of Management’s Financial Discussion and Analysis for Entergy and each of its Registrant Subsidiaries and Note 11 to the financial statements.
The litigation environment in the states in which the Registrant Subsidiaries operate poses a significant risk to those businesses.
Entergy and its subsidiaries and related entities are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, asbestos, hazardous material and customer matters, and injuries and damages issues, among other matters. The states in which the Registrant Subsidiaries operate have proven to be unusually litigious environments. Judges and juries in these states have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
cases. Entergy and its subsidiaries use legal and appropriate means to contest litigation threatened or filed against them, but the litigation environment in these states poses a significant business risk.
Terrorist attacks, physical attacks, cyber attacks, system failures or data breaches of Entergy’s and its subsidiaries’ or their suppliers’ infrastructure or technology systems may adversely affect Entergy’s results of operations.
Entergy and its subsidiaries operate in a business that requires evolving information technology systems that include sophisticated data collection, processing systems, software, network infrastructure, and other technologies that are becoming more complex and may be subject to mandatory and prescriptive reliability and security standards. The functionality of Entergy’s technology systems depends on its own and its suppliers’ and their contractors’ technology. Suppliers’ and their contractors’ technology systems to which Entergy is connected directly or indirectly support a variety of business processes and activities to store sensitive data, including (i) intellectual property, (ii) proprietary business information, (iii) personally identifiable information of customers, employees, and others, and (iv) data with respect to invoicing and the collection of payments, accounting, procurement, and supply-chain activities. Any significant failure or malfunction of such information technology systems could result in loss of or inappropriate access to data or disruptions of operations.
There have been attacks and threats of attacks on energy infrastructure by cyber actors, including those associated with foreign governments. As an operator of critical infrastructure, Entergy and its subsidiaries face a heightened risk of physical attacks or acts or threats of terrorism, cyber attacks, including ransomware attacks, and data breaches, whether as a direct or indirect act against one of Entergy’s generation, transmission or distribution facilities, operations centers, infrastructure, or information technology systems used to manage, monitor, and transport power to customers and perform day-to-day business functions as well as against the systems of critical suppliers and contractors. Further, attacks may become more frequent in the future as technology becomes more prevalent in energy infrastructure. An attack could affect Entergy’s ability to operate, including its ability to operate the information technology systems and network infrastructure on which it relies to conduct business.
Given the rapid technological advancements of existing and emerging threats, Entergy’s technology systems remain inherently vulnerable despite implementations and enhancements of the multiple layers of security and controls. If Entergy’s or its subsidiaries’ technology systems, or those of critical suppliers or contractors, were compromised and unable to detect or recover in a timely fashion to a normal state of operations, Entergy or its subsidiaries could be unable to perform critical business functions that are essential to the company’s well-being and could result in a loss of or inappropriate access to its confidential, sensitive, and proprietary information, including personal information of its customers, employees, suppliers, and others in Entergy’s care.
Any such attacks, failures, or data breaches could have a material effect on Entergy’s and the Utility operating companies’ business, financial condition, results of operations or reputation. Although Entergy and the Utility operating companies purchase insurance for cyber attacks and data breaches, such insurance prices have increased substantially, and coverage may not be adequate to cover all losses that might arise in connection with these events. Such events may also expose Entergy to an increased risk of litigation (and associated damages and fines).
Entergy and the Registrant Subsidiaries are subject to risks associated with their ability to obtain adequate insurance at acceptable costs.
The global economic cost to insurers resulting from cyber attacks, natural disasters and other catastrophic events, in addition to an increased focus on climate issues could have disruptive effects on insurance markets. The availability of insurance capacity may decrease, and the insurance policies that Entergy or the Registrant Subsidiaries are able to obtain may have higher deductibles, higher premiums, and more restrictive terms and conditions. Further, the insurance policies of Entergy or the Registrant Subsidiaries may not cover all of their potential exposures or actual amounts of losses incurred.
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
Significant increases in commodity prices, other materials and supplies, and operation and maintenance expenses may adversely affect Entergy's results of operations, financial condition, and liquidity.
Entergy and its subsidiaries have observed and expect future inflationary pressures related to commodity prices, other materials and supplies, and operation and maintenance expenses, including in the areas of labor, health care, and pension costs. The contracts for the construction of certain of the Utility operating companies’ generation facilities also have included, and in the future may include, price adjustment provisions that, subject to certain limitations, may enable the contractor to increase the contract price to reflect increases in certain costs of constructing the facility. These inflationary pressures could impact the ability of Entergy and its subsidiaries to control costs and/or make substantial investments in their businesses, including their ability to recover costs and investments, and to earn their allowed return on equity within frameworks established by their regulators while maintaining affordability of their services for their customers, in addition to having unpredictable effects on Entergy’s customers. Increases in commodity prices, other materials and supplies, and operation and maintenance expenses, including increasing labor costs and costs and funding requirements associated with Entergy's defined benefit retirement plans, health care plans, and other employee benefits, could increase their financing needs and otherwise adversely affect their results of operations, financial condition, and liquidity.
(Entergy New Orleans)
The effect of higher purchased gas cost charges to customers taking gas service may adversely affect Entergy New Orleans’s results of operations and liquidity.
Gas rates charged to retail gas customers are comprised primarily of purchased gas cost charges, which provide no return or profit to Entergy New Orleans, and distribution charges, which provide a return or profit to the utility. Distribution charges recover fixed costs on a volumetric basis and, thus, are affected by the amount of gas sold to customers. When purchased gas cost charges increase due to higher gas procurement costs, customer usage may decrease, especially in weaker economic times, resulting in lower distribution charges for Entergy New Orleans, which, given its relatively smaller size, could adversely affect results of operations. Purchased gas cost charges, which comprise most of a customer’s bill and may be adjusted monthly, represent gas commodity costs that Entergy New Orleans recovers from its customers. Entergy New Orleans’s cash flows can be affected by differences between the time when gas is purchased and the time when ultimate recovery from customers occurs.
(Entergy Corporation and System Energy)
System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on sales to affiliated companies for all of its revenues. Certain contractual arrangements relating to System Energy, the affiliated companies, and these revenues are the subject of ongoing litigation and regulatory proceedings. The aggregate amount of refunds claimed in these proceedings substantially exceeds the current net book value of System Energy. In the event of an adverse decision in one or more of these proceedings requiring the payment of substantial additional refunds, System Energy would be required to seek financing to pay such refunds which financing may not be available on terms acceptable to System Energy, or may not be available at all, when required. If one or more of the foregoing events occurs, System Energy may be required to explore other options or protections available to it to extend, restructure, or retire its indebtedness and to prioritize its obligations.
System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf. Charges under the Unit Power Sales Agreement are paid by the Utility operating companies (other than Entergy Texas) as consideration for their respective entitlements to receive capacity and energy. The useful economic life of Grand Gulf is finite and is limited by the terms of its operating license, which currently expires in November 2044. System Energy’s financial condition depends both on the receipt of payments from the Utility operating companies (other than Entergy Texas)
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
under the Unit Power Sales Agreement and on the continued commercial operation of Grand Gulf. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC, including a challenge with respect to System Energy’s uncertain tax positions, sale leaseback arrangement, authorized return on equity and capital structure, a broader investigation of rates under the Unit Power Sales Agreement, and a prudence complaint challenging the extended power uprate completed at Grand Gulf in 2012 and the operation and management of Grand Gulf, particularly in the 2016-2020 time period.
The claims in these proceedings include claims for refunds and claims for rate adjustments. The aggregate amount of refunds claimed in these proceedings substantially exceeds the current net book value of System Energy. Entergy Corporation is not obligated to provide funding to System Energy to enable it to pay any such refunds. In the event that an adverse decision in one or more of these proceedings required the payment of substantial additional refunds, System Energy would need to source additional financing to pay such refunds. Such financing may not be available on terms acceptable to System Energy, or may not be available at all, when required. An adverse development in one or more of these proceedings also could jeopardize System Energy’s ability to finance its operations and pay its obligations, at a reasonable cost or when due. If one or more of the foregoing events occurs, System Energy may be required to explore other options or protections available to it to extend, restructure, or retire its indebtedness and to prioritize its obligations. One or more rating agencies may downgrade the ratings of System Energy or its debt securities, which could adversely affect the market prices of System Energy’s debt securities and otherwise adversely affect System Energy’s financial condition.
In addition, an order requiring System Entergy to pay substantial additional refunds could result in a default and, in certain cases, acceleration under one or more of System Energy’s existing bond indentures, credit agreements, or other financing arrangements. Certain events constituting events of default under System Energy’s financing agreements may also result in defaults under, or acceleration with respect to, financing arrangements involving certain credit agreement and guarantee obligations of Entergy Corporation.
These proceedings are pending before their respective adjudicators and no final decisions have been reached. Thus, Entergy cannot predict with certainty the outcome of any of these proceedings, or the magnitude of any refunds or rate adjustments, and an adverse outcome in any of them could have a material adverse effect on Entergy’s or System Energy’s results of operations, financial condition, or liquidity. In particular, in connection with the uncertain tax position proceeding and related December 2022 FERC order and System Energy’s compliance report filed in January 2023, if the FERC were to order additional refunds at a level consistent with the position of the LPSC, the APSC, and the City Council on the remedy for the formerly uncertain tax positions, System Energy’s continued financial viability would be jeopardized. See Note 2 to the financial statements for further discussion of the proceedings. The Utility operating companies (other than Entergy Texas) have agreed to implement certain protocols for providing retail regulators with information regarding rates billed under the Unit Power Sales Agreement.
For information regarding the Unit Power Sales Agreement, the sale and leaseback transactions and certain other agreements relating to certain Entergy System companies’ support of System Energy, see Notes 5 and 8 to the financial statements and the “Utility - System Energy and Related Agreements” section of Part I, Item 1.
(Entergy Corporation)
Entergy’s non-regulated operations are subject to substantial governmental regulation and may be adversely affected by legislative, regulatory, or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
Entergy’s non-regulated operations are subject to regulation under federal, state, and local laws. Compliance with the requirements under these various regulatory regimes may cause Entergy’s non-regulated operations to incur significant additional costs, and failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of liens, fines, and/or civil or criminal liability.
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
Public utilities under the Federal Power Act are required to obtain FERC acceptance of their rate schedules for wholesale sales of electricity. Entergy’s non-regulated operations include legal entities that meet the definition of a “public utility” under the Federal Power Act by virtue of making wholesale sales of electric energy and/or owning wholesale electric transmission facilities. The FERC has granted those entities the authority to sell electricity at market-based rates. The FERC’s orders that grant those entities market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that those entities can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, market-based sales are subject to certain market behavior rules, and if one of those entities were deemed to have violated one of those rules, they would be subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority and potential penalties of up to $1.29 million per day per violation. If one of those entities were to lose their market-based rate authority, it would be required to obtain the FERC’s acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have an adverse effect on the rates those entities charge for power from its facilities.
Entergy’s non-regulated operations are also affected by legislative and regulatory changes, as well as by changes to market design, market rules, tariffs, cost allocations, and bidding rules imposed by the existing Independent System Operator. The Independent System Operator that oversees the relevant wholesale power market may impose, and in the future may continue to impose, mitigation, including price limitations, offer caps and other mechanisms, to address some of the volatility and the potential exercise of market power in that market. These types of price limitations and other regulatory mechanisms may have an adverse effect on the profitability of Entergy’s non-regulated operations’ generation facilities that sell energy and capacity into the wholesale power markets.
The regulatory environment applicable to the electric power industry is subject to changes as a result of restructuring initiatives at both the state and federal levels. Entergy cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on Entergy’s non-regulated operations. In addition, in some of these markets, interested parties have proposed material market design changes, including the elimination of a single clearing price mechanism, have raised claims that the competitive marketplace is not working, and have made proposals to re-regulate the markets, impose a generation tax, or require divestitures by generating companies to reduce their market share. Other proposals to re-regulate may be made and legislative or other attention to the electric power market restructuring process may delay or reverse the deregulation process, which could require material changes to business planning models. If competitive restructuring of the electric power markets is reversed, modified, discontinued, or delayed, Entergy’s non-regulated operations’ results of operations, financial condition, and liquidity could be materially affected.
As a holding company, Entergy Corporation depends on cash distributions from its subsidiaries to meet its debt service and other financial obligations and to pay dividends on its common stock, and has provided, and may continue to provide, capital contributions or debt financing to its subsidiaries, which would reduce the funds available to meet its other financial obligations.
Entergy Corporation is a holding company with no material revenue generating operations of its own or material assets other than the stock of its subsidiaries. Accordingly, all of its operations are conducted by its subsidiaries. Entergy Corporation has provided, and may continue to provide, capital contributions or debt financing to its subsidiaries, which would reduce the funds available to meet its financial obligations, including making interest and principal payments on outstanding indebtedness, and to pay dividends on Entergy’s common stock. Entergy Corporation’s ability to satisfy its financial obligations, including the payment of interest and principal on its outstanding debt, and to pay dividends on its common stock depends on the payment to it of dividends or distributions by its subsidiaries. The subsidiaries of Entergy Corporation are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any dividends or make distributions to Entergy Corporation. The ability of such subsidiaries to make payments of dividends or distributions to Entergy
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
Corporation depends on their results of operations and cash flows and other items affecting retained earnings, and on any applicable legal, regulatory, or contractual limitations on subsidiaries’ ability to pay such dividends or distributions. Prior to providing funds to Entergy Corporation, such subsidiaries have financial and regulatory obligations that must be satisfied, including among others, debt service and, in the case of Entergy Utility Holding Company and Entergy Texas, dividends and distributions on preferred securities. Any distributions from the Registrant Subsidiaries other than Entergy Texas and System Energy are paid directly to Entergy Utility Holding Company and are therefore subject to prior payment of distributions on its preferred securities.
Item 1B. Unresolved Staff Comments
None.
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
2022 Compared to 2021
Earnings Applicable to Member’s Equity
Earnings decreased $19.3 million primarily due to higher other operation and maintenance expenses, the reversal in 2021 of the remaining $38.8 million regulatory liability for the formula rate plan 2019 historical year netting adjustment, higher depreciation and amortization expenses, higher interest expense, and higher taxes other than income taxes, partially offset by higher retail electric price and higher volume/weather.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 2022 to 2021:
| | | | | |
| Amount |
| (In Millions) |
| 2021 operating revenues | $2,338.6 | |
| Fuel, rider, and other revenues that do not significantly affect net income | 209.2 | |
| Retail electric price | 70.0 | |
| Volume/weather | 47.4 | |
| Return of unprotected excess accumulated deferred income taxes to customers | 8.0 | |
| 2022 operating revenues | $2,673.2 | |
Entergy Arkansas’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.
The retail electric price variance is primarily due to an increase in formula rate plan rates effective January 2022. See Note 2 to the financial statements for further discussion of the 2021 formula rate plan filing.
The volume/weather variance is primarily due to the effect of more favorable weather on residential sales and an increase in demand charges as a result of an updated contract with an industrial customer in the primary metals industry, partially offset by a decrease in weather-adjusted residential usage.
The return of unprotected excess accumulated deferred income taxes to customers resulted from the return of unprotected excess accumulated deferred income taxes through a tax adjustment rider beginning in April 2018. In 2021, $8 million was returned to customers. There was no effect on net income as the reduction in operating revenues was offset by a reduction in income tax expense. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Total electric energy sales for Entergy Arkansas for the years ended December 31, 2022 and 2021 are as follows:
| | | | | | | | | | | | | | | | | |
| 2022 | | 2021 | | % Change |
| (GWh) | | |
| Residential | 8,147 | | | 7,914 | | | 3 | |
| Commercial | 5,615 | | | 5,491 | | | 2 | |
| Industrial | 8,493 | | | 8,466 | | | — | |
| Governmental | 218 | | | 225 | | | (3) | |
| Total retail | 22,473 | | | 22,096 | | | 2 | |
| Sales for resale: | | | | | |
| Associated companies | 1,906 | | | 2,254 | | | (15) | |
| Non-associated companies | 6,520 | | | 6,151 | | | 6 | |
| Total | 30,899 | | | 30,501 | | | 1 | |
See Note 19 to the financial statements for additional discussion of Entergy Arkansas’s operating revenues.
Other Income Statement Variances
Other operation and maintenance expenses increased primarily due to:
•an increase of $24.1 million in power delivery expenses primarily due to higher vegetation maintenance costs, higher safety and training costs, and higher reliability costs, partially offset by a decrease in meter reading expenses as a result of the deployment of advanced metering systems;
•an increase of $17 million in nuclear generation expenses primarily due to a higher scope of work performed in 2022 as compared to 2021 and higher nuclear labor costs;
•an increase of $11.6 million in non-nuclear generation expenses primarily due to a higher scope of work, including during plant outages, performed in 2022 as compared to 2021 and higher costs associated with materials and supplies in 2022 as compared to 2021;
•an increase of $7.9 million in energy efficiency expenses primarily due to the timing of recovery from customers, partially offset by lower energy efficiency costs; and
•an increase of $4.6 million in customer service center support costs primarily due to higher contract costs.
Taxes other than income taxes increased primarily due to increases in ad valorem taxes resulting from higher assessments and millage rate increases, increases in employment taxes, and increases in local franchise taxes.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including the Searcy Solar facility, which was placed in service in December 2021.
Other regulatory charges (credits) - net includes the reversal in first quarter 2021 of the remaining $38.8 million regulatory liability for the 2019 historical year netting adjustment as part of its 2020 formula rate plan proceeding. See Note 2 to the financial statements for discussion of the 2020 formula rate plan filing. In addition, Entergy Arkansas records a regulatory charge or credit for the difference between asset retirement obligation-related expenses and nuclear decommissioning trust earnings plus asset retirement obligation-related costs collected in revenue.
Other income decreased primarily due to changes in decommissioning trust fund activity, including portfolio rebalancing of the decommissioning trust funds in 2021.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Interest expense increased primarily due to the issuance of $200 million of 4.20% Series mortgage bonds in March 2022 and the issuance of $400 million of 3.35% Series mortgage bonds in March 2021, partially offset by the repayment of $350 million of 3.75% Series mortgage bonds in February 2021.
Net loss attributable to noncontrolling interest reflects the earnings or losses attributable to the noncontrolling interest partner of the tax equity partnership for the Searcy Solar facility under HLBV accounting. Entergy Arkansas recorded regulatory charges of $4.5 million in 2022 compared to $18.1 million in 2021 to defer the difference between the losses allocated to the tax equity partner under the HLBV method of accounting and the earnings/loss that would have been allocated to the tax equity partner under its respective ownership percentage in the partnership. See Note 1 to the financial statements for discussion of the HLBV method of accounting.
The effective income tax rates were 21.6% for 2022 and 20.1% for 2021. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates, and for additional discussion regarding income taxes.
2021 Compared to 2020
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy Arkansas’s Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC onFebruary 25, 2022, for discussion of results of operations for 2021 compared to 2020.
Income Tax Legislation
See the “Income Tax Legislation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the Inflation Reduction Act of 2022.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2022, 2021, and 2020 were as follows:
| | | | | | | | | | | | | | | | | | |
| | 2022 | | 2021 | | 2020 | |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period | $12,915 | | | $192,128 | | | $3,519 | | |
| | | | | | |
| Net cash provided by (used in): | | | | | | |
| Operating activities | 699,732 | | | 549,216 | | | 659,818 | | |
| Investing activities | (852,794) | | | (898,193) | | | (795,709) | | |
| Financing activities | 145,425 | | | 169,764 | | | 324,500 | | |
| Net increase (decrease) in cash and cash equivalents | (7,637) | | | (179,213) | | | 188,609 | | |
| | | | | | |
| Cash and cash equivalents at end of period | $5,278 | | | $12,915 | | | $192,128 | | |
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2022 Compared to 2021
Operating Activities
Net cash flow provided by operating activities increased $150.5 million in 2022 primarily due to:
•higher collections from customers;
•the timing of recovery of fuel and purchased power costs. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery; and
•a decrease in spending of $23.6 million on nuclear refueling outages in 2022.
The increase was partially offset by:
•payments to vendors, including timing and increase in cost of operations;
•an increase of $26.3 million in pension contributions in 2022. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding; and
•a decrease of $16.2 million in income tax refunds. Entergy Arkansas received income tax refunds in 2022 and 2021, each in accordance with an intercompany income tax allocation agreement.
Investing Activities
Net cash flow used in investing activities decreased $45.4 million in 2022 primarily due to:
•the purchase of the Searcy Solar facility by the tax equity partnership in December 2021 for approximately $131.8 million. See Note 14 to the financial statements for further discussion of the Searcy Solar facility purchase; and
•a decrease of $16.6 million in non-nuclear generation construction expenditures primarily due to a lower scope of work on projects performed in 2022 as compared to 2021.
The decrease was partially offset by:
•an increase of $78.7 million in distribution construction expenditures primarily due to higher capital expenditures for storm restoration in 2022 and increased investment in the reliability and infrastructure of Entergy Arkansas’s distribution system, partially offset by lower spending in 2022 on advanced metering infrastructure;
•an increase of $27.2 million in decommissioning trust fund investment activity; and
•an increase of $19 million in transmission construction expenditures primarily due to a higher scope of work on projects performed in 2022 as compared to 2021.
Financing Activities
Net cash flow provided by financing activities decreased $24.3 million in 2022 primarily due to:
•the issuance of $400 million of 3.35% Series mortgage bonds in March 2021;
•money pool activity;
•capital contributions of $51.2 million received in 2021 from the noncontrolling tax equity investor in AR Searcy Partnership, LLC and used by the partnership to acquire the Searcy Solar facility. See Note 14 to the financial statements for discussion of the Searcy Solar facility purchase;
•lower prepaid deposits of $50.9 million related to contributions-in-aid-of-construction reimbursement agreements in 2022 as compared to 2021; and
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
•an increase of $36 million in common equity distributions paid in 2022 as compared to 2021 in order to maintain Entergy Arkansas’s capital structure.
The decrease was partially offset by:
•the repayment, at maturity, of $350 million of 3.75% Series mortgage bonds in February 2021;
•the issuance of $200 million of 4.20% Series mortgage bonds in March 2022; and
•the repayment, at maturity, of $45 million of 2.375% Series governmental bonds in January 2021.
Increases in Entergy Arkansas’s payable to the money pool are a source of cash flow, and Entergy Arkansas’s payable to the money pool increased $40.9 million in 2022 compared to increasing by $139.9 million in 2021. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
See Note 5 to the financial statements for further details of long-term debt.
2021 Compared to 2020
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Arkansas’s Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 25, 2022, for discussion of operating, investing, and financing cash flow activities for 2021 compared to 2020.
Capital Structure
Entergy Arkansas’s debt to capital ratio is shown in the following table.
| | | | | | | | | | | |
| | December 31,
2022 | | December 31,
2021 |
| Debt to capital | 52.5 | % | | 52.6 | % |
| Effect of subtracting cash | — | % | | — | % |
| Net debt to net capital (non-GAAP) | 52.5 | % | | 52.6 | % |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. Entergy Arkansas uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition. The net debt to net capital ratio is a non-GAAP measure. Entergy Arkansas also uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition because net debt indicates Entergy Arkansas’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Arkansas seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a distribution, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Arkansas may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reducing distributions, Entergy Arkansas may receive equity contributions to maintain its capital structure.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Uses of Capital
Entergy Arkansas requires capital resources for:
•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.
Following are the amounts of Entergy Arkansas’s planned construction and other capital investments.
| | | | | | | | | | | | | | | | | |
| | 2023 | | 2024 | | 2025 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation | $255 | | | $1,175 | | | $910 | |
| Transmission | 110 | | | 160 | | | 135 | |
| Distribution | 285 | | | 425 | | | 350 | |
| Utility Support | 105 | | | 65 | | | 90 | |
| Total | $755 | | | $1,825 | | | $1,485 | |
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Arkansas includes investments in generation projects to modernize, decarbonize, and diversify Entergy Arkansas’s portfolio, including Walnut Bend Solar, West Memphis Solar, and Driver Solar; investments in ANO 1 and 2; distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to drive reliability and resilience while also supporting renewables expansion; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, government actions, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.
While Entergy Arkansas is still assessing the effect on its planned solar projects, the investigation by the U.S. Department of Commerce into potential circumvention of duties and tariffs may result in increased duties or tariffs on imported solar panels and has exacerbated previously existing supply chain disruptions, which have negatively affected the timing and cost of completion of these projects.
Following are the amounts of Entergy Arkansas’s existing debt and lease obligations (includes estimated interest payments).
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2023 | | 2024 | | 2025 | | 2026-2027 | | After 2027 |
| | (In Millions) |
| Long-term debt (a) | $432 | | | $504 | | | $123 | | | $898 | | | $5,060 | |
| Operating leases (b) | $16 | | | $14 | | | $12 | | | $16 | | | $2 | |
| Finance leases (b) | $3 | | | $3 | | | $3 | | | $4 | | | $2 | |
(a)Long-term debt is discussed in Note 5 to the financial statements.
(b)Lease obligations are discussed in Note 10 to the financial statements.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Other Obligations
Entergy Arkansas currently expects to contribute approximately $54.5 million to its qualified pension plans and approximately $526 thousand to its other postretirement health care and life insurance plans in 2023, although the 2023 required pension contributions will be known with more certainty when the January 1, 2023 valuations are completed, which is expected by April 1, 2023. See “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Entergy Arkansas has $175.4 million of unrecognized tax benefits net of unused tax attributes plus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition, Entergy Arkansas enters into fuel and purchased power agreements that contain minimum purchase obligations. Entergy Arkansas has rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations. See Note 8 to the financial statements for discussion of Entergy Arkansas’s obligations under the Unit Power Sales Agreement.
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Arkansas pays distributions from its earnings at a percentage determined monthly.
Renewables
Walnut Bend Solar
In October 2020, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 100 MW Walnut Bend Solar facility is in the public interest. Entergy Arkansas primarily requested cost recovery through the formula rate plan rider. In July 2021 the APSC granted Entergy Arkansas’s petition and approved the acquisition of the resource and cost recovery through the formula rate plan rider. In addition, the APSC directed Entergy Arkansas to file a report within 180 days detailing its efforts to obtain a tax equity partnership. In January 2022, Entergy Arkansas filed its tax equity partnership status report and will file subsequent reports until a tax equity partnership is obtained or a tax equity partnership is no longer sought. Closing was expected to occur in 2022. The counter-party notified Entergy Arkansas that it was terminating the project, though it was willing to consider an alternative for the site. Entergy Arkansas disputed the right of termination. Negotiations are ongoing, including with respect to cost and schedule and to updates arising as a result of the Inflation Reduction Act of 2022, and the updates would require additional APSC approval. At this time, the project, if approved, is expected to achieve commercial operation in 2024.
West Memphis Solar
In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 180 MW West Memphis Solar facility is in the public interest. In October 2021 the APSC granted Entergy Arkansas’s petition and approved the acquisition of the West Memphis Solar facility and cost recovery through the formula rate plan rider. In addition, the APSC directed Entergy Arkansas to file a report within 180 days detailing its efforts to obtain a tax equity partnership. In April 2022, Entergy Arkansas filed its tax equity partnership status report and will file subsequent reports until a tax equity partnership is obtained or a tax equity partnership is no longer sought. Closing had been expected to occur in 2023. In March 2022 the counter-party notified Entergy Arkansas that it was seeking changes to certain terms of the build-own-transfer agreement, including both cost and schedule. In January 2023, Entergy Arkansas filed a supplemental application with the APSC seeking approval for a change in the transmission route and updates to the cost and schedule that were previously approved by the APSC. The project is expected to achieve commercial operation in 2024.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Driver Solar
In April 2022, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 250 MW Driver Solar facility is in the public interest and requested cost recovery through the formula rate plan rider. The APSC established a procedural schedule with a hearing scheduled in June 2022, but the parties later agreed to waive the hearing and submit the matter to the APSC for a decision consistent with the filed record. In August 2022 the APSC granted Entergy Arkansas’s petition and approved the acquisition of Driver Solar and cost recovery through the formula rate plan rider. In addition, the APSC directed Entergy Arkansas to inform the APSC as to the status of a tax equity partnership once construction is commenced. The parties are evaluating the effects of certain matters related to the Inflation Reduction Act of 2022, including the viability of a tax equity partnership. The project is expected to achieve commercial operation in 2024.
Sources of Capital
Entergy Arkansas’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•the Entergy System money pool;
•debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations, Entergy Arkansas expects to continue, when economically feasible, to retire higher-cost debt and replace it with lower-cost debt if market conditions permit.
All debt and common and preferred membership interest issuances by Entergy Arkansas require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in Entergy Arkansas’s bond indenture and other agreements. Entergy Arkansas has sufficient capacity under these tests to meet its foreseeable capital needs for the next twelve months and beyond.
Entergy Arkansas’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
| | | | | | | | | | | | | | | | | | | | |
| 2022 | | 2021 | | 2020 | | 2019 |
| (In Thousands) |
| ($180,795) | | ($139,904) | | $3,110 | | ($21,634) |
See Note 4 to the financial statements for a description of the money pool.
Entergy Arkansas has a credit facility in the amount of $150 million scheduled to expire in June 2027. Entergy Arkansas also has a $25 million credit facility scheduled to expire in April 2023. The $150 million credit facility includes fronting commitments for the issuance of letters of credit against $5 million of the borrowing capacity of the facility. As of December 31, 2022, there were no cash borrowings and no letters of credit outstanding under the credit facilities. In addition, Entergy Arkansas is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2022, $5.6 million in
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
letters of credit were outstanding under Entergy Arkansas’s uncommitted letter of credit facility. See Note 4 to the financial statements for further discussion of the credit facilities.
The Entergy Arkansas nuclear fuel company variable interest entity has a credit facility in the amount of $80 million scheduled to expire in June 2025. As of December 31, 2022, there were no loans outstanding under the credit facility for the Entergy Arkansas nuclear fuel company variable interest entity. See Note 4 to the financial statements for further discussion of the nuclear fuel company variable interest entity credit facility.
Entergy Arkansas obtained authorization from the FERC through October 2023 for short-term borrowings not to exceed an aggregate amount of $250 million at any time outstanding and borrowings by its nuclear fuel company variable interest entity. See Note 4 to the financial statements for further discussion of Entergy Arkansas’s short-term borrowing limits. The long-term securities issuances of Entergy Arkansas are limited to amounts authorized by the FERC. The APSC has concurrent jurisdiction over Entergy Arkansas’s first mortgage bond/secured issuances. Entergy Arkansas has obtained long-term financing authorization from the FERC that extends through October 2023. Entergy Arkansas has obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2023.
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy Arkansas charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Arkansas is regulated, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the APSC, is primarily responsible for approval of the rates charged to customers.
Retail Rates
2020 Formula Rate Plan Filing
In May 2017,July 2020, Entergy LouisianaArkansas filed with the APSC its 2020 formula rate plan filing to set its formula rate for the 2021 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2021, as amended through subsequent filings in the proceeding, and a netting adjustment for the historical year 2019. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2021 projected year is 8.22% resulting in a revenue deficiency of $64.3 million. The earned rate of return on common equity for the 2019 historical year was 9.07% resulting in a $23.9 million netting adjustment. The total proposed revenue change for the 2021 projected year and 2019 historical year netting adjustment was $88.2 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $74.3 million. As part of the formula rate plan tariff the calculation for the revenue constraint was updated based on actual revenues which had the effect of reducing the initially-proposed $74.3 million revenue requirement increase to $72.6 million. In October 2020, Entergy Arkansas filed with the APSC a unanimous settlement agreement reached with the other parties that resolved all but one issue. As a result of the settlement agreement, Entergy Arkansas’s requested revenue increase was $68.4 million, including a $44.5 million increase for the projected 2021 year and a $23.9 million netting adjustment. The remaining issue litigated concerned the methodology used to calculate the netting adjustment within the formula rate plan. In December 2020 the APSC issued an order rejecting the netting adjustment method used by Entergy Arkansas. Applying the approach ordered by the APSC changed the netting adjustment for the 2019 historical year from a $23.9 million deficiency to $43.5 million excess. Overall, the decision reduced Entergy Arkansas’s revenue adjustment for 2021 to $1 million. In December 2020, Entergy Arkansas filed a petition for rehearing of the APSC’s decision in the 2020 formula rate plan proceeding regarding the 2019 netting adjustment, and in January 2021 the APSC granted further consideration of Entergy Arkansas’s petition. Based on the progress of the proceeding at that point, in December 2020, Entergy Arkansas recorded a regulatory liability of $43.5 million to reflect the netting adjustment for 2019, as included in the APSC’s December 2020 order, which would be returned
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
to customers in 2021. Entergy Arkansas also requested an extension of the formula rate plan rider for a second five-year term. In March 2021 the Arkansas Governor signed HB1662 into law (Act 404). Act 404 clarified aspects of the original formula rate plan legislation enacted in 2015, including with respect to the extension of a formula rate plan, the methodology for the netting adjustment, and debt and equity levels; it also reaffirmed the customer protections of the original formula rate plan legislation, including the cap on annual formula rate plan rate changes. Pursuant to Act 404, Entergy Arkansas’s formula rate plan rider was extended for a second five-year term. Entergy Arkansas filed a compliance tariff in its formula rate plan docket in April 2021 to effectuate the netting provisions of Act 404, which reflected a net change in required formula rate plan rider revenue of $39.8 million, effective with the first billing cycle of May 2021. In April 2021 the APSC issued an order approving the compliance tariff and recognizing the formula rate plan extension. Also in April 2021, Entergy Arkansas filed for approval of modifications to the formula rate plan tariff incorporating the provisions in Act 404, and the APSC approved the tariff modifications in April 2021. Given the APSC general staff’s support for the expedited approval of these filings by the APSC, Entergy Arkansas supported an amendment to Act 404 to achieve a reduced return on equity from 9.75% to 9.65% to apply for years applicable to the extension term; that amendment was signed by the Arkansas Governor in April 2021 and is now Act 894. Based on the APSC’s order issued in April 2021, in the first quarter 2021, Entergy Arkansas reversed the remaining regulatory liability for the netting adjustment for 2019. In June 2021, Entergy Arkansas filed another compliance tariff in its formula rate plan proceeding to effectuate the additional provisions of Act 894, and the APSC approved the second compliance tariff filing in July 2021.
2021 Formula Rate Plan Filing
In July 2021, Entergy Arkansas filed with the APSC its 2021 formula rate plan filing to set its formula rate for the 2022 calendar year. The filing contained an evaluation reportof Entergy Arkansas’s earnings for its 2016 calendarthe projected year operations.2022 and a netting adjustment for the historical year 2020. The evaluation report reflected anfiling showed that Entergy Arkansas’s earned rate of return on common equity for the 2022 projected year is 7.65% resulting in a revenue deficiency of 9.84%. As such, no$89.2 million. The earned rate of return on common equity for the 2020 historical year was 7.92% resulting in a $19.4 million netting adjustment. The total proposed revenue change for the 2022 projected year and 2020 historical year netting 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 revenueis $108.7 million. By operation 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, 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 is limited to $72.4 million. In October 2021, Entergy Arkansas filed with the APSC a settlement agreement reached with other parties resolving all issues in the proceeding. As a result of the settlement agreement, the total proposed revenue change is $82.2 million, including a $62.8 million increase for the projected 2022 year and a $19.4 million netting adjustment. Because Entergy Arkansas’s revenue requirement exceeded the constraint, the resulting increase is limited to $72.1 million. In December 2021 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 2022.
2022 Formula Rate Plan Filing
In July 2022, Entergy Arkansas filed with the APSC its 2022 formula rate plan filing to set its formula rate for the 2023 calendar year. The filing contained an evaluation report calledof Entergy Arkansas’s earnings for the projected year 2023 and a netting adjustment for the historical year 2021. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2023 projected year is 7.40% resulting in a revenue deficiency of $104.8 million. The earned rate of return on common equity for the 2021 historical year was 8.38% resulting in a $15.2 million netting adjustment. The total proposed revenue change for the 2023 projected year and 2021 historical year netting adjustment is $119.9 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement was subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $79.3 million. In October 2022 other parties filed their testimony recommending various adjustments to Entergy Arkansas’s overall proposed revenue deficiency, and Entergy Arkansas filed a response including an update to actual revenues through August 2022, which raised the constraint to $79.8 million. In November 2022, Entergy Arkansas filed with the APSC a settlement agreement reached with other parties resolving all issues in the
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
proceeding. As a result of the settlement agreement, the total revenue change was $102.8 million, including a $87.7 million increase for the 2023 projected year and a $15.2 million netting adjustment. Because Entergy Arkansas’s revenue requirement exceeded the constraint, the resulting increase was limited to $79.8 million. In December 2022 the APSC approved the settlement agreement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2023.
Green Promise Renewable Tariff
In July 2021, Entergy Arkansas filed a proposed green tariff designed to help participating customers meet their renewable and sustainability goals and to enhance economic development efforts in Arkansas. The total proposed amount of solar capacity requested to be available under this tariff was up to 200 MW. In September and October 2021 the APSC general staff and two net metering developer intervenors filed responses indicating opposition to the tariff as proposed. The tariff was supported by certain commercial and industrial customers that have indicated an interest in subscribing to the tariff. In October 2021, Entergy Arkansas, Walmart, and industrial customers filed a non-unanimous settlement agreement supporting that the tariff should be approved as filed by Entergy Arkansas; the Arkansas Attorney General stated it did not oppose the settlement. In January 2022 the APSC general staff filed in opposition to the non-unanimous settlement agreement, and one of the net metering developer intervenors withdrew from the proceeding. In January 2022 the parties agreed to a paper hearing with written responses to the APSC’s questions being filed in February and March 2022. In May 2022 the APSC found Entergy Arkansas’s proposal for the tariff to be just and reasonable for an initial offering of 100 MW of solar capacity, and in June 2022 the APSC approved Entergy Arkansas’s compliance tariff filing.
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 decreasechange 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 $40.5recovering 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 MISOsettlement agreement, including the resolution of civil litigation currently pending regarding the stator incident by the Circuit Court of Pope County, Arkansas. A trial date was established by the circuit court for March 1, 2023, but has been continued. In December 2022 the APSC approved Entergy Arkansas’s request for an additional extension of the deadline for initiating a regulatory proceeding for the purpose of recovering funds related to the stator incident to no later than sixty days after the circuit court issues a final order in the civil litigation proceedings. See the “ANO Damage, Outage, and NRC Reviews” section in Note 8 to the financial statements for further discussion of the ANO stator incident.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
In March 2017, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery revenue requirementrider, which reflected an increase in the rate from $46.8 million$0.01164 per kWh to $6.3 million. Rates reflecting these adjustments were$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 SeptemberApril 2017 under the normal operation of the tariff. Accordingly, the redetermined rate went into effect on March 31, 2017 pursuant to the tariff. In July 2017 the Arkansas Attorney General requested additional information to support certain of the costs included in Entergy Arkansas’s 2017 energy cost rate redetermination.
In March 2018, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01547 per kWh to $0.01882 per kWh. The Arkansas Attorney General filed a response to Entergy Arkansas’s annual redetermination filing requesting that the APSC suspend the proposed tariff to investigate the amount of the redetermination or, alternatively, to allow recovery subject to refund. Among the reasons the Attorney General cited for suspension were questions pertaining to how Entergy Arkansas forecasted sales and potential implications of the Tax Cuts and Jobs Act. Entergy Arkansas replied to the Attorney General’s filing and stated that, to the extent there are questions pertaining to its load forecasting or the operation of the energy cost recovery rider, those issues exceed the scope of the instant rate redetermination. Entergy Arkansas also stated that potential effects of the Tax Cuts and Jobs Act are appropriately considered in the APSC’s separate proceeding regarding potential implications of the tax law. The APSC general staff filed a reply to the Attorney General’s filing and agreed that Entergy Arkansas’s filing complied with the terms of the energy cost recovery rider. The redetermined rate became effective with the first billing cycle of April 2018. Subsequently in April 2018 the APSC issued an order declining to suspend Entergy Arkansas’s energy cost recovery rider rate and declining to require further investigation at that time of the issues suggested by the Attorney General in the proceeding. Following a period of discovery, the Attorney General filed a supplemental response in October 2018 raising new issues with Entergy Arkansas’s March 2018 rate redetermination and asserting that $45.7 million of the increase should be collected subject to refund pending further investigation. Entergy Arkansas filed to dismiss the Attorney General’s supplemental response, the APSC general staff filed a motion to strike the Attorney General’s filing, and the Attorney General filed a supplemental response disputing Entergy Arkansas and the APSC staff’s filing. Applicable APSC rules and processes authorize its general staff to initiate periodic audits of Entergy Arkansas’s energy cost recovery rider. In late-2018 the APSC general staff notified Entergy Arkansas it 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 2020, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $0.01462 per kWh to $0.01052 per kWh. The redetermined rate became effective with the first billing cycle in April 2020 through the normal operation of the tariff.
In March 2021, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $0.01052 per kWh to $0.00959 per kWh. The redetermined rate calculation also included an adjustment to account for a portion of the increased fuel costs resulting from the February 2021 winter storms. The redetermined rate became effective with the first billing cycle in April 2021 through the normal operation of the tariff.
In March 2022, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase from $0.00959 per kWh to $0.01785 per kWh. The primary reason for the rate increase is a large under-recovered balance as a result of higher natural gas prices in 2021, particularly in the fourth quarter 2021. At the request of the APSC general staff, Entergy Arkansas deferred its request for recovery of $32 million from the under-recovery related to the 2021 February winter storms until the 2023 energy cost rate redetermination, unless a request for an interim adjustment to the energy cost recovery rider is necessary. This resulted in a redetermined rate of $0.016390 per kWh, which became effective with the first billing cycle in April 2022 through the normal operation of the tariff. In February 2023 the APSC issued orders initiating proceedings with the utilities to address the prudence of costs incurred and appropriate cost allocation of the 2021 February winter storms. With respect to any prudence review of Entergy Arkansas fuel costs, as part of the APSC’s
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
draft report issued in its 2021 February winter storm investigation docket, the APSC included findings that the load shedding plans of the investor-owned utilities and some cooperatives were appropriate and comprehensive, and, further, that Entergy Arkansas’s emergency plan was comprehensive and had a multilayered approach supported by a system-wide response plan, which is considered an industry standard.
Opportunity Sales Proceeding
In June 2009 the LPSC filed a complaint requesting that the FERC determine that certain of Entergy Arkansas’s sales of electric energy to third parties: (a) violated the provisions of the System Agreement that allocated the energy generated by Entergy System resources; (b) imprudently denied the Entergy System and its ultimate consumers the benefits of low-cost Entergy System generating capacity; and (c) violated the provision of the System Agreement that prohibited sales to third parties by individual companies absent an offer of a right-of-first-refusal to other Utility operating companies. The LPSC’s complaint challenged sales made beginning in 2002 and requested refunds. In July 2009 the Utility operating companies filed a response to the complaint arguing among other things that the System Agreement contemplates that the Utility operating companies may make sales to third parties for their own account, subject to the requirement that those sales be included in the load (or load shape) for the applicable Utility operating company. The FERC subsequently ordered a hearing in the proceeding.
After a hearing, the ALJ issued an initial decision in December 2010. The ALJ found that the System Agreement allowed for Entergy Arkansas to make the sales to third parties but concluded that the sales should be accounted for in the same manner as joint account sales. The ALJ concluded that “shareholders” should make refunds of the damages to the Utility operating companies, along with interest. Entergy disagreed with several aspects of the ALJ’s initial decision and in January 2011 filed with the FERC exceptions to the decision.
The FERC issued a decision in June 2012 and held that, while the System Agreement is ambiguous, it does provide authority for individual Utility operating companies to make opportunity sales for their own account and Entergy Arkansas made and priced these sales in good faith. The FERC found, however, that the System Agreement does not provide authority for an individual Utility operating company to allocate the energy associated with such opportunity sales as part of its load but provides a different allocation authority. The FERC further found that the after-the-fact accounting methodology used to allocate the energy used to supply the sales was inconsistent with the System Agreement. The FERC in its decision established further hearing procedures to quantify the effect of repricing the opportunity sales in accordance with the FERC’s June 2012 decision. The hearing was held in May 2013 and the ALJ issued an initial decision in August 2013. The LPSC, the APSC, the City Council, and FERC staff filed briefs on exceptions and/or briefs opposing exceptions. Entergy filed a brief on exceptions requesting that the FERC reverse the initial decision and a brief opposing certain exceptions taken by the LPSC and FERC staff.
In April 2016 the FERC issued orders addressing requests for rehearing filed in July 2012 and the ALJ’s August 2013 initial decision. The first order denied Entergy’s request for rehearing and affirmed the FERC’s earlier rulings that Entergy’s original methodology for allocating energy costs to the opportunity sales was incorrect and, as a result, Entergy Arkansas must make payments to the other Utility operating companies to put them in the same position that they would have been in absent the incorrect allocation. The FERC clarified that interest should be included with the payments. The second order affirmed in part, and reversed in part, the rulings in the ALJ’s August 2013 initial decision regarding the methodology that should be used to calculate the payments Entergy Arkansas is to make to the other Utility operating companies. The FERC affirmed the ALJ’s ruling that a full re-run of intra-system bills should be performed but required that methodology be modified so that the sales have the same priority for purposes of energy allocation as joint account sales. The FERC reversed the ALJ’s decision that any payments by Entergy Arkansas should be reduced by 20%. The FERC also reversed the ALJ’s decision that adjustments to other System Agreement service schedules and excess bandwidth payments should not be taken into account when calculating the payments to be made by Entergy Arkansas. The FERC held that such adjustments and excess bandwidth payments should be taken into account but ordered further proceedings before an ALJ to address
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
whether a cap on any reduction due to bandwidth payments was necessary and to implement the other adjustments to the calculation methodology.
In May 2016, Entergy Services filed a request for rehearing of the FERC’s April 2016 order arguing that payments made by Entergy Arkansas should be reduced as a result of the timing of the LPSC’s approval of certain contracts. Entergy Services also filed a request for clarification and/or rehearing of the FERC’s April 2016 order addressing the ALJ’s August 2013 initial decision. The APSC and the LPSC also filed requests for rehearing of the FERC’s April 2016 order. In September 2017 the FERC issued an order denying the request for rehearing on the issue of whether any payments by Entergy Arkansas to the other Utility operating companies should be reduced due to the timing of the LPSC’s approval of Entergy Arkansas’s wholesale baseload contract with Entergy Louisiana. In November 2017 the FERC issued an order denying all of the remaining requests for rehearing of the April 2016 order. In November 2017, Entergy Services filed a petition for review in the D.C. Circuit of the FERC’s orders in the first two phases of the opportunity sales case. In December 2017 the D.C. Circuit granted Entergy Services’ request to hold the appeal in abeyance pending final resolution of the related proceeding before the FERC. In January 2018 the APSC and the LPSC filed separate petitions for review in the D.C. Circuit, and the D.C. Circuit consolidated the appeals with Entergy Services’ appeal.
The hearing required by the FERC’s April 2016 order was held in May 2017. In July 2017 the ALJ issued an initial decision addressing whether a cap on any reduction due to bandwidth payments was necessary and whether to implement the other adjustments to the calculation methodology. In August 2017 the Utility operating companies, the LPSC, the APSC, and FERC staff filed individual briefs on exceptions challenging various aspects of the initial decision. In September 2017 the Utility operating companies, the LPSC, the APSC, the MPSC, the City Council, and FERC staff filed separate briefs opposing exceptions taken by various parties.
Based on testimony previously submitted in the case and its assessment of the April 2016 FERC orders, in the first quarter 2016, Entergy Arkansas recorded a liability of $87 million, which included interest, for its estimated increased costs and payment to the other Utility operating companies, and a deferred fuel regulatory asset of $75 million. Following its assessment of the course of the proceedings, including the FERC’s denial of rehearing in November 2017 described above, in the fourth quarter 2017, Entergy Arkansas recorded an additional liability of $35 million and a regulatory asset of $31 million.
In October 2018 the FERC issued an order addressing the ALJ’s July 2017 initial decision. The FERC reversed the ALJ’s decision to cap the reduction in Entergy Arkansas’s payment to account for the increased bandwidth payments that Entergy Arkansas made to the other operating companies. The FERC also reversed the ALJ’s decision that Grand Gulf sales from January through September 2000 should be included in the calculation of Entergy Arkansas’s payment. The FERC affirmed on other grounds the ALJ’s rejection of the LPSC’s claim that certain joint account sales should be accounted for as part of the calculation of Entergy Arkansas’s payment. In November 2018 the LPSC requested rehearing of the FERC’s October 2018 decision. In December 2019 the FERC denied the LPSC’s request for rehearing. In January 2020 the LPSC appealed the December 2019 decision to the D.C. Circuit.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
In December 2018, Entergy made a compliance filing in response to the FERC’s October 2018 order. The compliance filing provided a final calculation of Entergy Arkansas’s payments to the other Utility operating companies, including interest. No protests were filed in response to the December 2018 compliance filing. Refunds and interest in the following amounts were paid by Entergy Arkansas to the other operating companies in December 2018:
| | | | | | | | | | | |
| | Total refunds including interest |
| Payment/(Receipt) |
| | (In Millions) |
| Principal | Interest | Total |
| Entergy Arkansas | $68 | $67 | $135 |
| Entergy Louisiana | ($30) | ($29) | ($59) |
| Entergy Mississippi | ($18) | ($18) | ($36) |
| Entergy New Orleans | ($3) | ($4) | ($7) |
| Entergy Texas | ($17) | ($16) | ($33) |
Entergy Arkansas previously recognized a regulatory asset with a balance of $116 million as of December 31, 2018 for a portion of the payments due as a result of this proceeding.
As described above, the FERC’s opportunity sales orders have been appealed to the D.C. Circuit. In February 2020 all of the appeals were consolidated and in April 2020 the D.C. Circuit established a briefing schedule. Briefing was completed in September 2020 and oral argument was heard in December 2020. In July 2021 the D.C. Circuit issued a decision denying all of the petitions for review filed in response to the FERC’s opportunity sales orders.
In February 2019 the LPSC filed a new complaint relating to two issues that were raised in the opportunity sales proceeding, but that, in its October 2018 order, the FERC held were outside the scope of the proceeding. In March 2019, Entergy Services filed an answer and motion to dismiss the new complaint. In November 2019 the FERC issued an order denying the LPSC’s complaint. The order concluded that the settlement agreement approved by the FERC in December 2015 terminating the System Agreement barred the LPSC’s new complaint. In December 2019 the LPSC requested rehearing of the FERC’s November 2019 order, and in July 2020 the FERC issued an order dismissing the LPSC’s request for rehearing. In September 2020 the LPSC appealed to the D.C. Circuit the FERC’s orders dismissing the new opportunity sales complaint. In November 2020 the D.C. Circuit issued an order establishing that briefing will occur in January 2021 through April 2021. Oral argument was held in September 2021. In December 2021 the D.C. Circuit denied the LPSC’s Petition for Review of the new opportunity sales complaint. The opportunity sales cases are complete at FERC and at the D.C. Circuit and no additional refund amounts are owed by Entergy Arkansas.
In May 2019, Entergy Arkansas filed an application and supporting testimony with the APSC requesting approval of a special rider tariff to recover the costs of these payments from its retail customers over a 24-month period. The application requested that the APSC approve the rider to take effect within 30 days or, if suspended by the APSC as allowed by commission rule, approve the rider to take effect in the first billing cycle of the first month occurring 30 days after issuance of the APSC’s order approving the rider. In June 2019 the APSC suspended Entergy Arkansas’s tariff and granted Entergy Arkansas’s motion asking the APSC to establish the proceeding as the single designated proceeding in which interested parties may assert claims related to the appropriate retail rate treatment of the FERC’s October 2018 order and related FERC orders in the opportunity sales proceeding. In January 2020 the APSC adopted a procedural schedule with a hearing in April 2020. In January 2020 the Attorney General and Arkansas Electric Energy Consumers, Inc. filed a joint motion seeking to dismiss Entergy Arkansas’s application alleging that the APSC, in a prior proceeding, ruled on the issues addressed in the application and determined that Entergy Arkansas’s requested relief violates the filed rate doctrine and the prohibition against retroactive ratemaking. Entergy Arkansas responded to the joint motion in February 2020 rebutting these
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
arguments, including demonstrating that the claims in this proceeding differ substantially from those the APSC addressed previously and that the payment resulting from a FERC tariff violation for which Entergy Arkansas seeks retail cost recovery in this proceeding differs materially from the refunds resulting from a FERC tariff amendment that the APSC previously rejected on filed rate doctrine and the retroactive ratemaking grounds. In addition, in January 2020 the Attorney General and Arkansas Electric Energy Consumers, Inc. filed testimony opposing the recovery by Entergy Arkansas of the opportunity sales payment but also claiming that certain components of the payment should be segregated and refunded to customers. In March 2020, Entergy Arkansas filed rebuttal testimony.
In July 2020 the APSC issued a decision finding that Entergy Arkansas’s application is not in the public interest. The order also directed Entergy Arkansas to refund to its retail customers within 30 days of the order the FERC-determined over-collection of $13.7 million, plus interest, associated with a recalculated bandwidth remedy. In addition to these primary findings, the order also denied the Attorney General’s request for Entergy Arkansas to prepare a compliance filing detailing all of the retail impacts from the opportunity sales and denied a request by the Arkansas Electric Energy Consumers to recalculate all costs using the revised responsibility ratio. Entergy Arkansas filed a motion for temporary stay of the 30-day requirement to allow Entergy Arkansas a reasonable opportunity to seek rehearing of the APSC order, but in July 2020 the APSC denied Entergy Arkansas’s request for a stay and directed Entergy Arkansas to refund to its retail customers the component of the total FERC-determined opportunity sales payment that was associated with increased bandwidth remedy payments of $13.7 million, plus interest. The refunds were issued in the August 2020 billing cycle. While the APSC denied Entergy Arkansas’s stay request, Entergy Arkansas believes its actions were prudent and, therefore, the costs, including the $13.7 million, plus interest, are recoverable. In July 2020, Entergy Arkansas requested rehearing of the APSC order, which rehearing was denied by the APSC in August 2020. In September 2020, Entergy Arkansas filed a complaint in the U.S. District Court for the Eastern District of Arkansas challenging the APSC’s order denying Entergy Arkansas’s request to recover the costs of these payments. In October 2020 the APSC filed a motion to dismiss Entergy Arkansas’s complaint, to which Entergy Arkansas responded. Also in December 2020, Entergy Arkansas and the APSC held a pre-trial conference, and filed a report indicatingwith the court in January 2021. The court held a hearing in February 2021 regarding issues addressed in the pre-trial conference report, and in June 2021 the court stayed all discovery until it rules on pending motions, after which the court will issue an amended schedule if necessary. In March 2022 the court denied the APSC’s motion to dismiss, and, in April 2022, issued a scheduling order including a trial date in February 2023. In June 2022, Entergy Arkansas filed a motion asserting that it is entitled to summary judgment because Entergy Arkansas’s position that the APSC’s order is pre-empted by the filed rate doctrine and violates the Dormant Commerce Clause is premised on facts that are not subject to genuine dispute. In July 2022, Arkansas Electric Energy Consumers, Inc., an industrial customer association, filed a motion to intervene and to hold Entergy Arkansas’s motion for summary judgment in abeyance pending a ruling on the motion to intervene. Entergy Arkansas filed a consolidated opposition to both motions. In August 2022 the APSC filed a motion for summary judgment arguing that there is no changesgenuine issue as to any material fact and the APSC is entitled to judgment as a matter of law. In September 2022, Entergy Louisiana’s originalArkansas filed an opposition to the motion. In October 2022 the APSC filed a motion asking the court to hold further proceedings in abeyance pending a decision on the motions for summary judgment filed by Entergy Arkansas and the APSC. Also in October 2022, Entergy Arkansas filed an opposition to the motion, and the APSC filed a reply in support of its motion for summary judgment. In January 2023 the judge assigned to the case, on her own motion, identified facts that may present a conflict and recused herself; a new judge was assigned to the case, but he also recused due to a conflict. The case again was reassigned to a new judge. In January 2023 the court denied all pending motions (including those described above) except for a motion by the APSC to exclude certain testimony and further ruled that the matter would proceed to trial. In January 2023, Arkansas Electric Energy Consumers, Inc. filed a notice of appeal of the court’s order denying its motion to intervene to the United States Court of Appeals for the Eighth Circuit and a motion with the district court to stay the proceedings pending the appeal, which was denied. In February 2023, Arkansas Electric Energy Consumers, Inc. filed a motion with the United States Court of Appeals for the Eighth District to stay the proceedings pending the appeal, which also was denied. The trial was held in February 2023. Following the trial, Entergy Arkansas filed a motion with the United States Court of Appeals for the Eighth District
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
to expedite the appeal filed by Arkansas Electric Energy Consumers, Inc. The court granted Entergy Arkansas’s request.
Net Metering Legislation
An Arkansas law was enacted effective July 2019 that, among other things, expands the definition of a “net metering customer” to include two additional types of customers: (1) customers that lease net metering facilities, subject to certain leasing arrangements, and (2) government entities or other entities exempt from state and federal income taxes that enter into a service contract for a net metering facility. The latter provision allows eligible entities, many of whom are small and large general service customers, to purchase renewable energy directly from third party providers and receive bill credits for these purchases. The APSC was given authority under this law to address certain matters, such as cost shifting and the appropriate compensation for net metered energy and initiated proceedings for this purpose. Because of the size and number of customers eligible under this new law, there is a risk of loss of load and the shifting of costs to customers. A hearing was held in December 2019, with utilities, including Entergy Arkansas, cooperatives, the Arkansas Attorney General, and industrial customers advocating the need for establishment of a reasonable rate structure that takes into account impacts to non-net metering customers; an additional hearing was conducted in February 2020 for purposes of public comment only. The APSC issued an order in June 2020, and in July 2020 several parties, including Entergy Arkansas, filed for rehearing on multiple grounds, including for the reasons that it imposes an unreasonable rate structure and allows facilities to net meter that do not meet the statutory definition of net metering facilities. After granting the rehearing requests, the APSC issued an order in September 2020 largely upholding its June 2020 order. In October 2020, Entergy Arkansas and several other parties filed an appeal of the APSC’s September 2020 order. In January 2021, Entergy Arkansas, pursuant to an APSC order, filed an updated net metering tariff, which was approved in February 2021. In May 2021, Entergy Arkansas filed a motion to dismiss its pending judicial appeal of the APSC’s September 2020 order on rehearing in the proceeding addressing its net metering rules. In June 2021 the Arkansas Court of Appeals granted the motion and dismissed Entergy Arkansas’s appeal, although other appeals of the September 2020 APSC order remained before the court. In May 2022 the court issued an order affirming the APSC’s decision in part and reversing in part. In June 2022 the APSC sought rehearing from the court with respect to the court’s ruling on a grid charge, which the court of appeals denied in July 2022. One of the cooperative appellants filed a further appeal to the Arkansas Supreme Court in July 2022, which the court decided not to hear.
Separately, as directed by the APSC general staff, the APSC opened a proceeding to compel utilities to amend their net metering tariffs to incorporate the provisions of the legislation that the APSC general staff considered “black letter law.” Entergy Arkansas, the Arkansas Attorney General, and other intervenors opposed this directive pending the development of the rules for implementation that are being considered in the separate net metering rulemaking docket. Nevertheless, reserving its rights, Entergy Arkansas has complied with the directive to amend its tariffs. Asserting procedural and due process violations, in January 2020, Entergy Arkansas and the Arkansas Attorney General separately appealed certain APSC orders in the proceeding. In December 2021 the Arkansas Court of Appeals dismissed the appeal on procedural grounds and without prejudice.
Since the enactment of the net metering legislation, the APSC has approved numerous applications allowing Entergy Arkansas customers to enter into purchase power agreements with third parties and to utilize these purchase power agreements to offset power usage by Entergy Arkansas, despite the lack of proximity between the purchase power agreement and the end-use customer. The APSC also has allowed the aggregation of accounts by net metering customers. These decisions by the APSC have created subsidies in favor of eligible net metering customers to the detriment of non-participating customers. The level of this subsidy continues to grow as additional net metering applications are approved by the APSC.
In September 2022 the APSC opened a rulemaking concerning proposed amendments to the net metering rules to address the expiration on December 31, 2022 of the automatic grandfathering of the existing net metering rate structure. Entergy Arkansas and other utility parties filed initial briefs and comments setting forth that the statute imposing the expiration of the automatic grandfathering is not ambiguous and that the APSC does not have
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
the authority to extend the grandfathering period, and the hearing was held in October 2022. In December 2022 the APSC issued an order attempting to modify the net metering rules and purporting to allow for the potential for grandfathering after December 31, 2022. More than thirty applicants filed individual net metering applications in December 2022 seeking to be considered under the APSC’s order, although the APSC issued an order in January 2023 holding those applications in abeyance. Several parties, including Entergy Arkansas, sought rehearing, and the Arkansas’s Governor’s executive order limiting new rulemakings calls into question how the APSC’s order to adopt new rules may be effectuated.
Also in September 2022 the APSC opened another proceeding to investigate the issue of potential cost shifting arising as a result of net metering. Investor owned utilities and some cooperatives were required to make and did make filings in October 2022 with supporting documentation as to the amount and extent of cost shifting and the manner in which they would design tariffs to recover those costs on behalf of non-net metering customers. Responses to the utility and cooperative filings were filed in January 2023, and utilities filed their further responses in February 2023.
COVID-19 Orders
In April 2020, in light of the COVID-19 pandemic, the APSC issued an order requiring utilities, to the extent they had not already done so, to suspend service disconnections during the remaining pendency of the Arkansas Governor’s emergency declaration or until the APSC rescinds the directive. The order also authorized utilities to establish a regulatory asset to record costs resulting from the suspension of service disconnections, directed that in future proceedings the APSC will consider whether the request for recovery of these regulatory assets is reasonable and necessary, and required utilities to track and report the costs and any savings directly attributable to suspension of disconnects. In May 2020 the APSC approved Entergy Arkansas expanding deferred payment agreements to assist customers during the COVID-19 pandemic. Quarterly reporting began in August 2020 and the APSC ordered additional reporting in October 2020 regarding utilities’ transitional plans for ending the moratorium on service disconnects. In March 2021 the APSC issued an order confirming the lifting of the moratorium on service disconnects effective in May 2021. In August 2021 the APSC general staff filed a report recommending that utilities with a formula rate plan evaluation report were required but reserved for several issues, including Entergy Louisiana’s September 2017 update todiscontinue capturing any additional direct costs and savings as a regulatory asset and seek cost recovery through the formula rate plan. The APSC general staff further recommended that uncollectible amounts should be determined as of the end of its write-off period, approximately December 2021, and recovered in the next formula rate plan evaluation report.filing over one year. In July 2018,November 2021 the APSC found the APSC general staff’s recommendation to be premature and asked utilities to report on the continued need for a regulatory asset. Entergy LouisianaArkansas reported a continued need for a regulatory asset due to a variety of factors including the unusually long terms of the customer delayed payment agreements. As of December 31, 2022, Entergy Arkansas had a regulatory asset of $39 million for costs associated with the COVID-19 pandemic.
Remaining Useful Lives Review
In response to recent legislation, the APSC opened a proceeding in December 2022 to establish a procedure to evaluate life extensions of all utility generation units and opened a separate docket to evaluate life extensions for White Bluff, Independence, and Lake Catherine. In January 2023, Entergy Arkansas and one other party filed for rehearing of the order in the general proceeding, and Entergy Arkansas moved to dismiss the separate docket. In February 2023 the APSC granted rehearing in the general proceeding. For additional discussion related to these plants, see “Regulation of Entergy’s Business - Environmental Regulation - National Ambient Air Quality Standards - Regional Haze” in Part I, Item 1.
Federal Regulation
See the “Rate, Cost-recovery, and Other Regulation– Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Nuclear Matters
Entergy Arkansas owns and, through an affiliate, operates the ANO 1 and 2 nuclear power plants. Entergy Arkansas is, therefore, subject to the risks related to owning and operating nuclear plants. These include risks related to: the use, storage, and handling and disposal of high-level and low-level radioactive materials; the substantial financial requirements, both for capital investments and operational needs, to position Entergy’s nuclear fleet to meet its operational goals; the performance and capacity factors of these nuclear plants including the financial requirements to address emerging issues related to equipment reliability; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license amendments, and decommissioning; the availability of interim or permanent sites for the disposal of spent nuclear fuel and nuclear waste, including the fees charged for such disposal; the sufficiency of nuclear decommissioning trust fund assets and earnings to complete decommissioning of each site when required; and limitations on the amounts and types of insurance commercially available for losses in connection with nuclear plant operations and catastrophic events such as a nuclear accident. In the event of an unanticipated early shutdown of either ANO 1 or 2, Entergy Arkansas may be required to file with the APSC a rate mechanism to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. ANO 1’s operating license expires in 2034 and ANO 2’s operating license expires in 2038.
Environmental Risks
Entergy Arkansas’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Arkansas is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of Entergy Arkansas’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the LPSC staff filed an unopposed joint report setting forthpotential for future changes in the assumptions and measurements that could produce estimates that would have a correctionmaterial effect on the presentation of Entergy Arkansas’s financial position or results of operations.
Nuclear Decommissioning Costs
See “Nuclear Decommissioning Costs” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.
Utility Regulatory Accounting
See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Impairment of Long-lived Assets
See “Impairment of Long-lived Assets” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the impairment of long-lived assets.
Taxation and Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.
Qualified Pension and Other Postretirement Benefits
Entergy Arkansas’s qualified pension and other postretirement reported costs, as described in Note 11 to the annualizationfinancial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Costs and Sensitivities
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2023 Qualified Pension Cost | | Impact on 2022 Qualified Projected Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $1,301 | | $26,969 |
| Rate of return on plan assets | | (0.25%) | | $2,600 | | $— |
| Rate of increase in compensation | | 0.25% | | $1,081 | | $5,122 |
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2023 Postretirement Benefit Cost | | Impact on 2022 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $78 | | $4,097 |
| Health care cost trend | | 0.25% | | $287 | | $3,365 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Costs and Employer Contributions
Total qualified pension cost for Entergy Arkansas in 2022 was $74.8 million, including $36.4 million in settlement costs. Entergy Arkansas anticipates 2023 qualified pension cost to be $34.1 million. Entergy Arkansas contributed $93 million to its qualified pension plans in 2022 and estimates pension contributions will be approximately $54.5 million in 2023, although the 2023 required pension contributions will be known with more certainty when the January 1, 2023 valuations are completed, which is expected by April 1, 2023.
Total other postretirement health care and life insurance benefit income for Entergy Arkansas in 2022 was $5.7 million. Entergy Arkansas expects 2023 postretirement health care and life insurance benefit income of approximately $1.9 million. Entergy Arkansas contributed $1.6 million to its other postretirement plans in 2022 and estimates 2023 contributions will be approximately $526 thousand.
Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the member and Board of Directors of
Entergy Arkansas, LLC and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy Arkansas, LLC and Subsidiaries (the “Company”) as of December 31, 2022 and 2021, the related consolidated statements of income, cash flows and changes in equity (pages 340 through 344 and applicable items in pages 53 through 245), for each of the three years in the period ended December 31, 2022, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Rate and Regulatory Matters —Entergy Arkansas, LLC and Subsidiaries — Refer to Note 2 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Arkansas Public Service Commission (the “APSC”), which has jurisdiction with respect to the rates of electric companies in Arkansas, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.
The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the APSC and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the APSC and the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs, including costs related to the Opportunity Sales Proceeding and refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the APSC and the FERC, involved specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and significant auditor judgment to evaluate management estimates and the subjectivity of audit evidence.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the APSC and the FERC included the following, among others:
•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 Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
• We read relevant regulatory orders issued by the APSC and the FERC for the Company, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the APSC’s 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.
• For regulatory matters in process, including the Opportunity Sales Proceeding, we inspected the Company’s filings with the APSC and the FERC, including the annual formula rate plan filing, and considered the filings with the APSC and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.
• We obtained an analysis from management and support 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 not yet addressed in a regulatory order, including the Opportunity Sales Proceeding, to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 24, 2023
We have served as the Company’s auditor since 2001.
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | |
| | | For the Years Ended December 31, |
| | | 2022 | | 2021 | | 2020 |
| | | (In Thousands) |
| | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | | $2,673,194 | | | $2,338,590 | | | $2,084,494 | |
| | | | | | |
| OPERATING EXPENSES | | | | | | |
| Operation and Maintenance: | | | | | | |
| Fuel, fuel-related expenses, and gas purchased for resale | | 640,344 | | | 347,166 | | | 271,896 | |
| Purchased power | | 201,726 | | | 280,504 | | | 187,690 | |
| Nuclear refueling outage expenses | | 53,438 | | | 51,141 | | | 55,737 | |
| Other operation and maintenance | | 754,293 | | | 687,418 | | | 669,518 | |
| Decommissioning | | 82,326 | | | 77,696 | | | 73,319 | |
| Taxes other than income taxes | | 136,565 | | | 127,249 | | | 121,057 | |
| Depreciation and amortization | | 386,272 | | | 361,479 | | | 338,029 | |
| Other regulatory charges (credits) - net | | (89,418) | | | (31,501) | | | (35,310) | |
| TOTAL | | 2,165,546 | | | 1,901,152 | | | 1,681,936 | |
| | | | | | |
| OPERATING INCOME | | 507,648 | | | 437,438 | | | 402,558 | |
| | | | | | |
| OTHER INCOME | | | | | | |
| Allowance for equity funds used during construction | | 17,787 | | | 15,273 | | | 15,019 | |
| Interest and investment income | | 19,554 | | | 76,953 | | | 35,579 | |
| Miscellaneous - net | | (27,348) | | | (22,278) | | | (21,908) | |
| TOTAL | | 9,993 | | | 69,948 | | | 28,690 | |
| | | | | | |
| INTEREST EXPENSE | | | | | | |
| Interest expense | | 150,928 | | | 140,348 | | | 144,834 | |
| Allowance for borrowed funds used during construction | | (7,070) | | | (6,641) | | | (6,595) | |
| TOTAL | | 143,858 | | | 133,707 | | | 138,239 | |
| | | | | | |
| INCOME BEFORE INCOME TAXES | | 373,783 | | | 373,679 | | | 293,009 | |
| | | | | | |
| Income taxes | | 80,896 | | | 75,195 | | | 47,777 | |
| | | | | | |
| NET INCOME | | 292,887 | | | 298,484 | | | 245,232 | |
| | | | | | |
| Net loss attributable to noncontrolling interest | | (4,358) | | | (18,092) | | | — | |
| | | | | | |
| EARNINGS APPLICABLE TO MEMBER'S EQUITY | | $297,245 | | | $316,576 | | | $245,232 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | |
| | | For the Years Ended December 31, |
| | | 2022 | | 2021 | | 2020 |
| | | (In Thousands) |
| | | | | | |
| OPERATING ACTIVITIES | | | | | | |
| Net income | | $292,887 | | | $298,484 | | | $245,232 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 532,291 | | | 503,539 | | | 490,457 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 78,958 | | | 100,459 | | | 87,019 | |
| Changes in assets and liabilities: | | | | | | |
| Receivables | | (73,579) | | | 17,682 | | | (24,507) | |
| Fuel inventory | | (252) | | | (7,081) | | | (10,066) | |
| Accounts payable | | 64,944 | | | 27,967 | | | (22,773) | |
| Taxes accrued | | 10,936 | | | 7,753 | | | 6 | |
| Interest accrued | | 1,708 | | | (5,637) | | | (43) | |
| Deferred fuel costs | | (31,009) | | | (162,458) | | | (1,186) | |
| Other working capital accounts | | (29,789) | | | (53,343) | | | (11,061) | |
| Provisions for estimated losses | | 2,914 | | | 6,915 | | | 6,289 | |
| Other regulatory assets | | (120,603) | | | 142,706 | | | (165,534) | |
| Other regulatory liabilities | | (264,054) | | | 21,066 | | | 106,878 | |
| | | | | | |
| Pension and other postretirement liabilities | | (67,783) | | | (175,863) | | | 42,576 | |
| Other assets and liabilities | | 302,163 | | | (172,973) | | | (83,469) | |
| Net cash flow provided by operating activities | | 699,732 | | | 549,216 | | | 659,818 | |
| INVESTING ACTIVITIES | | | | | | |
| Construction expenditures | | (785,168) | | | (722,628) | | | (775,595) | |
| Allowance for equity funds used during construction | | 17,787 | | | 15,273 | | | 15,019 | |
| Nuclear fuel purchases | | (98,635) | | | (84,302) | | | (100,678) | |
| Proceeds from sale of nuclear fuel | | 37,198 | | | 16,279 | | | 30,638 | |
| | | | | | |
| Proceeds from nuclear decommissioning trust fund sales | | 248,191 | | | 530,628 | | | 321,360 | |
| Investment in nuclear decommissioning trust funds | | (269,497) | | | (524,783) | | | (336,392) | |
| Payment for purchase of assets | | (1,044) | | | (131,770) | | | (5,988) | |
| Changes in money pool receivable - net | | — | | | 3,110 | | | (3,110) | |
| | | | | | |
| | | | | | |
| | | | | | |
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | — | | | — | | | 55,001 | |
| | | | | | |
| | | | | | |
| Other | | (1,626) | | | — | | | 4,036 | |
| Net cash flow used in investing activities | | (852,794) | | | (898,193) | | | (795,709) | |
| FINANCING ACTIVITIES | | | | | | |
| Proceeds from the issuance of long-term debt | | 232,731 | | | 719,284 | | | 1,071,121 | |
| Retirement of long-term debt | | (28,521) | | | (728,917) | | | (632,175) | |
| | | | | | |
| Capital contributions from noncontrolling interest | | — | | | 51,202 | | | — | |
| | | | | | |
| Changes in money pool payable - net | | 40,891 | | | 139,904 | | | (21,634) | |
| | | | | | |
| | | | | | |
| Common equity distributions paid | | (86,000) | | | (50,000) | | | (95,000) | |
| | | | | | |
| Other | | (13,676) | | | 38,291 | | | 2,188 | |
| Net cash flow provided by financing activities | | 145,425 | | | 169,764 | | | 324,500 | |
| Net increase (decrease) in cash and cash equivalents | | (7,637) | | | (179,213) | | | 188,609 | |
| Cash and cash equivalents at beginning of period | | 12,915 | | | 192,128 | | | 3,519 | |
| Cash and cash equivalents at end of period | | $5,278 | | | $12,915 | | | $192,128 | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | |
| Cash paid (received) during the period for: | | | | | | |
| Interest - net of amount capitalized | | $147,060 | | | $143,561 | | | $140,735 | |
| Income taxes | | ($2,753) | | | ($18,933) | | | ($21,971) | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
| | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | |
| | | December 31, |
| | | 2022 | | 2021 |
| | | (In Thousands) |
| | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | | $1,911 | | | $8,155 | |
| Temporary cash investments | | 3,367 | | | 4,760 | |
| Total cash and cash equivalents | | 5,278 | | | 12,915 | |
| | | | |
| Accounts receivable: | | | | |
| Customer | | 140,513 | | | 154,412 | |
| Allowance for doubtful accounts | | (6,528) | | | (13,072) | |
| Associated companies | | 45,336 | | | 29,587 | |
| Other | | 101,096 | | | 51,064 | |
| Accrued unbilled revenues | | 116,816 | | | 101,663 | |
| Total accounts receivable | | 397,233 | | | 323,654 | |
| | | | |
| Deferred fuel costs | | 139,739 | | | 108,862 | |
| Fuel inventory - at average cost | | 51,144 | | | 50,892 | |
| Materials and supplies - at average cost | | 288,260 | | | 247,980 | |
| Deferred nuclear refueling outage costs | | 56,443 | | | 65,318 | |
| | | | |
| | | | |
| Prepayments and other | | 26,576 | | | 14,863 | |
| | | | |
| TOTAL | | 964,673 | | | 824,484 | |
| | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | |
| Decommissioning trust funds | | 1,199,860 | | | 1,438,416 | |
| | | | |
| Other | | 2,414 | | | 947 | |
| TOTAL | | 1,202,274 | | | 1,439,363 | |
| | | | |
| UTILITY PLANT | | | | |
| Electric | | 14,077,844 | | | 13,578,297 | |
| | | | |
| Construction work in progress | | 417,244 | | | 241,127 | |
| Nuclear fuel | | 176,174 | | | 182,055 | |
| TOTAL UTILITY PLANT | | 14,671,262 | | | 14,001,479 | |
| Less - accumulated depreciation and amortization | | 5,729,304 | | | 5,472,296 | |
| UTILITY PLANT - NET | | 8,941,958 | | | 8,529,183 | |
| | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | |
| Regulatory assets: | | | | |
| | | | |
| Other regulatory assets | | 1,810,281 | | | 1,689,678 | |
| Deferred fuel costs | | 68,883 | | | 68,751 | |
| Other | | 18,507 | | | 13,660 | |
| TOTAL | | 1,897,671 | | | 1,772,089 | |
| | | | |
| TOTAL ASSETS | | $13,006,576 | | | $12,565,119 | |
| | | | |
| See Notes to Financial Statements. | | | | |
| | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | |
| | | December 31, |
| | | 2022 | | 2021 |
| | | (In Thousands) |
| | | | |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | | $290,000 | | | $— | |
| | | | |
| Accounts payable: | | | | |
| Associated companies | | 276,362 | | | 217,310 | |
| Other | | 310,339 | | | 190,476 | |
| Customer deposits | | 102,799 | | | 92,511 | |
| Taxes accrued | | 100,526 | | | 89,590 | |
| | | | |
| Interest accrued | | 18,816 | | | 17,108 | |
| | | | |
| | | | |
| Other | | 43,394 | | | 38,901 | |
| TOTAL | | 1,142,236 | | | 645,896 | |
| | | | |
| NON-CURRENT LIABILITIES | | | | |
| Accumulated deferred income taxes and taxes accrued | | 1,498,234 | | | 1,416,201 | |
| Accumulated deferred investment tax credits | | 28,472 | | | 29,299 | |
| Regulatory liability for income taxes - net | | 435,157 | | | 431,655 | |
| Other regulatory liabilities | | 475,758 | | | 743,314 | |
| Decommissioning | | 1,472,736 | | | 1,390,410 | |
| Accumulated provisions | | 79,998 | | | 77,084 | |
| Pension and other postretirement liabilities | | 118,020 | | | 185,789 | |
| Long-term debt | | 3,876,500 | | | 3,958,862 | |
| Other | | 97,650 | | | 110,754 | |
| TOTAL | | 8,082,525 | | | 8,343,368 | |
| | | | |
| Commitments and Contingencies | | | | |
| | | | |
| | | | |
| | | | |
| EQUITY | | | | |
| Member's equity | | 3,753,990 | | | 3,542,745 | |
| Noncontrolling interest | | 27,825 | | | 33,110 | |
| TOTAL | | 3,781,815 | | | 3,575,855 | |
| | | | |
| TOTAL LIABILITIES AND EQUITY | | $13,006,576 | | | $12,565,119 | |
| | | | |
| See Notes to Financial Statements. | | | | |
| | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| For the Years Ended December 31, 2022, 2021, and 2020 |
| | | | | |
| | Noncontrolling Interest | | Member's Equity | | Total |
| | (In Thousands) |
| | | | | |
| Balance at December 31, 2019 | $— | | | $3,125,937 | | | $3,125,937 | |
| Net income | — | | | 245,232 | | | 245,232 | |
| | | | | |
| | | | | |
| Common equity distributions | — | | | (95,000) | | | (95,000) | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Balance at December 31, 2020 | $— | | | $3,276,169 | | | $3,276,169 | |
| Net income (loss) | (18,092) | | | 316,576 | | | 298,484 | |
| | | | | |
| | | | | |
| Common equity distributions | — | | | (50,000) | | | (50,000) | |
| | | | | |
| | | | | |
| Capital contributions from noncontrolling interest | 51,202 | | | — | | | 51,202 | |
| | | | | |
| Balance at December 31, 2021 | $33,110 | | | $3,542,745 | | | $3,575,855 | |
| Net income (loss) | (4,358) | | | 297,245 | | | 292,887 | |
| | | | | |
| | | | | |
| Common equity distributions | — | | | (86,000) | | | (86,000) | |
| | | | | |
| | | | | |
| | | | | |
| Distributions to noncontrolling interest | (927) | | | — | | | (927) | |
| | | | | |
| Balance at December 31, 2022 | $27,825 | | | $3,753,990 | | | $3,781,815 | |
| | | | | |
| See Notes to Financial Statements. | | | | | |
ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
2022 Compared to 2021
Net Income
Net income increased $201.9 million primarily due to the net effects of Entergy Louisiana’s storm cost securitization, including a $290 million reduction in income tax expense, partially offset by a $224.4 million ($165.4 million net-of-tax) regulatory charge to reflect its obligation to share the benefits of the securitization with customers. Also contributing to the net income increase was higher volume/weather and higher retail electric price, partially offset by higher other operation and maintenance expenses, higher depreciation and amortization expenses, lower other income, higher interest expense, and higher taxes other than income taxes. See Note 2 to the financial statements for further discussion of the securitization.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 2022 to 2021:
| | | | | |
| Amount |
| (In Millions) |
| 2021 operating revenues | $5,068.4 | |
| Fuel, rider, and other revenues that do not significantly affect net income | 1,013.0 | |
| Retail electric price | 111.7 | |
| Volume/weather | 108.2 | |
| Storm restoration carrying costs | 37.5 | |
| 2022 operating revenues | $6,338.8 | |
Entergy Louisiana’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.
The retail electric price variance is primarily due to increases in formula rate plan revenues, including increases in the distribution and transmission recovery mechanisms, effective September 2021 and September 2022. See Note 2 to the financial statements for further discussion of the formula rate plan proceedings.
The volume/weather variance is primarily due to an increase of 2,934 GWh, or 5%, in electricity usage across all customer classes, including the effect of whichmore favorable weather on residential sales. The increase in commercial usage was primarily due to the effect of the COVID-19 pandemic on businesses in 2021. The increase in industrial usage was primarily due to an increase in demand from expansion projects, primarily in the chemicals, petroleum refining, and transportation industries, an increase in demand from cogeneration and small industrial customers, and an increase in demand from existing customers, primarily in the chemicals and pulp and paper industries as a net $3.5 million revenue requirement reduction and indicating that there are no outstanding issues withresult of prior year temporary plant shutdowns. The increased usage from these industrial customers has a relatively smaller effect on operating revenues because a larger portion of the 2016 formula rate plan report, the supplemental report, or the interim updates. In September 2018 the LPSC approved the unopposed joint report.revenues from those customers comes from fixed charges.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Formula Rate Plan Extension Through 2019 Test Year
In August 2017,Total electric energy sales for Entergy Louisiana filed a request with the LPSC seeking to extend its formula rate plan for three years (2017-2019) with limited modifications to its terms. In April 2018, the LPSC approved an unopposed joint motion filed by Entergy Louisiana and the LPSC staff that settles the matter and extends 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, some of the more 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 yearyears ended December 31, 2022 and 2021 are as follows:
| | | | | | | | | | | | | | | | | |
| 2022 | | 2021 | | % Change |
| (GWh) | | |
| Residential | 14,119 | | | 13,445 | | | 5 | |
| Commercial | 10,927 | | | 10,388 | | | 5 | |
| Industrial | 31,666 | | | 29,978 | | | 6 | |
| Governmental | 820 | | | 787 | | | 4 | |
| Total retail | 57,532 | | | 54,598 | | | 5 | |
| Sales for resale: | | | | | |
| Associated companies | 5,416 | | | 4,950 | | | 9 | |
| Non-associated companies | 3,423 | | | 2,764 | | | 24 | |
| Total | 66,371 | | | 62,312 | | | 7 | |
See Note 19 to the financial statements for the St. Charles Power Station when it enters commercial operation;additional discussion of Entergy Louisiana’s operating revenues.
a 9.8% target earned return on common equity for the 2018
Other Income Statement Variances
Other operation and 2019 test years;maintenance expenses increased primarily due to:
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•an increase of $35$27.7 million for the 2018 evaluation period,in power delivery expenses primarily due to higher vegetation maintenance costs, higher reliability costs, and $70 million for the cumulative 2018higher safety 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.
Entergy Louisiana has indicated its intent to seek an extension of its formula rate plan on terms similar to the existing terms.
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 increasedtraining costs, partially offset by a total of $98 milliondecrease in meter reading expenses as a result of the evaluation reportdeployment of advanced metering systems;
•an increase of $19 million in nuclear generation expenses primarily due to adjustmentsa higher scope of work performed in 2022 as compared to 2021 and higher nuclear labor costs;
•an increase of $10.3 million in bad debt expense, primarily due to the additional capacity and MISO cost recovery mechanismsdeferral in 2021 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 changesbad debt expense resulting from the 2016 test year formula rate plan proceedings, a decreaseCOVID-19 pandemic. See Note 2 to the transmission recovery mechanism to reflect lower actual capital additions, and a decrease to evaluation period expenses to reflect the termsfinancial statements for discussion 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 adjustmentsregulatory activity associated with the returnCOVID-19 pandemic;
•an increase of excess accumulated deferred$9.8 million due to a $14.8 million gain on the sale of a pipeline recorded in 2021 as compared to a $5 million contingent gain recorded on the 2021 sale in 2022;
•an increase of $7.5 million in customer service center support costs primarily due to higher contract costs;
•an increase of $6.6 million in non-nuclear generation expenses primarily due to higher costs associated with materials and supplies in 2022 as compared to 2021;
•an increase of $5.1 million in loss provisions;
•an increase of $4.8 million in energy efficiency expenses due to the timing of recovery from customers, partially offset by lower energy efficiency costs; and
•several individually insignificant items.
Taxes other than income taxes pursuantincreased primarily due to the Tax Actincreases in franchise taxes, increases in employment taxes, and the treatment of accumulated deferred incomeincreases in ad valorem taxes relatedresulting from higher assessments.
Depreciation and amortization expenses increased primarily due to reductions of rate base; 2) Entergy Louisiana’s reservation regarding treatment of a regulatory asset relatedadditions 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.plant in service.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Other regulatory charges (credits) - net includes a regulatory charge of $224 million, recorded in second quarter 2022, to reflect Entergy Louisiana’s obligation to provide credits to its customers in recognition of obligations related to an LPSC ancillary order issued in the Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida securitization regulatory proceeding. See Note 2 to the financial statements for discussion of the securitization. In addition, Entergy Louisiana also includedrecords a regulatory charge or credit for the difference between asset retirement obligation-related expenses and nuclear decommissioning trust earnings plus asset retirement obligation related costs collected in its filing revenue.
Other income decreased primarily due to:
•changes in decommissioning trust fund activity, including portfolio rebalancing of the decommissioning trust funds in 2022 and 2021; and
•a presentation$31.6 million charge for the LURC’s 1% beneficial interest in the storm trust established as part of an initial proposal to combine the legacy Entergy LouisianaHurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, 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.Hurricane Ida securitization.
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.decrease was partially offset by:
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 of $58.2 million in affiliated dividend income resulting from the transmission recovery mechanism,storm trust’s investment of securitization proceeds in affiliated preferred membership interests, partially offset by reductions in the additional capacity mechanism revenue requirements and extraordinary cost items. The filing is subject to review by the LPSC. Resulting rates were implemented in September 2019, subject to refund.
Entergy Louisiana also included in its filing a presentation of an initial proposal to combine the legacy Entergy Louisiana and legacy Entergy Gulf States Louisiana residential rates, which combination, if approved, would be accomplished on a revenue-neutral basis intended not to affect the rates of other customer classes. Entergy Louisiana contemplates that any combination of residential rates resulting from this request would be implemented with the results of the 2019 test year formula rate plan filing.
Several parties intervened in the proceeding and the LPSC staff filed its report of objections/reservations in accordance with the applicable provisions of the formula rate plan. In its report the LPSC staff re-urged reservations with respect to the outstanding issues from the 2017 test year formula rate plan filing and disputed the inclusion of certain affiliate costs for test years 2017 and 2018. The LPSC staff objected to Entergy Louisiana’s proposal to combine residential rates but proposed the setting of a status conference to establish a procedural schedule to more fully address the issue. The LPSC staff also reserved its right to object to the treatment of the sale of Willow Glen reflected in the evaluation report and to the August 2019 compliance update, which was made primarily to update the capital additions reflected in the formula rate plan’s transmission recovery mechanism, based on limited time to review it. Additionally, since the completion of certain transmission projects, the LPSC staff has issued supplemental data requests addressing the prudenceliquidation of Entergy Louisiana’s expendituresinvestment in affiliated preferred membership interests acquired in connection with those projects. Entergy Louisiana isprevious securitizations of storm restoration costs; and
•an increase of $16.8 million due to the recognition of storm restoration carrying costs, primarily related to Hurricane Ida.
See Note 2 to the financial statements for discussion of the securitization.
Interest expense increased primarily due to:
•the issuances of $500 million of 2.35% Series mortgage bonds and $500 million of 3.10% Series mortgage bonds, each in March 2021;
•the processissuance of responding$1 billion of 0.95% Series mortgage bonds in October 2021;
•the $1.2 billion unsecured term loan drawn in January 2022. The term loan was repaid in June 2022; and
•the issuance of $500 million of 4.75% Series mortgage bonds in August 2022.
The increase was partially offset by the repayment of $200 million of 4.8% Series mortgage bonds in May 2021.
The effective income tax rates were (23.5%) for 2022 and 15.5% for 2021. See Note 3 to those requests.the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates, and for additional discussion regarding income taxes.
Investigation2021 Compared to 2020
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results 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 includedOperations” in the retail ratesItem 7 of Entergy Louisiana. As stated inLouisiana’s Annual Report on Form 10-K for the noticeyear ended December 31, 2021, filed with the SEC on February 25, 2022, for discussion of proceeding,results of operations for 2021 compared to 2020.
Income Tax Legislation
See the LPSC observed an increase in capital construction-related costs incurred by“Income Tax Legislation” section of Entergy Services. Discovery was issuedCorporation and included efforts to seek highly detailed information on a broad range of matters unrelated to the scopeSubsidiaries Management’s Financial Discussion and Analysis for discussion of the audit. There has been no further activity in the investigation since May 2019.Inflation Reduction Act of 2022.
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
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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
Cash Flow
Cash flows for the conduct of its contractoryears ended December 31, 2022, 2021, and subcontractor and, therefore, recommended a disallowance of $672020 were as follows:
| | | | | | | | | | | | | | | | | |
| | 2022 | | 2021 | | 2020 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period | $18,573 | | | $728,020 | | | $2,006 | |
| | | | | |
| Net cash provided by (used in): | | | | | |
| Operating activities | 1,177,508 | | | 1,052,526 | | | 1,072,986 | |
| Investing activities | (4,707,711) | | | (3,700,199) | | | (1,944,671) | |
| Financing activities | 3,568,243 | | | 1,938,226 | | | 1,597,699 | |
| Net increase (decrease) in cash and cash equivalents | 38,040 | | | (709,447) | | | 726,014 | |
| | | | | |
| Cash and cash equivalents at end of period | $56,613 | | | $18,573 | | | $728,020 | |
2022 Compared to 2021
Operating Activities
Net cash flow provided by operating activities increased $125 million in capital costs. Additionally, the ALJ concluded that Entergy Louisiana did not sufficiently justify the incurrence2022 primarily due to:
•a decrease of $2$221.9 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 progressstorm spending, primarily due to Hurricane Ida, Hurricane Laura, Hurricane Delta, and Hurricane Zeta restoration efforts in 2021;
•an increase of the proceeding in light of the ALJ recommendation, Entergy Louisiana recorded in the fourth quarter 2015 approximately $77$64 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 settlementincome tax refunds 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 million2022 as a result of an intercompany income tax allocation agreement; and
•higher collections from customers.
The increase was partially offset by:
•increased fuel costs. See Note 2 to the settlement approvedfinancial statements for a discussion of fuel and purchased power cost recovery;
•an increase of $23.5 million in spending on nuclear refueling outages;
•an increase of $15.8 million in interest paid in 2022; and
•payments to vendors, including timing and an increase in cost of operations.
Investing Activities
Net cash flow used in investing activities increased $1,007.5 million in 2022 primarily due to:
•an increase in investments in affiliates due to the $3,163.6 million purchase by the LPSC was made to customers in January 2017. Ofstorm trust of preferred membership interests issued by an Entergy affiliate, partially offset by the $71$1,390.6 million redemption of refunds, $68 million was credited to customers through Entergy Louisiana’s formula rate plan, outside of sharing, and $3 million through its fuel adjustment clause. Entergy Louisiana had previously recorded a provision of $48 million for this refund. The previously-recorded provision included the cumulative revenues recorded through December 2016 relatedpreferred membership interests. See Note 2 to the $67 million of disallowed plant. An additional regulatory charge of $23 million was recorded in fourth quarter 2016 to reflect the effectsfinancial statements for a discussion of the settlement. The settlement also provided that Entergy Louisiana could retain the value associated with potential service credits agreedsecuritization;
•net payments to by the project contractor,storm reserve escrow accounts of $293.4 million in 2022;
•an increase of $100.4 million in nuclear construction expenditures primarily due to the extent they are realizedincreased spending on various nuclear projects in the future. Following2022 and higher capital expenditures for storm restoration in 2022;
•an increase of $23.1 million in non-nuclear generation construction expenditures primarily due to a review by the parties, an unopposed joint reporthigher scope of proceedings was filed by the LPSC staff and Entergy Louisianawork on projects performed in May 2017 and the LPSC accepted the joint report of proceedings resolving the matter.
Advanced Metering Infrastructure (AMI)
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 proposed2022 as compared 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 Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
•an increase of $13.3 million in information technology capital expenditures primarily due to increased spending on various technology projects in 2022; and
•an increase of $12.2 million as a result of fluctuations in nuclear fuel activity, primarily due to variations from year to year in the timing and pricing of fuel reload requirements, materials and services deliveries, and the timing of cash payments during the nuclear fuel cycle.
The increase was partially offset by:
•a decrease of $856.2 million in distribution construction expenditures primarily due to lower capital expenditures for storm restoration in 2022 and lower spending in 2022 on advanced metering infrastructure, partially offset by higher capital expenditures as a result of increased development in Entergy Louisiana’s service area, and increased investment in the reliability and infrastructure of Entergy Louisiana’s distribution system;
•a decrease of $328.5 million in transmission construction expenditures primarily due to lower capital expenditures for storm restoration in 2022;
•a decrease of $25.3 million in nuclear decommissioning trust fund activity as a result of a lump sum contribution in 2021 for amounts collected over a 17-month period. See Note 2 to the financial statements for a discussion of nuclear decommissioning expense recovery; and
•money pool activity.
Decreases in Entergy Louisiana’s receivables from the money pool are a source of cash flow, and Entergy Louisiana’s receivable from the money pool decreased $14.5 million in 2022 compared to increasing by $1.1 million in 2021. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Financing Activities
Net cash flow provided by financing activities increased $1,630 million in 2022 primarily due to:
•proceeds from securitization of $3.2 billion received by the storm trust in 2022;
•a capital contribution of $1 billion received indirectly from Entergy Corporation in May 2022 to finance the establishment of the storm escrow account for Hurricane Ida costs;
•the issuance of $500 million of 4.75% Series mortgage bonds in August 2022;
•money pool activity;
•the repayment, at maturity, of $200 million of 4.80% Series mortgage bonds in May 2021;
•the repayment, at maturity, of Entergy Louisiana Waterford VIE’s $40 million of 3.92% Series H secured notes in February 2021; and
•higher prepaid deposits of $32 million related to contributions-in-aid-of-construction reimbursement agreements in 2022 as compared to 2021.
The increase was partially offset by:
•the issuance of $500 million of 2.35% Series mortgage bonds and $500 million of 3.10% Series mortgage bonds, each in March 2021;
•the issuance of $1 billion of 0.95% Series mortgage bonds in October 2021;
•an increase of $564 million in common equity distributions in 2022 primarily to return to Entergy Corporation the $125 million capital contribution received in December 2021 to assist in paying for costs associated with Hurricane Ida and to maintain Entergy Louisiana’s targeted capital structure;
•the repayment, prior to maturity, in May 2022 of $435 million, a portion of the outstanding principal, of 0.62% Series mortgage bonds due November 2023;
•the repayment, at maturity, of $200 million of 3.3% Series mortgage bonds in December 2022;
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
•net repayments of $75 million in 2022 compared to net borrowings of $125 million in 2021 on Entergy Louisiana’s revolving credit facility;
•a capital contribution of $125 million received from Entergy Corporation in December 2021 in order to assist in paying costs associated with Hurricane Ida; and
•net repayments of long-term borrowings of $8.4 million in 2022 compared to net long-term borrowings of $24.1 million in 2021 on the nuclear fuel company variable interest entities’ credit facilities.
Increases in Entergy Louisiana’s payable to the money pool are a source of cash flow, and Entergy Louisiana’s payable to the money pool increased $226.1 million in 2022.
See Note 5 to the financial statements for details of long-term debt.
2021 Compared to 2020
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Louisiana’s Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 25, 2022, for discussion of operating, investing, and financing cash flow activities for 2021 compared to 2020.
Capital Structure
Entergy Louisiana’s debt to capital ratio is shown in the following table. The decrease in the debt to capital ratio for Entergy Louisiana is primarily due to the $1.0 billion capital contribution received indirectly from Entergy Corporation in May 2022.
| | | | | | | | | | | |
| | December 31,
2022 | | December 31,
2021 |
| Debt to capital | 53.0 | % | | 57.2 | % |
| | | |
| | | |
| Effect of subtracting cash | (0.1 | %) | | 0.0 | % |
| Net debt to net capital (non-GAAP) | 52.9 | % | | 57.2 | % |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and common equity. Net capital consists of capital less cash and cash equivalents. Entergy Louisiana uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Louisiana’s financial condition. The net debt to net capital ratio is a non-GAAP measure. Entergy Louisiana also uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Louisiana’s financial condition because net debt indicates Entergy Louisiana’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Louisiana seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a distribution, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Louisiana may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reducing distributions, Entergy Louisiana may receive equity contributions to maintain its capital structure.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Uses of Capital
Entergy Louisiana requires capital resources for:
•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.
Following are the amounts of Entergy Louisiana’s planned construction and other capital investments.
| | | | | | | | | | | | | | | | | |
| | 2023 | | 2024 | | 2025 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation | $405 | | | $435 | | | $1,305 | |
| Transmission | 245 | | | 545 | | | 490 | |
| Distribution | 445 | | | 545 | | | 635 | |
| Utility Support | 175 | | | 110 | | | 120 | |
| Total | $1,270 | | | $1,635 | | | $2,550 | |
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Louisiana includes specific investments in generation projects to modernize, decarbonize, and diversify Entergy Louisiana’s portfolio, including the St. Jacques Facility; investments in River Bend and Waterford 3; distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to drive reliability and resilience while also supporting renewables expansion; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, government actions, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.
While Entergy Louisiana is still assessing the effect on its planned solar projects, the investigation by the U.S. Department of Commerce into potential circumvention of duties and tariffs may result in increased duties or tariffs on imported solar panels and has exacerbated previously existing supply chain disruptions, which have negatively affected the timing and cost of completion of these projects.
Following are the amounts of Entergy Louisiana’s existing debt and lease obligations (includes estimated interest payments).
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2023 | | 2024 | | 2025 | | 2026-2027 | | After 2027 |
| | (In Millions) |
| Long-term debt (a) | $1,362 | | | $2,029 | | | $655 | | | $1,733 | | | $10,288 | |
| Operating leases (b) | $15 | | | $12 | | | $10 | | | $10 | | | $2 | |
| Finance leases (b) | $5 | | | $4 | | | $4 | | | $5 | | | $2 | |
| | | | | | | | | |
(a)Long-term debt is discussed in Note 5 to the financial statements.
(b)Lease obligations are discussed in Note 10 to the financial statements.
Other Obligations
Entergy Louisiana currently expects to contribute approximately $44.6 million to its qualified pension plans and approximately $15.4 million to its other postretirement health care and life insurance plans in 2023, although the 2023 required pension contributions will be known with more certainty when the January 1, 2023 valuations are
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
completed, which is expected by April 1, 2023. See “Critical Accounting Estimates- Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Entergy Louisiana has $21.9 million of unrecognized tax benefits net of unused tax attributes plus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition, Entergy Louisiana enters into fuel and purchased power agreements that contain minimum purchase obligations. Entergy Louisiana has rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations. See Note 8 to the financial statements for discussion of Entergy Louisiana’s obligations under the Unit Power Sales Agreement and the Vidalia purchased power agreement.
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Louisiana pays distributions from its earnings at a percentage determined monthly.
2021 Solar Certification and the Geaux Green Option
In November 2021, Entergy Louisiana filed an application with the LPSC seeking certification of and approval for the addition of four new solar photovoltaic resources with a combined nameplate capacity of 475 megawatts (the 2021 Solar Portfolio) and the implementation of a new green tariff, the Geaux Green Option (Rider GGO). The 2021 Solar Portfolio consists of four resources that are expected to provide $242 million in net benefits to Entergy Louisiana’s customers. These resources, all of which would be constructed in Louisiana, include (i) the Vacherie Facility, a 150 megawatt resource in St. James Parish; (ii) the Sunlight Road Facility, a 50 megawatt resource in Washington Parish; (iii) the St. Jacques Facility, a 150 megawatt resource in St. James Parish; and (iv) the Elizabeth Facility, a 125 megawatt resource in Allen Parish. The St. Jacques Facility would be acquired through a build-own-transfer agreement; the remaining resources involve power purchase agreements. The Sunlight Road Facility and the Elizabeth Facility have estimated in service dates in 2024, and the Vacherie Facility and the St. Jacques Facility have estimated in service dates in 2025. The filing proposed to recover the costs of the power purchase agreements through the fuel adjustment clause and the formula rate plan and the acquisition costs through the formula rate plan.
The proposed Rider GGO is a voluntary rate schedule that will enhance Entergy Louisiana’s ability to help customers meet their sustainability goals by allowing customers to align some or all of their electricity requirements with renewable energy from the resources. Because subscription fees from Rider GGO participants would help to offset the cost of the resources, the design of Rider GGO also preserves the benefits of the 2021 Solar Portfolio for non-participants by providing them with the reliability and capacity benefits of locally-sited solar generation at a discounted price.
In March 2022 direct testimony from Walmart, the Louisiana Energy Users Group (LEUG), and the LPSC staff was filed. Each party recommended that the LPSC approve the resources proposed in Entergy Louisiana’s application, and the LPSC staff witness indicated that the process through which Entergy Louisiana solicited or obtained the proposals for the resources complied with applicable LPSC orders. The LPSC staff and LEUG’s witnesses made recommendations to modify the proposed Rider GGO and Entergy Louisiana’s proposed rate relief. In April 2022 the LPSC staff and LEUG filed cross-answering testimony concerning each other’s proposed modifications to Rider GGO and the proposed rate recovery. Entergy Louisiana filed rebuttal testimony in June 2022. In August 2022 the parties reached a settlement certifying the 2021 Solar Portfolio and approving implementation of Rider GGO. In September 2022 the LPSC approved the settlement. Following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities until the later
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
of March 2023 or the completion of an environmental and economic impact study, which is ongoing. This development may potentially affect the size and final in service dates of the Vacherie and St. Jacques facilities.
System Resilience and Storm Hardening
In December 2022, Entergy Louisiana filed an application seeking a public interest finding regarding Phase I of Entergy Louisiana’s Future Ready resilience plan and approval of a rider mechanism to recover the program’s costs. Phase I reflects the first five years of a ten-year resilience plan and includes investment of approximately $5 billion, including hardening investment, transmission dead-end structures, enhanced vegetation management, and telecommunications improvement. A procedural schedule has not yet been adopted in this docket.
Sources of Capital
Entergy Louisiana’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•the Entergy System money pool;
•storm reserve escrow accounts;
•debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations, Entergy Louisiana expects to continue, when economically feasible, to retire higher-cost debt and replace it with lower-cost debt if market conditions permit.
All debt and common and preferred membership interest issuances by Entergy Louisiana require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in its bond indentures and other agreements. Entergy Louisiana has sufficient capacity under these tests to meet its foreseeable capital needs for the next twelve months and beyond.
Entergy Louisiana’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
| | | | | | | | | | | | | | | | | | | | |
| 2022 | | 2021 | | 2020 | | 2019 |
| (In Thousands) |
| ($226,114) | | $14,539 | | $13,426 | | ($82,826) |
See Note 4 to the financial statements for a description of the money pool.
Entergy Louisiana has a credit facility in the amount of $350 million scheduled to expire in June 2027. The credit facility includes fronting commitments for the issuance of letters of credit against $15 million of the borrowing capacity of the facility. As of December 31, 2022, there were $50 million of cash borrowings and no letters of credit outstanding under the credit facility. In addition, Entergy Louisiana is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2022, $20 million in letters of credit were outstanding under Entergy Louisiana’s uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
The Entergy Louisiana nuclear fuel company variable interest entities have two separate credit facilities, each in the amount of $105 million and scheduled to expire in June 2025. As of December 31, 2022, $13.1 million of loans were outstanding under the credit facility for the Entergy Louisiana River Bend nuclear fuel company variable interest entity. As of December 31, 2022, $60.8 million in loans were outstanding under the Entergy Louisiana Waterford nuclear fuel company variable interest entity credit facility. See Note 4 to the financial statements for additional discussion of the nuclear fuel company variable interest entity credit facilities.
Entergy Louisiana had $293.4 million in its storm reserve escrow account at December 31, 2022.
Entergy Louisiana obtained authorizations from the FERC through October 2023 for the following:
•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.
See Note 4 to the financial statements for further discussion of Entergy Louisiana’s short-term borrowing limits.
Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida
In August 2020 and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of Entergy Louisiana’s service area. The storms resulted in widespread outages, significant damage to distribution and transmission infrastructure, and the loss of sales during the outages. Additionally, as a result of Hurricane Laura’s extensive damage to the grid infrastructure serving the impacted area, large portions of the underlying transmission system required nearly a complete rebuild.
In October 2020, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments in connection with the issuance of shorter-term mortgage bonds to provide interim financing for restoration costs associated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta. Subsequently, Entergy Louisiana and the LPSC staff filed a joint motion seeking approval to exclude from the derivation of Entergy Louisiana’s capital structure and cost rate of debt for ratemaking purposes, including the allowance for funds used during construction, shorter-term debt up to $1.1 billion issued by Entergy Louisiana to fund costs associated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta costs on an interim basis. In November 2020 the LPSC issued an order approving the joint motion, and Entergy Louisiana issued $1.1 billion of 0.62% Series mortgage bonds due November 2023. Also in November 2020, Entergy Louisiana withdrew $257 million from its funded storm reserves.
In February 2021 two winter storms (collectively, Winter Storm Uri) brought freezing rain and ice to Louisiana. Ice accumulation sagged or downed trees, limbs, and power lines, causing damage to Entergy Louisiana’s transmission and distribution systems. The additional weight of ice caused trees and limbs to fall into power lines and other electric equipment. When the ice melted, it affected vegetation and electrical equipment, causing additional outages. As discussed in the “Fuel and purchased power recovery” section of Note 2 to the financial statements, Entergy Louisiana recovered the incremental fuel costs associated with Winter Storm Uri over a five-month period from April 2021 through August 2021.
In April 2021, Entergy Louisiana filed an application with the LPSC relating to Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri restoration costs and in July 2021, Entergy Louisiana made a supplemental filing updating the total restoration costs. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by these storms were estimated to be approximately $2.06 billion, including approximately $1.68 billion in capital costs and approximately $380 million in non-capital costs. Including carrying costs through January 2022, Entergy Louisiana sought an LPSC determination that $2.11 billion was prudently incurred and, therefore, was eligible for recovery from customers. Additionally, Entergy Louisiana requested that the LPSC determine that re-establishment of a storm escrow account to the previously authorized
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Management’s Financial Discussion and Analysis
amount of $290 million was appropriate. In July 2021, Entergy Louisiana supplemented the application with a request regarding the financing and recovery of the recoverable storm restoration costs. Specifically, Entergy Louisiana requested approval to securitize its restoration costs pursuant to Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021.
In August 2021, Hurricane Ida caused extensive damage to Entergy Louisiana’s distribution and, to a lesser extent, transmission systems resulting in widespread power outages. In September 2021, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments in connection with the issuance of approximately $1 billion of shorter-term mortgage bonds to provide interim financing for restoration costs associated with Hurricane Ida, which bonds were issued in October 2021. Also in September 2021, Entergy Louisiana sought approval for the creation and funding of a $1 billion restricted escrow account for Hurricane Ida related restoration costs, subject to a subsequent prudence review.
After filing of testimony by the LPSC staff and intervenors, which generally supported or did not oppose Entergy Louisiana’s requests in regard to Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida, the parties negotiated and executed an uncontested stipulated settlement which was filed with the LPSC in February 2022. The settlement agreement contained the following key terms: $2.1 billion of restoration costs from Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri were prudently incurred and were eligible for recovery; carrying costs of $51 million were recoverable; a $290 million cash storm reserve should be re-established; a $1 billion reserve should be established to partially pay for Hurricane Ida restoration costs; and Entergy Louisiana was authorized to finance $3.186 billion utilizing the securitization process authorized by Act 55, as supplemented by Act 293. The LPSC issued an order approving the settlement in March 2022. As a result of the financing order, Entergy Louisiana reclassified $1.942 billion from utility plant to other regulatory assets.
In May 2022 the securitization financing closed, resulting in the issuance of $3.194 billion principal amount of bonds by Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA), a political subdivision of the State of Louisiana. The securitization was authorized pursuant to the Louisiana Utilities Restoration Corporation Act, Part VIII of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana legislature approved in 2021. The LCDA loaned the proceeds to the LURC. Pursuant to Act 293, the LURC contributed the net bond proceeds to a State legislatively authorized and LURC-sponsored trust, Restoration Law Trust I (the storm trust).
Pursuant to Act 293, the net proceeds of the bonds were used by the storm trust to purchase 31,635,718.7221 Class A preferred, non-voting membership interest units (the preferred membership interests) issued by Entergy Finance Company, LLC, a majority-owned indirect subsidiary of Entergy. Entergy Finance Company is required to make annual distributions (dividends) commencing on December 15, 2022 on the preferred membership interests issued to the storm trust. These annual dividends received by the storm trust will be distributed to Entergy Louisiana and the LURC, as beneficiaries of the storm trust. Specifically, 1% of the annual dividends received by the storm trust will be distributed to the LURC, for the benefit of customers, and 99% will be distributed to Entergy Louisiana, net of storm trust expenses. The preferred membership interests have a stated annual cumulative cash dividend rate of 7% and a liquidation price of $100 per unit. The terms of the preferred membership interests include certain financial covenants to which Entergy Finance Company is subject.
Entergy and Entergy Louisiana do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA. The bonds are secured by system restoration property, which is the right granted by law to the LURC to collect a system restoration charge from customers. The system restoration charge is adjusted at least semi-annually to ensure that it is sufficient to service the bonds. Entergy Louisiana collects the system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee. Entergy Louisiana began collecting the system restoration charge effective with the first billing cycle of June 2022 and the system restoration charge is expected to remain in place up to 15 years. Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as a billing and collection agent for the LCDA and the LURC. In the remote possibility that the system restoration charge, as well as any funds in the
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Management’s Financial Discussion and Analysis
excess subaccount and funds in the debt service reserve account, are insufficient to service the bonds resulting in a payment default, the storm trust is required to liquidate Entergy Finance Company preferred membership interests in an amount equal to what would be required to cure the default. The estimated value of this indirect guarantee is immaterial.
From the proceeds from the issuance of the preferred membership interests, Entergy Finance Company distributed $1.4 billion to its parent, Entergy Holdings Company, LLC, a company wholly-owned and consolidated by Entergy. Subsequently, Entergy Holdings Company liquidated, distributing the $1.4 billion it received from Entergy Finance Company to Entergy Louisiana as holder of 6,843,780.24 units of Class A, 4,126,940.15 units of Class B, and 2,935,152.69 units of Class C preferred membership interests. Entergy Louisiana had acquired these preferred membership interests with proceeds from previous securitizations of storm restoration costs. Entergy Finance Company loaned the remaining $1.7 billion from the preferred membership interests proceeds to Entergy which used the cash to redeem $650 million of 4.00% Series senior notes due July 2022 and indirectly contributed $1 billion to Entergy Louisiana as a capital contribution.
Entergy Louisiana used the $1 billion capital contribution to fund its Hurricane Ida escrow account and subsequently withdrew the $1 billion from the escrow account. With a portion of the $1 billion withdrawn from the escrow account and the $1.4 billion from the Entergy Holdings Company liquidation, Entergy Louisiana deposited $290 million in a restricted escrow account as a storm damage reserve for future storms, used $1.2 billion to repay its unsecured term loan due June 2023, and used $435 million to redeem a portion of its 0.62% Series mortgage bonds due November 2023.
As discussed in Note 3 to the financial statements, the securitization resulted in recognition of a reduction of income tax expense of approximately $290 million by Entergy Louisiana. Entergy’s recognition of reduced income tax expense was partially offset by other tax charges resulting in a net reduction of income tax expense of $283 million. In recognition of obligations related to an LPSC ancillary order issued as part of the securitization regulatory proceeding, Entergy Louisiana recorded a $224 million ($165 million net-of-tax) regulatory charge and a corresponding regulatory liability to reflect its obligation to share the benefits of the securitization with customers.
As discussed in Note 17 to the financial statements, Entergy Louisiana consolidates the storm trust as a variable interest entity and the LURC’s 1% beneficial interest is shown as noncontrolling interest in the financial statements. In second quarter 2022, Entergy Louisiana recorded a charge of $31.6 million in other income to reflect the LURC’s beneficial interest in the trust.
In April 2022, Entergy Louisiana filed an application with the LPSC relating to Hurricane Ida restoration costs. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by Hurricane Ida currently are estimated to be approximately $2.54 billion, including approximately $1.96 billion in capital costs and approximately $586 million in non-capital costs. Including carrying costs of $57 million through December 2022, Entergy Louisiana is seeking an LPSC determination that $2.60 billion was prudently incurred and, therefore, is eligible for recovery from customers. As part of this filing, Entergy Louisiana also is seeking an LPSC determination that an additional $32 million in costs associated with the restoration of Entergy Louisiana’s electric facilities damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta as well as Winter Storm Uri was prudently incurred. This amount is exclusive of the requested $3 million in carrying costs through December 2022. In total, Entergy Louisiana is requesting an LPSC determination that $2.64 billion was prudently incurred and, therefore, is eligible for recovery from customers. As discussed above, in March 2022 the LPSC approved financing of a $1 billion storm escrow account from which funds were withdrawn to finance costs associated with Hurricane Ida restoration. In June 2022, Entergy Louisiana supplemented the application with a request regarding the financing and recovery of the recoverable storm restoration costs. Specifically, Entergy Louisiana requested approval to securitize its restoration costs pursuant to Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021. In October 2022 the LPSC staff recommended a finding that the requested storm restoration costs of $2.64 billion, including associated carrying costs of $59.1 million, were prudently incurred and are eligible for recovery from customers. The LPSC staff further recommended approval of
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Management’s Financial Discussion and Analysis
Entergy Louisiana’s plans to securitize these costs, net of the $1 billion in funds withdrawn from the storm escrow account described above. The parties negotiated and executed an uncontested stipulated settlement which was filed with the LPSC in December 2022. The settlement agreement contains the following key terms: $2.57 billion of restoration costs from Hurricane Ida, Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri were prudently incurred and were eligible for recovery; carrying costs of $59.2 million were recoverable; and Entergy Louisiana was authorized to finance $1.657 billion utilizing the securitization process authorized by Act 55, as supplemented by Act 293. A procedural motion to consider the uncontested settlement at the December 2022 LPSC meeting did not pass and the settlement was not voted on. In January 2023 an ALJ with the LPSC conducted a settlement hearing to receive the uncontested settlement and supporting testimony into evidence and issued a report of proceedings, which allows the LPSC to consider the uncontested settlement without the procedural motion that did not pass in December. In January 2023, the LPSC staff approved the stipulated settlement subject to certain modifications. These modifications include the recognition of accumulated deferred income tax benefits related to damaged assets and system restoration costs as a reduction of the amount authorized to be financed utilizing the securitization process authorized by Act 55, as supplemented by Act 293, from $1.657 billion to $1.491 billion. These modifications do not affect the staff’s conclusion that all system restoration costs sought by Entergy Louisiana were reasonable and prudent. The LPSC order is not yet final and non-appealable due to the forty-five day appeal period. In February 2023 the Louisiana Bond Commission voted to authorize the LCDA to issue the bonds authorized in the LPSC’s financing order; the bond rating and marketing process has yet to occur.
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy Louisiana charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Louisiana is regulated, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the LPSC, is primarily responsible for approval of the rates charged to customers.
Retail Rates - Electric
Retail Rates - Gas
2016 Rate Stabilization Plan Filing
In January 2017, Entergy Louisiana filedaccordance with the LPSC itssettlement of Entergy Gulf States Louisiana’s gas rate stabilization plan for the test year ended September 30, 2016.2012, in August 2014, Entergy Gulf States Louisiana submitted for consideration a proposal for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment and relocation projects mandated by local governments. After review by the LPSC staff and inclusion of certain customer safeguards required by the LPSC staff, in December 2014, Entergy Gulf States Louisiana and the LPSC staff submitted a joint settlement for implementation of an accelerated gas pipe replacement program providing for the replacement of approximately 100 miles of pipe over the next ten years, as well as relocation of certain existing pipe resulting from local government-related infrastructure projects, and for a rider to recover the investment associated with these projects. The filingrider allows for recovery of approximately $65 million over ten years. The rider recovery will be adjusted on a quarterly basis to include actual investment incurred for the prior quarter and is subject to the following conditions, among others: a ten-year term; application of any earnings in excess of the evaluation report for test year 2016 reflectedupper end of the earnings band as an earned return on common equityoffset to the revenue requirement of 6.37%. In April 2017the infrastructure rider; adherence to a specified spending plan, within plus or minus 20% annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding 10%; and an annual true-up. The joint settlement was approved by 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 filing2015. Implementation 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 effectiveinfrastructure rider commenced with bills rendered on and after the first billing cycle of May 2018,April 2015. In April 2022 Entergy Louisiana submitted for consideration a proposal to extend the infrastructure rider to address replacement of an additional 187 miles of pipe. In December 2022 Entergy Louisiana and the LPSC staff submitted an uncontested settlement that extends the rider for an additional ten years beginning after the end of the current term of the rider in 2025. The extension is subject to the same customer safeguards and conditions as the original term of the rider. The extension allows for recovery of approximately $95 million over ten years. In February 2023, the uncontested settlement was approved by the LPSC.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Louisiana’s filings to recover storm-related costs.
Other
In March 2016 the LPSC opened two dockets to examine, on a generic basis, issues that it identified in connection with its review of Cleco Corporation’s acquisition by third party investors. The first docket is captioned “In re: Investigation of double leveraging issues for all LPSC-jurisdictional utilities,” and the second is captioned “In re: Investigation of tax structure issues for all LPSC-jurisdictional utilities.” In April 2016 the LPSC clarified that the concerns giving rise to the two dockets arose as a result of its review of the structure of the Cleco-Macquarie transaction and that the specific intent of the directives is to seek more information regarding intra-corporate debt financing of a utility’s capital structure as well as the use of investment tax credits to mitigate the tax
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obligation at the parent level of a $0.2consolidated entity. No schedule has been set for either docket, and limited discovery has occurred.
In December 2019 an LPSC commissioner issued an unopposed directive to staff to research customer-centered options for all customer classes, as well as other regulatory environments, and recommend a plan for how to ensure customers are the focus. There was no opposition to the directive from other commissioners but several remarked that the intent of the directive was not initiated to pursue retail open access. In furtherance of the directive, the LPSC issued a notice of the opening of a docket to conduct a rulemaking to research and evaluate customer-centered options for all electric customer classes as well as other regulatory environments in January 2020. To date, the LPSC staff has requested multiple rounds of comments from stakeholders and conducted one technical conference. Topics on which comments have been filed include full and limited retail access, demand response, sleeved power purchase agreements, and energy efficiency. Neither the LPSC or the LPSC staff have made recommendations or adopted any rules.
Entergy Mississippi
Formula Rate Plan
Since the conclusion in 2015 of Entergy Mississippi’s most recent base rate case, Entergy Mississippi has set electric base rates annually through a formula rate plan. Between base rate cases, Entergy Mississippi is able to adjust base rates annually, subject to certain caps, through formula rate plans that utilize forward-looking features. In addition, Entergy Mississippi is subject to an annual “look-back” evaluation. Entergy Mississippi is allowed a maximum rate increase of 4% of each test year’s retail revenue. Any increase above 4% requires a base rate case. If Entergy Mississippi’s formula rate plan were terminated without replacement, it would revert to the more traditional rate case environment or seek approval of a new formula rate plan.
In August 2012 the MPSC opened inquiries to review whether the then current formulaic methodology used to calculate the return on common equity in both Entergy Mississippi’s formula rate plan and Mississippi Power Company’s annual formula rate plan was still appropriate or could be improved to better serve the public interest. The intent of this inquiry and review was for informational purposes only; the evaluation of any recommendations for changes to the existing methodology would take place in a general rate case or in the existing formula rate plan proceeding. In March 2013 the Mississippi Public Utilities Staff filed its consultant’s report which noted the return on common equity estimation methods used by Entergy Mississippi and Mississippi Power Company are commonly used throughout the electric utility industry. The report suggested ways in which the methods used by Entergy Mississippi and Mississippi Power Company might be improved, but did not recommend specific changes in the return on common equity formulas or calculations at that time. In June 2014 the MPSC expanded the scope of the August 2012 inquiry to study the merits of adopting a uniform formula rate plan that could be applied, where possible in whole or in part, to both Entergy Mississippi and Mississippi Power Company in order to achieve greater consistency in the plans. The MPSC directed the Mississippi Public Utilities Staff to investigate and review Entergy Mississippi’s formula rate plan rider schedule and Mississippi Power Company’s Performance Evaluation Plan by considering the merits and deficiencies and possibilities for improvement of each and then to propose a uniform formula rate plan that, where possible, could be applicable to both companies. No procedural schedule has been set. In October 2014 the Mississippi Public Utilities Staff conducted a public technical conference to discuss performance benchmarking and its potential application to the electric utilities’ formula rate plans. The docket remains open.
In December 2019 the MPSC approved Entergy Mississippi’s proposed revisions to its formula rate plan to 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 as well as to allow similar cost recovery treatment for other capacity acquisitions that are approved by the MPSC. 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
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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.
Fuel Recovery
Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased power costs. The energy cost rate for each calendar year is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy costs as of the 12-month period ended September 30. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC. The energy cost recovery riders allow interim rate adjustments depending on the level of over- or under-recovery of fuel and purchased energy costs.
To help stabilize electricity costs, Entergy Mississippi received approval from the MPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Mississippi hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of recovery of Entergy Mississippi’s storm-related costs.
Entergy New Orleans
Formula Rate Plan
As part of its determination of rates in the base rate case filed by Entergy New Orleans in 2018, in November 2019, the City Council issued a resolution resolving the rate case, with rates to become effective retroactive to August 2019. The resolution allows Entergy New Orleans to implement a three-year formula rate plan, beginning with the 2019 test year as adjusted for forward-looking known and measurable changes, with the filing for the first test year to be made in 2020. As part of a settlement of Entergy New Orleans’ appeal of the Council’s decision in its 2018 base rate case, Entergy New Orleans agreed to postpone the filing of its first test year formula rate plan to 2021 and, in return, to be provided an additional test year for the three-year cycle. Accordingly, Entergy New Orleans will submit its final formula rate plan filing of the three-year cycle in April 2023 unless the formula rate plan is extended or renewed. See Note 2 to the financial statements for further discussion.
Fuel Recovery
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.
To help stabilize gas costs, Entergy New Orleans seeks approval annually from the City Council to continue implementation of its natural gas hedging program consistent with the City Council’s stated policy objectives. The program uses financial instruments to hedge exposure to volatility in the wholesale price of natural gas purchased to
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serve Entergy New Orleans gas customers. Entergy New Orleans hedges up to 25% of actual gas sales made during the winter months.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy New Orleans’s filings to recover storm-related costs.
Entergy Texas
Base Rates
The base rates of Entergy Texas are established largely in traditional base rate case proceedings. Between base rate proceedings, Entergy Texas has available rate riders to recover the revenue requirements associated with certain incremental costs. Entergy Texas is required to file full base rate case proceedings every four years and within eighteen months of utilizing its generation cost recovery rider for investments above $200 million.
Fuel Recovery
Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, that are not included 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 every three years, at a minimum. In the course of this reconciliation, the PUCT determines whether eligible fuel and fuel-related expenses and revenues are necessary and reasonable and makes a prudence finding for each of the fuel-related contracts entered into during the reconciliation period. The PUCT fuel cost proceedings are discussed in Note 2 to the financial statements.
At the PUCT’s April 2013 open meeting, the PUCT Commissioners discussed their view that a purchased power capacity rider was good public policy. The PUCT issued an order in May 2013 adopting the rule allowing for a purchased power capacity rider, subject to an offsetting adjustment for load growth. The rule, as adopted, also includes a process for obtaining pre-approval by the PUCT of purchased power agreements. No Texas utility, including Entergy Texas, has exercised the option to recover capacity costs under the new rider mechanism, but Entergy Texas will continue to evaluate the benefits of utilizing the rider to recover future capacity costs.
Other Cost Recovery
As discussed above, Entergy Texas has available rate riders to recover the revenue requirements associated with certain incremental costs. These riders include a transmission cost recovery factor rider mechanism for the recovery of transmission-related capital investments, a distribution cost recovery factor rider mechanism for the recovery of distribution-related capital investment, and a generation cost recovery rider mechanism for the recovery of generation-related capital investments.
In June 2009 a law was enacted in Texas containing provisions that allow Entergy Texas to take advantage of a cost recovery mechanism that permits annual filings for the recovery of reasonable and necessary expenditures for transmission infrastructure improvement and changes in wholesale transmission charges. This mechanism was previously available to other non-ERCOT Texas utility companies, but not to Entergy Texas.
In September 2011 the PUCT adopted a proposed rule implementing a distribution cost recovery factor to recover capital and capital-related costs related to distribution infrastructure. The distribution cost recovery factor permits utilities once per year to implement an increase or decrease in rates above or below amounts reflected in base rates to reflect distribution-related depreciation expense, federal income tax and other taxes, and return on
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investment. The distribution cost recovery factor rider may be changed a maximum of four times between base rate cases.
In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery rider rule, implementing legislation passed in the 2019 Texas legislative session intended to allow electric utilities to recover generation investments between base rate proceedings. The PUCT approved the final rule in July 2020.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Texas’s filings to recover storm-related costs.
Electric Industry Restructuring
In June 2009 a law was enacted in Texas that required Entergy Texas to cease all activities relating to Entergy Texas’s transition to competition. The law allows Entergy Texas to remain a part of the SERC Reliability Corporation (SERC) Region, although it does not prevent Entergy Texas from joining another power region. The law provides that proceedings to certify a power region that Entergy Texas belongs to as a qualified power region can be initiated by the PUCT, or on motion by another party, when the conditions supporting such a proceeding exist. Under the law, the PUCT may not approve a transition to competition plan for Entergy Texas until the expiration of four years from the PUCT’s certification of a qualified power region for Entergy Texas.
The law further amended already existing law that had required Entergy Texas to propose for PUCT approval a tariff to allow eligible customers the ability to contract for competitive generation. The amending language in the law provides, among other things, that: 1) the tariff shall not be implemented in a manner that harms the sustainability or competitiveness of manufacturers who choose not to participate in the tariff; 2) Entergy Texas shall “purchase competitive generation service, selected by the customer, and provide the generation at retail to the customer;” and 3) Entergy Texas shall provide and price transmission service and ancillary services under that tariff at a rate that is unbundled from its cost of service. The law directs that the PUCT may not issue an order on the tariff that is contrary to an applicable decision, rule, or policy statement of a federal regulatory agency having jurisdiction. The PUCT determined that unrecovered costs that may be recovered through the rider consist only of those costs necessary to implement and administer the competitive generation program and do not include lost revenues or embedded generation costs. The amount of customer load that may be included in the competitive generation service program is limited to 115 MW.
System Energy
Cost of Service
The rates of System Energy are established by the FERC, and the costs allowed to be charged pursuant to these rates are, in turn, passed through to the participating Utility operating companies through the Unit Power Sales Agreement, which has monthly billings that reflect the current operating costs of, and investment in, Grand Gulf. Retail regulators and other parties may seek to initiate proceedings at FERC to investigate the prudence of costs included in the rates charged under the Unit Power Sales Agreement and examine, among other things, the reasonableness or prudence of the operation and maintenance practices, level of expenditures, allowed rates of return and rate base, and previously incurred capital expenditures. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC, including a challenge with respect to System Energy’s uncertain tax positions, sale leaseback arrangement, authorized return on equity and capital structure, and a separate proceeding for a broader investigation of rates under the Unit Power Sales Agreement. In addition, certain of the Utility operating companies’ retail regulators have filed a complaint at FERC challenging the 2012 extended power uprate of Grand Gulf and the operation and management of the plant, particularly during the time period 2016 - 2020. Beginning in 2021, System Energy implemented billing protocols to provide retail regulators with
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information regarding rates billed under the Unit Power Sales Agreement. Entergy cannot predict the outcome of any of these proceedings, and an adverse outcome in any of them could have a material adverse effect on Entergy’s or System Energy’s results of operations, financial condition, or liquidity. See Note 2 to the financial statements for further discussion of the proceedings.
Franchises
Entergy Arkansas holds exclusive franchises to provide electric service in approximately 308 incorporated cities and towns in Arkansas. These franchises generally are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas, franchises are considered to be contracts and, therefore, are governed pursuant to the terms of the franchise agreement and applicable statutes.
Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 175 incorporated municipalities and in the unincorporated areas of approximately 59 parishes of Louisiana. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and in East Baton Rouge Parish. Municipal franchise agreement terms range from 25 to 60 years while parish franchise terms range from 25 to 99 years.
Entergy Mississippi has received from the MPSC certificates of public convenience and necessity to provide electric service to areas within 45 counties, including a number of municipalities, in western Mississippi. Under Mississippi statutory law, such certificates are exclusive. Entergy Mississippi may continue to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence.
Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city ordinances. These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans’s electric and gas utility properties.
Entergy Texas holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 27 counties in eastern Texas and holds non-exclusive franchises to provide electric service in approximately 70 incorporated municipalities. Entergy Texas typically obtains 25-year franchise agreements as existing agreements expire. Entergy Texas’s electric franchises expire over the period 2023-2058.
The business of System Energy is limited to wholesale power sales. It has no distribution franchises.
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Property and Other Generation Resources
Owned Generating Stations
The total capability of the generating stations owned and leased by the Utility operating companies and System Energy as of December 31, 2022 is indicated below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Owned and Leased Capability MW(a) |
| Company | | Total | | CT / CCGT (b) | | Legacy Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
| Entergy Arkansas | | 5,276 | | | 1,567 | | | 522 | | | 1,822 | | | 1,192 | | | 73 | | | 100 | |
| Entergy Louisiana | | 10,829 | | | 5,595 | | | 2,766 | | | 2,129 | | | 339 | | | — | | | — | |
| Entergy Mississippi | | 2,857 | | | 1,738 | | | 707 | | | — | | | 310 | | | — | | | 102 | |
| Entergy New Orleans | | 663 | | | 636 | | | — | | | — | | | — | | | — | | | 27 | |
| Entergy Texas | | 3,190 | | | 980 | | | 1,960 | | | — | | | 250 | | | — | | | — | |
| System Energy | | 1,260 | | | — | | | — | | | 1,260 | | | — | | | — | | | — | |
| Total | | 24,075 | | | 10,516 | | | 5,955 | | | 5,211 | | | 2,091 | | | 73 | | | 229 | |
(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.
(b)Represents Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.
Summer peak load for the Utility has averaged 21,602 MW over the previous decade.
The Utility operating companies’ load and capacity projections are reviewed periodically to assess the need and timing for additional generating capacity and interconnections. These reviews consider existing and projected demand, the availability and price of power, the location of new load, the economy, Entergy’s clean energy and other public policy goals, environmental regulations, and the age and condition of Entergy’s existing infrastructure.
The Utility operating companies’ long-term resource strategy (Portfolio Transformation Strategy) calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Over the past decade, the Portfolio Transformation Strategy has resulted in the addition of about 8,975 MW of new long-term resources and the deactivation of about 4,881 MW of legacy generation. As MISO market participants, the Utility operating companies also participate in MISO’s Day Ahead and Real Time Energy and Ancillary Services markets to economically dispatch generation and purchase energy to serve customers reliably and at the lowest reasonable cost.
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Other Generation Resources
RFP Procurements
The Utility operating companies from time to time issue requests for proposals (RFP) to procure supply-side resources from sources other than the spot market to meet the unique regional needs of the Utility operating companies. The RFPs issued by the Utility operating companies have sought resources needed to meet near-term MISO reliability requirements as well as long-term requirements through a broad range of wholesale power products, including long-term contractual products and asset acquisitions. The RFP process has resulted in selections or acquisitions, including, among other things:
•Entergy Louisiana’s construction of the 980 MW, combined-cycle, gas turbine J. Wayne Leonard Power Station (previously referred to as the St. Charles generating facility) at its existing Little Gypsy electric generating station. The facility began commercial operation in May 2019;
•Entergy Louisiana’s construction of the 994 MW, combined-cycle, gas turbine Lake Charles generating facility at its existing Nelson electric generating station site. The facility began commercial operation in March 2020;
•Entergy Texas’s construction of the 993 MW, combined-cycle, gas turbine Montgomery County Power Station at its existing Lewis Creek electric generating station. The facility began commercial operation in January 2021;
•Entergy New Orleans’s construction of the 20 MW solar photovoltaic facility, New Orleans Solar Station, located at the NASA Michoud Facility. The facility began commercial operation in December 2020;
•In December 2020, Entergy Texas selected the self-build alternative, Orange County Advanced Power Station, out of the 2020 Entergy Texas combined-cycle, gas turbine RFP. Regulatory approval was received in November 2022 and construction has commenced. The facility is expected to be in service by mid-2026;
•In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Searcy Solar facility, sited on approximately 800 acres in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the APSC in April 2020, and closed on the acquisition, through use of a tax equity partnership, in December 2021. The Searcy Solar facility was placed in service in January 2022;
•In November 2018, Entergy Mississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Sunflower Solar facility, sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and the Sunflower Solar facility began commercial operation in September 2022;
•In June 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Walnut Bend Solar facility, that will be sited on approximately 1,000 acres in Lee County, Arkansas. In July 2021 the APSC issued an order approving the acquisition of the Walnut Bend Solar facility. The counter-party notified Entergy Arkansas that it was terminating the project, though it was willing to consider an alternative for the site. Entergy Arkansas disputed the right of termination. Negotiations are ongoing, including with respect to cost and schedule and to updates arising as a result of the Inflation Reduction Act of 2022, and the updates would require additional APSC approval. At this time the project, if approved, is expected to achieve commercial operation in 2024;
•In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility, West Memphis Solar facility, that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In October 2021 the APSC issued an order approving the acquisition of the West Memphis Solar facility. The counter-party notified Entergy Arkansas that it was seeking changes to certain terms of the build-own-transfer agreement, including both cost and schedule. In January 2023, Entergy Arkansas made a supplemental filing with the APSC. Following APSC supplemental approval, full notice to proceed will be issued with closing expected to occur in 2024;
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•In November 2021, Entergy Louisiana signed an agreement for the purchase of an approximately 150 MW to-be-constructed solar photovoltaic energy facility, St. Jacques facility, that will be sited in St. James Parish near Vacherie, Louisiana. In September 2022 the LPSC voted to approve the order including the St. Jacques facility; however, project details could be adjusted pending a final St. James Parish ruling on land use permit requirements. Closing is expected to occur in 2025 dependent upon the final St. James Parish ruling; and
•In August 2022, Entergy Arkansas signed an agreement for the purchase of an approximately 250 MW to-be-constructed solar photovoltaic energy facility, Driver Solar facility, that will be sited near Osceola, Arkansas. Also in August 2022, Entergy Arkansas received necessary approvals for the Driver Solar facility, and Entergy Arkansas has issued the counter-party full notice to proceed to begin construction. The parties are evaluating the effects of certain matters related to the Inflation Reduction Act of 2022, including the viability of a tax equity partnership. Closing is expected to occur by the end of 2024.
The RFP process has also resulted in the selection, or confirmation of the economic merits of, long-term purchased power agreements (PPAs), including, among others:
•River Bend’s 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’s 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 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. In November 2019, LS Power sold and transferred the Carville Energy Center and facility to Argo Infrastructure Partners, which included the power purchase agreement;
•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 to-be-constructed solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and the PPA began in November 2020;
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•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 to-be-constructed solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the PPA began in October 2020;
•In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in the first half of 2023;
•In August 2018, Entergy Louisiana and South Alexander Development I, LLC executed a 5-year agreement for 5 MW from a solar photovoltaic electric generating facility located in Livingston Parish, Louisiana. The PPA began in December 2020 and received regulatory approval in January 2021;
•In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and achieved commercial operation in November 2022;
•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in Polk County, Texas. The PPA is expected to start when the facility reaches commercial operation in December 2023;
•In June 2021, Entergy Louisiana and Sunlight Road Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. In September 2022 the LPSC voted to approve the order including this project. The facility is expected to reach commercial operation in December 2024;
•In June 2021, Entergy Louisiana and Vacherie Solar Energy Center, LLC executed a 20-year PPA for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. In September 2022 the LPSC voted to approve the order including this project; however, project details could be adjusted pending a final St. James Parish ruling on land use permit requirements. The facility is expected to reach commercial operation in 2025;
•In November 2021, Entergy Louisiana signed a PPA for approximately 125 MW from a to-be-constructed solar photovoltaic energy facility located in Allen, Louisiana. In September 2022 the LPSC voted to approve the order including this project. The facility is expected to reach commercial operation in February 2024;
•In December 2022, Entergy Mississippi signed a PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Hinds County, Mississippi. Following execution of the agreement, Entergy Mississippi filed a petition with the MPSC requesting all necessary approvals. The facility is expected to reach commercial operation in June 2026;
•In October 2022, Entergy Mississippi signed a PPA for approximately 100 MW from a to-be-constructed solar photovoltaic energy facility located in Tallahatchie County, Mississippi. Following execution of the agreement, Entergy Mississippi filed a petition with the MPSC requesting all necessary approvals. The facility is expected to reach commercial operation as early as May 2026;
•In October 2022, Entergy Mississippi signed a PPA for approximately 170 MW from a to-be-constructed solar photovoltaic energy facility located in Washington County, Mississippi. Following execution of the agreement, Entergy Mississippi filed a petition with the MPSC requesting all necessary approvals. The facility is expected to reach commercial operation as early as May 2026;
•In October 2022, Entergy Arkansas signed a PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in St. Francis County, Arkansas. Following execution of the agreement, Entergy Arkansas filed a petition with the APSC requesting all necessary approvals. The facility is expected to reach commercial operation as early as May 2025;
•In October 2022, Entergy Arkansas signed a PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in Mississippi County, Arkansas. Following execution of the agreement, Entergy Arkansas filed a petition with the APSC requesting all necessary approvals. The facility is expected to reach commercial operation as early as May 2025; and
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•In January 2023, Entergy Texas signed a PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Walker County, Texas. The facility is expected to reach commercial operation as early as June 2026.
In March 2021, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic resources. Entergy Louisiana selected a combination of PPA and build-own-transfer resources by March 2022, some of which have been executed and are noted above and the remainder are in progress working through definitive agreements.
In July 2021, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar generation resources. Entergy Texas selected a combination of PPA and build-own-transfer resources in March 2022. One PPA was executed in January 2023 as noted above, and definitive agreements for the remaining resources are in progress.
In August 2021, Entergy Services, on behalf of Entergy Arkansas, issued an RFP for solar photovoltaic and wind resources. Entergy Arkansas selected a combination of PPA and build-own-transfer resources in February 2022, some of which have been executed and are noted above and the remainder are in progress working through definitive agreements.
In January 2022, Entergy Services, on behalf of Entergy Mississippi, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 500 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Mississippi customers.
In June 2022, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 1500 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Louisiana customers.
In April 2022, Entergy Services, on behalf of Entergy Arkansas, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 1000 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Arkansas customers.
In October 2022, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 2000 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Texas customers.
In November 2022, Entergy Services, on behalf of Entergy Mississippi, issued an RFP for solar photovoltaic and wind resources. The RFP is seeking up to 500 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Mississippi customers.
Other Procurements From Third Parties
The Utility operating companies have also made resource acquisitions outside of the RFP process, including Entergy Arkansas’s (Power Block 2), Entergy Louisiana’s (Power Blocks 3 and 4), and Entergy New Orleans’s (Power Block 1) March 2016 acquisitions of the 1,980 MW (summer rating), natural gas-fired, combined-cycle gas turbine Union Power Station power blocks, each rated at 495 MW (summer rating); and Entergy Mississippi’s October 2019 acquisition of the 810 MW, combined-cycle, natural gas-fired Choctaw Generating Station. The
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Utility operating companies have also entered into various limited- and long-term contracts in recent years as a result of bilateral negotiations.
The Washington Parish Energy Center is a 361 MW natural gas-fired peaking power plant approximately 60 miles north of New Orleans on a site Entergy Louisiana purchased from Calpine in 2019. In May 2018, Entergy Louisiana received LPSC approval of its certification application for this simple-cycle power plant to be developed pursuant to an agreement between Calpine and Entergy Louisiana. Calpine began construction on the plant in early 2019 and Entergy Louisiana purchased the plant upon completion in November 2020.
The Hardin County Peaking Facility, an existing 147 MW simple-cycle gas-fired peaking power plant in Kountze, Texas, previously owned by East Texas Electric Cooperative, was acquired by Entergy Texas in June 2021. The facility has been in operation since January 2010.
Power Through Programs
In December 2020, Entergy Texas filed an application with the PUCT to amend its certificate of convenience and necessity to own and operate up to 75 MW of natural gas-fired distributed generation to be installed at commercial and industrial customer premises. Under this proposal, Entergy Texas would own and operate a fleet of generators ranging from 100 kW to 10 MW that would supply a portion of Entergy Texas’s long-term resource needs and enhance the resiliency of Entergy Texas’s electric grid. This fleet of generators would also be available to customers during outages to supply backup electric service as part of a program known as “Power Through.” In its 2021 session, the Texas legislature modified the Texas Utilities Code to exempt generators under 10 megawatts from the requirement to obtain a certificate of convenience and necessity. In addition, the PUCT announced an intent to conduct a broad rulemaking related to distributed generation and recommended that utilities with pending applications addressing distributed generation withdraw them. Accordingly, Entergy Texas withdrew its application for a certificate of convenience and necessity and associated tariff from the PUCT without prejudice to refiling. Entergy Texas continues to deploy certain customer-sited distributed generators under an existing PUCT-approved tariff. In August 2022, Entergy Texas filed an application for PUCT approval of voluntary Rate Schedule Utility Owned Distributed Generation (UODG) through which it would charge host customers for back-up service from customer-sited Power Through generators. Based on the exemption enacted by the Texas legislature in 2021, Entergy Texas’s application was not required to, and did not, seek an amendment to its certificate of convenience and necessity in order to continue deploying Power Through generators. In October 2022 two intervenors filed requests for a hearing on Entergy Texas’s application. In October 2022 the PUCT staff filed a request that the proceeding be referred to the State Office of Administrative Hearings. In January 2023 the PUCT announced an intent to develop certain broadly applicable reliability metrics against which to measure distributed generation resources and directed Entergy Texas to withdraw its application. However, the PUCT did allow Entergy Texas to continue its pilot program for Power Through generators. Entergy Texas has withdrawn its application and is considering next steps.
In August 2021, Entergy Arkansas filed with the APSC an application for authority to deploy natural gas-fired distributed generation. The application was supported by a number of letters of interest from Entergy Arkansas customers. In December 2021 the APSC general staff requested briefing, which Entergy Arkansas opposed. In January 2022, Entergy Arkansas filed to support the establishment of a procedural schedule with a hearing in April 2022. Also in January 2022, the APSC granted the general staff’s request for briefing but on an expedited schedule; briefing concluded in February 2022. Based on testimony filed to date the APSC general staff, Arkansas Electric Energy Consumers, Sierra Club, and Audubon oppose Entergy Arkansas’s proposed “Power Through” offering, which has been demonstrated to be in high demand by interested customers, some of which directly have filed public comments encouraging the APSC to approve the application. A paper hearing was held in August and September 2022 with Entergy Arkansas responding to several written commissioner questions. The parties are awaiting a decision from the APSC.
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In July 2021, Entergy Louisiana filed with the LPSC an application for authority to deploy natural gas-fired distributed generation. The application was supported by a number of letters of interest from Entergy Louisiana customers. In October 2021, a procedural schedule was established with a hearing in April 2022. Staff and certain intervenors filed direct testimony in December 2021, and cross-answering testimony was filed in January 2022. Entergy Louisiana filed rebuttal testimony in February 2022. The parties reached an uncontested settlement which, among other things, recommended approval of 120 MW of natural gas fired distributed generation and an additional 30 MW of solar and battery distributed generation, for a total distributed generation program of 150 MW. Pursuant to the terms of the settlement agreement, Entergy Louisiana may seek to expand the distributed generation program following the earlier of two years after issuance of an order approving the settlement or the installation of 60 MW of distributed generation pursuant to this program. The settlement was approved by the LPSC in November 2022.
Interconnections
The Utility operating companies’ generating units are interconnected to a transmission system operating at various voltages up to 500 kV. These generating units consist of steam-turbine generators fueled by natural gas and coal, combustion-turbine generators, and reciprocating internal combustion engine generators that are fueled by natural gas, generators powered by pressurized and boiling water nuclear reactors and inverter-based resources interconnecting both solar photovoltaic systems and energy storage devices that operate in the MISO wholesale electric market. Additionally, some of the Utility operating companies also offer customer services and products that include resources interconnected to both the distribution and transmission systems that also participate in the wholesale market. Entergy’s Utility operating companies are MISO market participants and the companies’ transmission systems are interconnected with those of many neighboring utilities. MISO is an essential link in the safe, cost-effective delivery of electric power across all or parts of 15 U.S. states and the Canadian province of Manitoba. In addition, the Utility operating companies are members of SERC Reliability Corporation (SERC), the Regional Entity with delegated authority from the North American Electric Reliability Corporation (NERC) for the purpose of proposing and enforcing Bulk Electric System reliability standards within 16 central and southeastern states.
Gas Property
As of December 31, 2022, Entergy New Orleans distributed and transported natural gas for distribution within New Orleans, Louisiana, through approximately 2,600 miles of gas pipeline. As of December 31, 2022, the gas properties of Entergy Louisiana, which are located in and around Baton Rouge, Louisiana, were not material to Entergy Louisiana’s financial position.
Title
The Utility operating companies’ generating stations are generally located on properties owned in fee simple. Most of the substations and transmission and distribution lines are constructed on private property or public rights-of-way pursuant to easements, servitudes, or appropriate franchises. Some substation properties are owned in fee simple. The Utility operating companies generally have the right of eminent domain, whereby they may perfect title to, or secure easements or servitudes on, private property for their utility operations.
Substantially all of the physical properties and assets owned by Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are subject to the liens of mortgages securing bonds issued by those companies. The Lewis Creek generating station of Entergy Texas was acquired by merger with a subsidiary of Entergy Texas and is currently not subject to the lien of the Entergy Texas indenture.
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Fuel Supply
The average fuel cost per kWh for the Utility operating companies and System Energy for the years 2020-2022 were:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year | | Natural Gas | | Nuclear | | Coal | | Renewables (a) | | Purchased Power | | MISO Purchases (b) |
| 2022 | | (Cents Per kWh) |
| Entergy Arkansas | | 4.98 | | | 0.52 | | | 2.93 | | | 2.11 | | | 10.90 | | | (2.65) | |
| Entergy Louisiana | | 5.50 | | | 0.57 | | | 2.84 | | | 10.70 | | | 6.95 | | | 6.45 | |
| Entergy Mississippi | | 4.38 | | | — | | | 2.85 | | | 0.04 | | | 6.53 | | | 6.68 | |
| Entergy New Orleans (c) | | 5.10 | | | — | | | — | | | (5.16) | | | — | | | 7.21 | |
| Entergy Texas | | 5.77 | | | — | | | 2.83 | | | 6.26 | | | 5.61 | | | 6.68 | |
| System Energy | | — | | | 0.65 | | | — | | | — | | | — | | | — | |
| Utility | | 5.27 | | | 0.57 | | | 2.89 | | | 7.00 | | | 6.54 | | | 5.95 | |
| | | | | | | | | | | | |
| 2021 | | | | | | | | | | | | |
| Entergy Arkansas | | 4.11 | | | 0.56 | | | 2.43 | | | 2.85 | | | 2.53 | | | 3.87 | |
| Entergy Louisiana | | 3.77 | | | 0.56 | | | 2.62 | | | 10.87 | | | 5.52 | | | 4.04 | |
| Entergy Mississippi | | 2.71 | | | — | | | 2.53 | | | 1.22 | | | 2.70 | | | 4.16 | |
| Entergy New Orleans (c) | | 3.47 | | | — | | | — | | | (2.82) | | | — | | | 4.50 | |
| Entergy Texas | | 4.65 | | | — | | | 2.60 | | | 3.97 | | | 4.53 | | | 4.10 | |
| System Energy | | — | | | 0.55 | | | — | | | — | | | — | | | — | |
| Utility | | 3.75 | | | 0.56 | | | 2.48 | | | 9.07 | | | 4.76 | | | 4.08 | |
| | | | | | | | | | | | |
| 2020 | | | | | | | | | | | | |
| Entergy Arkansas | | 1.78 | | | 0.62 | | | 2.35 | | | 2.28 | | | 7.39 | | | 0.63 | |
| Entergy Louisiana | | 1.98 | | | 0.58 | | | 3.27 | | | 9.99 | | | 3.48 | | | 2.65 | |
| Entergy Mississippi | | 1.73 | | | — | | | 2.52 | | | 0.25 | | | 3.23 | | | 2.26 | |
| Entergy New Orleans | | 1.56 | | | — | | | — | | | 0.02 | | | — | | | 2.99 | |
| Entergy Texas | | 2.23 | | | — | | | 3.17 | | | 3.61 | | | 3.29 | | | 2.71 | |
| System Energy | | — | | | 0.39 | | | — | | | — | | | — | | | — | |
| Utility | | 1.92 | | | 0.57 | | | 2.54 | | | 8.28 | | | 3.35 | | | 2.48 | |
(a)Includes average fuel costs from both owned and purchased power resources.
(b)Includes activity from financial transmission rights. See Note 15 to the financial statements for discussion of financial transmission rights.
(c)Entergy New Orleans’s renewables include liquidated damage payments of $2.9 million in 2022 and $1 million in 2021 due to the delay of in-service dates related to purchased power agreements.
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Actual 2022 and projected 2023 sources of generation for the Utility operating companies and System Energy, including certain power purchases from affiliates under life of unit power purchase agreements, including the Unit Power Sales Agreement, are:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2022 |
| | CT / CCGT (b) | | Legacy Gas | | Nuclear | | Coal | | Renewables (c) | | Purchased Power (d) | | MISO Purchases (e) |
| Entergy Arkansas | 30 | % | | 1 | % | | 50 | % | | 12 | % | | 3 | % | | — | % | | 4 | % |
| Entergy Louisiana | 44 | % | | 9 | % | | 23 | % | | 3 | % | | 2 | % | | 8 | % | | 11 | % |
| Entergy Mississippi | 59 | % | | 6 | % | | 18 | % | | 7 | % | | 1 | % | | — | % | | 9 | % |
| Entergy New Orleans | 54 | % | | 1 | % | | 35 | % | | 1 | % | | 1 | % | | 1 | % | | 7 | % |
| Entergy Texas | 31 | % | | 20 | % | | 11 | % | | 5 | % | | — | % | | 9 | % | | 24 | % |
| System Energy (a) | — | % | | — | % | | 100 | % | | — | % | | — | % | | — | % | | — | % |
| Utility | 42 | % | | 8 | % | | 27 | % | | 5 | % | | 2 | % | | 5 | % | | 11 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2023 |
| | CT / CCGT (b) | | Legacy Gas | | Nuclear | | Coal | | Renewables (c) | | Purchased Power (d) | | MISO Purchases (e) |
| Entergy Arkansas | 26 | % | | — | % | | 58 | % | | 13 | % | | 3 | % | | — | % | | — | % |
| Entergy Louisiana | 47 | % | | 5 | % | | 30 | % | | 3 | % | | 3 | % | | 12 | % | | — | % |
| Entergy Mississippi | 63 | % | | — | % | | 26 | % | | 10 | % | | 1 | % | | — | % | | — | % |
| Entergy New Orleans | 48 | % | | 1 | % | | 45 | % | | 2 | % | | 3 | % | | 1 | % | | — | % |
| Entergy Texas | 44 | % | | 31 | % | | 15 | % | | 9 | % | | — | % | | 1 | % | | — | % |
| System Energy (a) | — | % | | — | % | | 100 | % | | — | % | | — | % | | — | % | | — | % |
| Utility | 44 | % | | 6 | % | | 36 | % | | 7 | % | | 2 | % | | 5 | % | | — | % |
(a)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.
(b)Represents natural gas sourced for Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.
(c)Includes generation from both owned and purchased power resources.
(d)Excludes MISO purchases and renewables purchased through purchased power agreements.
(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 2022 is not projected for 2023.
Some of the Utility’s gas-fired plants are also capable of using fuel oil, if necessary. Although based on current economics the Utility does not expect fuel oil use in 2023, it is possible that various operational events including weather or pipeline maintenance may require the use of fuel oil.
Natural Gas
The Utility operating companies have long-term firm and short-term interruptible gas contracts for both supply and transportation. Over 50% of the Utility operating companies’ power plants maintain some level of long-term firm transportation. Short-term contracts and spot-market purchases satisfy additional gas requirements.
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Entergy Texas owns a gas storage facility and Entergy Louisiana has a firm storage service agreement that provide reliable and flexible natural gas service to certain generating stations.
Many factors, including wellhead deliverability, storage, pipeline capacity, and demand requirements of end users, influence the availability and price of natural gas supplies for power plants. Demand is primarily tied to weather conditions as well as to the prices and availability of other energy sources. Pursuant to federal and state regulations, gas supplies to power plants may be interrupted during periods of shortage. To the extent natural gas supplies are disrupted or natural gas prices significantly increase, the Utility operating companies may in some instances use alternate fuels, such as oil when available, or rely to a larger extent on coal, nuclear generation, and purchased power.
Coal
Entergy Arkansas has committed to six two- to three-year contracts that will supply approximately 85% of the total coal supply needs in 2023. These contracts are staggered in term so that not all contracts have to be renewed the same year. If needed, additional Powder River Basin (PRB) coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. Based on the high cost of alternate sources, modes of transportation, and infrastructure improvements necessary for its delivery, no alternative coal consumption is expected at Entergy Arkansas during 2023. Coal will be transported to Arkansas via an existing Union Pacific transportation agreement that is expected to provide all of Entergy Arkansas’s rail transportation requirements for 2023.
Entergy Louisiana has committed to four two- to three-year contracts that will supply approximately 90% of Nelson Unit 6 coal needs in 2023. If needed, additional PRB coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. For the same reasons as the Entergy Arkansas plants, no alternative coal consumption is expected at Nelson Unit 6 during 2023. Coal will be transported to Nelson via an existing transportation agreement that is expected to provide all of Entergy Louisiana’s rail transportation requirements for 2023.
Coal transportation delivery rates to Entergy Arkansas- and Entergy Louisiana-operated coal-fired units became constrained and were unable to fully meet supply needs and obligations beginning in August 2021. Deliveries remained constrained through 2022 with modest improvement expected later in 2023. Both Entergy Arkansas and Entergy Louisiana control enough railcars to satisfy the rail transportation requirement.
The operator of Big Cajun 2 - Unit 3, Louisiana Generating, LLC, has advised Entergy Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2023, but is also currently experiencing delivery constraints. Entergy Louisiana’s and Entergy Texas’s coal nomination requests to Big Cajun 2 - Unit 3 are made on an annual basis.
Nuclear Fuel
The nuclear fuel cycle consists of the following:
•mining and milling of uranium ore to produce a concentrate;
•conversion of the concentrate to uranium hexafluoride gas;
•enrichment of the uranium hexafluoride gas;
•fabrication of nuclear fuel assemblies for use in fueling nuclear reactors; and
•disposal of spent fuel.
The Registrant Subsidiaries that own nuclear plants, Entergy Arkansas, Entergy Louisiana, and System Energy, are responsible through a shared regulated uranium pool for contracts to acquire nuclear material to be used in fueling Entergy’s Utility nuclear units. These companies own the materials and services in this shared regulated
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uranium pool on a pro rata fractional basis determined by the nuclear generation capability of each company. Any liabilities for obligations of the pooled contracts are on a several but not joint basis. The shared regulated uranium pool maintains inventories of nuclear materials during the various stages of processing. The Registrant Subsidiaries purchase enriched uranium hexafluoride for their nuclear plant reload requirements at the average inventory cost from the shared regulated uranium pool. Entergy Operations, Inc. contracts separately for the fabrication of nuclear fuel as agent on behalf of each of the Registrant Subsidiaries that owns a nuclear plant. All contracts for the disposal of spent nuclear fuel are between the DOE and the owner of a nuclear power plant.
Based upon currently planned fuel cycles, the Utility nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable or fixed prices through most of 2027. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners, including their ability to work through supply disruptions caused by global events, such as the COVID-19 pandemic, or national events, such as political disruption. There are a number of possible supply alternatives that may be accessed to mitigate any supplier performance failure, including potentially drawing upon Entergy’s inventory intended for later generation periods depending upon its risk management strategy at that time, although the pricing of any alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. In addition, some nuclear fuel contracts are on a non-fixed price basis subject to prevailing prices at the time of delivery.
The effects of market price changes may be reduced and deferred by risk management strategies, such as negotiation of floor and ceiling amounts for long-term contracts, buying for inventory or entering into forward physical contracts at fixed prices when Entergy believes it is appropriate and useful. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S.
Entergy’s ability to assure nuclear fuel supply also depends upon the performance reliability of conversion, enrichment, and fabrication services providers. There are fewer of these providers than for uranium. For conversion and enrichment services, like uranium, Entergy diversifies its supply by supplier and country and may take special measures as needed to ensure supply of enriched uranium for the reliable fabrication of nuclear fuel. For fabrication services, each plant is dependent upon the effective performance of the fabricator of that plant’s nuclear fuel, therefore, Entergy provides additional monitoring, inspection, and oversight for the fabrication process to assure reliability and quality.
Entergy Arkansas, Entergy Louisiana, and System Energy each have made arrangements to lease nuclear fuel and related equipment and services. The lessors, which are consolidated in the financial statements of Entergy and the applicable Registrant Subsidiary, finance the acquisition and ownership of nuclear fuel through credit agreements and the issuance of notes. These credit facilities are subject to periodic renewal, and the notes are issued periodically, typically for terms between three and seven years.
Natural Gas Purchased for Resale
Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with one interstate and three intrastate pipelines. Entergy New Orleans has a “no-notice” service gas purchase contract with Symmetry Energy Solutions which guarantees Entergy New Orleans gas delivery at specific delivery points and at any volume within the minimum and maximum set forth in the contract amounts. The Symmetry Energy Solutions gas supply is transported to Entergy New Orleans pursuant to a transportation service agreement with Gulf South Pipeline Co. This service is subject to FERC-approved rates. Entergy New Orleans also makes interruptible spot market purchases.
Entergy Louisiana purchased natural gas for resale in 2022 under a firm contract from Sequent Energy Management L.P. The gas is delivered through a combination of intrastate and interstate pipelines.
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As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy Louisiana’s or Entergy New Orleans’s suppliers failed to perform their obligations to deliver gas under their supply agreements. Gulf South Pipeline Co. could curtail transportation capacity only in the event of pipeline system constraints.
Federal Regulation of the Utility
State or local regulatory authorities, as described above, regulate the retail rates of the Utility operating companies. The FERC regulates wholesale sales of electricity rates and interstate transmission of electricity, including System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. See Note 2 to the financial statements for further discussion of federal regulation proceedings.
Transmission and MISO Markets
In December 2013 the Utility operating companies integrated into the MISO RTO. Although becoming a member of MISO did not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities, MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. MISO also exercises functional control of transmission planning and congestion management and provides schedules and pricing for the commitment and dispatch of generation that is offered into MISO’s markets, as well as pricing for load that bids into the markets. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their generating facilities into the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. Each Utility operating company has its own transmission pricing zone and a formula rate template (included as Attachment O to the MISO tariff) used to establish transmission rates within MISO. The terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets and the allocation of transmission upgrade costs, are subject to regulation by the FERC.
System Energy and Related Agreements
System Energy recovers costs related to its interest in Grand Gulf through rates charged to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans for capacity and energy under the Unit Power Sales Agreement (described below). In 1998 the FERC approved requests by Entergy Arkansas and Entergy Mississippi to accelerate a portion of their Grand Gulf purchased power obligations. Entergy Arkansas’s and Entergy Mississippi’s acceleration of Grand Gulf purchased power obligations ceased effective July 2001 and July 2003, respectively, as approved by the FERC. See Note 2 to the financial statements for discussion of proceedings at the FERC related to System Energy.
Unit Power Sales Agreement
The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System Energy’s ownership and leasehold interests in Grand Gulf to Entergy Arkansas (36%), Entergy Louisiana (14%), Entergy Mississippi (33%), and Entergy New Orleans (17%). Each of these companies is obligated to make payments to System Energy for its entitlement of capacity and energy on a full cost-of-service basis regardless of the quantity of energy delivered. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenue. The financial condition of System Energy depends upon the continued commercial operation of Grand Gulf and the receipt of such payments. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans generally recover payments made under the Unit Power Sales Agreement through rates charged to their customers.
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In the case of Entergy Arkansas and Entergy Louisiana, payments are also recovered through sales of electricity from their respective retained shares of Grand Gulf. Under a settlement agreement entered into with the APSC in 1985 and amended in 1988, Entergy Arkansas retains 22% of its 36% share of Grand Gulf-related costs and recovers the remaining 78% of its share in rates. In the event that Entergy Arkansas is not able to sell its retained share to third parties, it may sell such energy to its retail customers at a price equal to its avoided cost, which is currently less than Entergy Arkansas’s cost from its retained share. Entergy Arkansas has life-of-resources purchased power agreements with Entergy Louisiana and Entergy New Orleans that sell a portion of the output of Entergy Arkansas’s retained share of Grand Gulf to those companies, with the remainder of the retained share being sold to Entergy Mississippi through a separate life-of-resources purchased power agreement. In a series of LPSC orders, court decisions, and agreements from late 1985 to mid-1988, Entergy Louisiana was granted cost recovery with respect to costs associated with Entergy Louisiana’s share of capacity and energy from Grand Gulf, subject to certain terms and conditions. Entergy Louisiana retains and does not recover from retail ratepayers 18% of its 14% share of the costs of Grand Gulf capacity and energy and recovers the remaining 82% of its share in rates. Entergy Louisiana is allowed to recover through the fuel adjustment clause at 4.6 cents per kWh for the energy related to its retained portion of these costs. Alternatively, Entergy Louisiana may sell such energy to non-affiliated parties at prices above the fuel adjustment clause recovery amount, subject to the LPSC’s approval. Entergy Arkansas also has a life-of-resources purchased power agreement with Entergy Mississippi to sell a portion of the output of Entergy Arkansas’s non-retained share of Grand Gulf. Entergy Mississippi was granted cost recovery for those purchases by the MPSC through its annual unit power cost rate mechanism.
Availability Agreement
The Availability Agreement among System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans was entered into in 1974 in connection with the original financing by System Energy of Grand Gulf. The Availability Agreement provides that System Energy make available to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans all capacity and energy available from System Energy’s share of Grand Gulf.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans also agreed severally to pay System Energy monthly for the right to receive capacity and energy from Grand Gulf in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement) would at least equal System Energy’s total operating expenses for Grand Gulf (including depreciation at a specified rate and expenses incurred in a permanent shutdown of Grand Gulf) and interest charges.
The allocation percentages under the Availability Agreement are fixed as follows: Entergy Arkansas - 17.1%; Entergy Louisiana - 26.9%; Entergy Mississippi - 31.3%; and Entergy New Orleans - 24.7%. The allocation percentages under the Availability Agreement would remain in effect and would govern payments made under such agreement in the event of a shortfall of operating expense funds available to System Energy from other sources, including payments under the Unit Power Sales Agreement.
System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for all of its outstanding series of first mortgage bonds, as well as for its outstanding term loan and the pollution control revenue refunding bonds issued on its behalf. In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they were prohibited by governmental action from making payments under the Availability Agreement (for example, if the FERC reduced or disallowed such payments as constituting excessive rates), they would then make subordinated advances to System Energy in the same amounts and at the same times as the prohibited payments. System Energy would not be allowed to repay these subordinated advances so long as it remained in default under the related indebtedness or in other similar circumstances.
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Each of the assignment agreements relating to the Availability Agreement provides that Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans will make payments directly to System Energy. However, if there is an event of default, those payments must be made directly to the holders of indebtedness that are the beneficiaries of such assignment agreements. The payments must be made pro rata according to the amount of the respective obligations secured.
The obligations of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans to make payments under the Availability Agreement are subject to the receipt and continued effectiveness of all necessary regulatory approvals. Sales of capacity and energy under the Availability Agreement would require that the Availability Agreement be submitted to the FERC for approval with respect to the terms of such sale. No such filing with the FERC has been made because sales of capacity and energy from Grand Gulf are being made pursuant to the Unit Power Sales Agreement. If, for any reason, sales of capacity and energy are made in the future pursuant to the Availability Agreement, the jurisdictional portions of the Availability Agreement would be submitted to the FERC for approval.
Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement to System Energy have exceeded the amounts payable under the Availability Agreement and, therefore, 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 certain of 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 because their Availability Agreement obligations exceed their Unit Power Sales Agreement obligations.
The Availability Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, without further consent of any assignees or other creditors.
Service Companies
Entergy Services, a limited liability company wholly-owned by Entergy Corporation, provides management, administrative, accounting, legal, engineering, and other services primarily to the Utility operating companies, but also provides services to Entergy Wholesale Commodities. Entergy Operations is also wholly-owned by Entergy Corporation and provides nuclear management, operations and maintenance services under contract for ANO, River Bend, Waterford 3, and Grand Gulf, subject to the owner oversight of Entergy Arkansas, Entergy Louisiana, and System Energy, respectively. Entergy Services and Entergy Operations provide their services to the Utility operating companies and System Energy on an “at cost” basis, pursuant to cost allocation methodologies for these service agreements that were approved by the FERC.
Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas
Effective December 31, 2007, Entergy Gulf States, Inc. completed a jurisdictional separation into two vertically integrated utility companies, one operating under the sole retail jurisdiction of the PUCT, Entergy Texas, and the other operating under the sole retail jurisdiction of the LPSC, Entergy Gulf States Louisiana. Entergy Texas owns all Entergy Gulf States, Inc. distribution and transmission assets located in Texas, the gas-fired generating plants located in Texas, undivided 42.5% ownership shares of Entergy Gulf States, Inc.’s 70% ownership interest in Nelson Unit 6 and 42% ownership interest in Big Cajun 2, Unit 3, which are coal-fired generating plants located in Louisiana, and other assets and contract rights to the extent related to utility operations in Texas. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, owns all of the remaining assets that were owned by Entergy Gulf States, Inc. On a book value basis, approximately 58.1% of the Entergy Gulf States, Inc. assets were allocated to Entergy Gulf States Louisiana and approximately 41.9% were allocated to Entergy Texas.
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Entergy Texas purchases from Entergy Louisiana pursuant to a life-of-unit purchased power agreement a 42.5% share of capacity and energy from the 70% of River Bend subject to retail regulation. Entergy Texas was allocated a share of River Bend’s nuclear and environmental liabilities that is identical to the share of the plant’s output purchased by Entergy Texas under the purchased power agreement. In connection with the termination of the System Agreement effective August 31, 2016, the purchased power agreements that were put in place for certain legacy units at the time of the jurisdictional separation were also terminated at that time. See Note 2 to the financial statements for additional discussion of the purchased power agreements.
Entergy Louisiana and Entergy Gulf States Louisiana Business Combination
On October 1, 2015, the businesses formerly conducted by Entergy Louisiana (Old Entergy Louisiana) and Entergy Gulf States Louisiana (Old Entergy Gulf States Louisiana) were combined into a single public utility. In order to effect the business combination, under the Texas Business Organizations Code (TXBOC), Old Entergy Louisiana allocated substantially all of its assets to a new subsidiary, Entergy Louisiana Power, LLC, a Texas limited liability company (New Entergy Louisiana), and New Entergy Louisiana assumed the liabilities of Old Entergy Louisiana, in a transaction regarded as a merger under the TXBOC. Under the TXBOC, Old Entergy Gulf States Louisiana allocated substantially all of its assets to a new subsidiary (New Entergy Gulf States Louisiana) and New Entergy Gulf States Louisiana assumed the liabilities of Old Entergy Gulf States Louisiana, in a transaction regarded as a merger under the TXBOC. New Entergy Gulf States Louisiana then merged into New Entergy Louisiana with New Entergy Louisiana surviving the merger. Thereupon, Old Entergy Louisiana changed its name from “Entergy Louisiana, LLC” to “EL Investment Company, LLC” and New Entergy Louisiana changed its name from “Entergy Louisiana Power, LLC” to “Entergy Louisiana, LLC” (Entergy Louisiana). With the completion of the business combination, Entergy Louisiana holds substantially all of the assets, and has assumed the liabilities, of Old Entergy Louisiana and Old Entergy Gulf States Louisiana.
Entergy New Orleans Internal Restructuring
In November 2017, pursuant to the agreement in principle, Entergy New Orleans, Inc. undertook a multi-step restructuring, including the following:
•Entergy New Orleans, Inc. redeemed its outstanding preferred stock at a price of approximately $21 million, which included a call premium of approximately $819,000, plus any accumulated and unpaid dividends.
•Entergy New Orleans, Inc. converted from a Louisiana corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy New Orleans, Inc. allocated substantially all of its assets to a new subsidiary, Entergy New Orleans Power, LLC, a Texas limited liability company (Entergy New Orleans Power), and Entergy New Orleans Power assumed substantially all of the liabilities of Entergy New Orleans, Inc. in a transaction regarded as a merger under the TXBOC. Entergy New Orleans, Inc. remained in existence and held the membership interests in Entergy New Orleans Power.
•Entergy New Orleans, Inc. contributed the membership interests in Entergy New Orleans Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy New Orleans Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2017, Entergy New Orleans, Inc. changed its name to Entergy Utility Group, Inc., and Entergy New Orleans Power then changed its name to Entergy New Orleans, LLC. Entergy New Orleans, LLC holds substantially all of the assets, and has assumed substantially all of the liabilities, of Entergy New Orleans, Inc. The restructuring was accounted for as a transaction between entities under common control.
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Entergy Arkansas Internal Restructuring
In November 2018, Entergy Arkansas undertook a multi-step restructuring, including the following:
•Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.
•Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Arkansas Power, LLC, a Texas limited liability company (Entergy Arkansas Power), and Entergy Arkansas Power assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.
•Entergy Arkansas, Inc. contributed the membership interests in Entergy Arkansas Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Arkansas Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Arkansas, Inc. changed its name to Entergy Utility Property, Inc., and Entergy Arkansas Power then changed its name to Entergy Arkansas, LLC. Entergy Arkansas, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Arkansas, Inc. The transaction was accounted for as a transaction between entities under common control.
Entergy Mississippi Internal Restructuring
In November 2018, Entergy Mississippi undertook a multi-step restructuring, including the following:
•Entergy Mississippi, Inc. redeemed its outstanding preferred stock, at the aggregate redemption price of approximately $21.2 million.
•Entergy Mississippi, Inc. converted from a Mississippi corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Mississippi, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Mississippi Power and Light, LLC, a Texas limited liability company (Entergy Mississippi Power and Light), and Entergy Mississippi Power and Light assumed substantially all of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Mississippi, Inc. remained in existence and held the membership interests in Entergy Mississippi Power and Light.
•Entergy Mississippi, Inc. contributed the membership interests in Entergy Mississippi Power and Light to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Mississippi Power and Light is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Mississippi, Inc. changed its name to Entergy Utility Enterprises, Inc., and Entergy Mississippi Power and Light then changed its name to Entergy Mississippi, LLC. Entergy Mississippi, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Mississippi, Inc. The restructuring was accounted for as a transaction between entities under common control.
Entergy Wholesale Commodities
See “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the shutdown and sale of each of the Entergy Wholesale Commodities nuclear power plants. With the sale of Palisades in June 2022, Entergy completed its multi-year strategy to exit the merchant power business.
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Entergy Wholesale Commodities includes the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. Entergy Wholesale Commodities also provides decommissioning-related services to nuclear power plants owned by non-affiliated entities in the United States.
Property
Entergy Wholesale Commodities includes ownership in the following non-nuclear power plants:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Plant | | Location | | Ownership | | Net Owned Capacity (a) | | Type |
| Independence Unit 2; 842 MW | | Newark, AR | | 14% | | 121 MW(b) | | Coal |
| Nelson Unit 6; 550 MW | | Westlake, LA | | 11% | | 60 MW(b) | | Coal |
(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.
All of Entergy Wholesale Commodities’ owned generation falls under the authority of MISO. Entergy Wholesale Commodities’ customers for the sale of both energy and capacity from its owned generation and its contracted power purchases include retail power providers, utilities, electric power co-operatives, power trading organizations, and other power generation companies. The majority of Entergy Wholesale Commodities’ owned generation and contracted power purchases are sold under cost-based contract.
Other Business Activities
TLG Services, a subsidiary in the Entergy Wholesale Commodities segment, offers decommissioning, engineering, and related services to nuclear power plant owners.
Regulation of Entergy’s Business
Federal Power Act
The Federal Power Act provides the FERC the authority to regulate:
•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.
The Federal Power Act gives the FERC jurisdiction over the rates charged by System Energy for Grand Gulf capacity and energy provided to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans and over the rates charged by Entergy Arkansas and Entergy Louisiana to unaffiliated wholesale customers. The FERC also regulates wholesale power sales between the Utility operating companies. In addition, the FERC regulates the MISO RTO, an independent entity that maintains functional control over the combined transmission systems of its members and administers wholesale energy, capacity, and ancillary services markets for market participants in the MISO region, including the Utility operating companies. FERC regulation of the MISO RTO includes regulation of the design and implementation of the wholesale markets administered by the MISO RTO, as
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well as the rates, terms, and conditions of open access transmission service over the member systems and the allocation of costs associated with transmission upgrades.
Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 65 MW of capacity.
State Regulation
Utility
Entergy Arkansas is subject to regulation by the APSC as to the following:
•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 non-exempt 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.
Additionally, Entergy Arkansas serves a limited number of retail customers in Tennessee. Pursuant to legislation enacted in Tennessee, Entergy Arkansas is subject to complaints before the Tennessee Regulatory Authority only if it fails to treat its retail customers in Tennessee in the same manner as its retail customers in Arkansas. Additionally, Entergy Arkansas maintains limited facilities in Missouri but does not provide retail electric service to customers in Missouri. Although Entergy Arkansas obtained a certificate with respect to its Missouri facilities, Entergy Arkansas is not subject to retail ratemaking jurisdiction in Missouri.
Entergy Louisiana’s electric and gas business is subject to regulation by the LPSC as to the following:
•utility service;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment clause, environmental adjustment charge, 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 for purchase power contracts that exceed either 5 MW or one year in term;
•procurement process to acquire capacity over 50 MW;
•audits of the energy efficiency rider;
•avoided cost payment to non-exempt Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers and acquisitions and other changes of control.
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Entergy Mississippi is subject to regulation by the MPSC as to the following:
•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;
•certification of generating facilities and certain transmission projects;
•avoided cost payments to non-exempt Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers, acquisitions, and other changes of control.
Entergy Mississippi is also subject to regulation by the APSC as to the certificate of environmental compatibility and public need for the Independence Station, which is located in Arkansas.
Entergy New Orleans is subject to regulation by the City Council as to the following:
•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;
•avoided cost payments to non-exempt Qualifying Facilities;
•issuance and sale of certain securities; and
•utility mergers and acquisitions and other changes of control.
To the extent authorized by governing legislation, Entergy Texas is subject to the original jurisdiction of the municipal authorities of a number of incorporated cities in Texas with appellate jurisdiction over such matters residing in the PUCT. Entergy Texas is also subject to regulation by the PUCT as to the following:
•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 non-exempt Qualifying Facilities;
•net energy metering; 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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Regulation of the Nuclear Power Industry
Atomic Energy Act of 1954 and Energy Reorganization Act of 1974
Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose civil penalties or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, Entergy Louisiana, and System Energy, as owners of all or portions of ANO, River Bend and Waterford 3, and Grand Gulf, respectively, and Entergy Operations, as the licensee and operator of these units, are subject to the jurisdiction of the NRC.
Nuclear Waste Policy Act of 1982
Spent Nuclear Fuel
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 Arkansas is the only one of the Utility operating companies that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 2022 of $195.0 million for the one-time fee. The fees payable to the DOE may be adjusted in the future to assure full recovery. 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. Entergy’s total spent fuel fees to date, including the one-time fee liability of Entergy Arkansas, have surpassed $1.7 billion (exclusive of amounts relating to Entergy plants that were paid or are owed by prior owners of those plants).
The permanent spent fuel repository in the U.S. has been legislated to be Yucca Mountain, Nevada. The DOE is required by law to proceed with the licensing (the DOE filed the license application in June 2008) and, after the license is granted by the NRC, proceed with the repository construction and commencement of receipt of spent fuel. 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. The DOE continues to delay meeting its obligation. Specific steps were taken to discontinue the Yucca Mountain project, including a motion to the NRC to withdraw the license application with prejudice and the establishment of a commission to develop recommendations for alternative spent fuel storage solutions. In August 2013 the U.S. Court of Appeals for the D.C. Circuit ordered the NRC to continue with the Yucca Mountain license review, but only to the extent of funds previously appropriated by Congress for that purpose and not yet used. Although the NRC completed the safety evaluation report for the license review in 2015, the previously appropriated funds are not sufficient to complete the review, including required hearings. The government has taken no effective action to date related to the recommendations of the appointed spent fuel study commission. Accordingly, large uncertainty remains regarding the time frame under which the DOE will begin to accept spent fuel from Entergy’s facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at Entergy’s nuclear sites.
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 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
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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.
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. These subsidiaries have been, and continue to be, involved in litigation to recover the damages caused by the DOE’s delay in performance. See Note 8 to the financial statements for discussion of final judgments recorded by Entergy in 2020, 2021, and 2022 related to Entergy’s nuclear owner licensee subsidiaries’ litigation with the DOE. Through 2022, Entergy’s subsidiaries have won and collected on judgments against the government totaling approximately $1 billion.
Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are providing their own spent fuel storage. Storage capability additions using dry casks began operations at ANO in 1996, at River Bend in 2005, at Grand Gulf in 2006, and at Waterford 3 in 2011. These facilities will be expanded as needed.
Nuclear Plant Decommissioning
Entergy Arkansas, Entergy Louisiana, and System Energy are entitled to recover from customers through electric rates the estimated decommissioning costs for ANO, Waterford 3, and Grand Gulf, respectively. In addition, Entergy Louisiana and Entergy Texas are entitled to recover from customers through electric rates the estimated decommissioning costs for the portion of River Bend subject to retail rate regulation. The collections are deposited in trust funds that can only be used in accordance with NRC and other applicable regulatory requirements. Entergy periodically reviews and updates the estimated decommissioning costs to reflect inflation and changes in regulatory requirements and technology, and then makes applications to the regulatory authorities to reflect, in rates, the changes in projected decommissioning costs.
In December 2018 the APSC ordered collections in rates for decommissioning ANO 2 and found that ANO 1’s decommissioning was adequately funded without additional collections. In November 2021, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that both ANO 1 and 2 decommissioning trusts were adequately funded without further collections, and in December 2021 the APSC ordered zero collections for ANO 1 and 2 decommissioning. In November 2022, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that ANO 1’s decommissioning trust was adequately funded, but that ANO 2’s fund had a projected shortage as a result of a decline in decommissioning trust fund investment values over the past year. The filing proposes a reinstatement of decommissioning cost recovery for ANO 2. Management cannot predict the outcome of this filing.
In July 2010 the LPSC approved increased decommissioning collections for Waterford 3 and the Louisiana regulated share of River Bend to address previously identified funding shortfalls. This LPSC decision contemplated that the level of decommissioning collections could be revisited should the NRC grant license extensions for both Waterford 3 and River Bend. In July 2019, following the NRC approval of license extensions for Waterford 3 and River Bend, Entergy Louisiana made a filing with the LPSC seeking to adjust decommissioning and depreciation rates for those plants, including one proposed scenario that would adjust Louisiana-jurisdictional decommissioning collections to zero for both plants (including an offsetting increase in depreciation rates). Because of the ongoing public health emergency arising from the COVID-19 pandemic and accompanying economic uncertainty, Entergy Louisiana determined that the relief sought in the filing was no longer appropriate, and in November 2020, filed an unopposed motion to dismiss the proceeding. Following that filing, in a December 2020 order, the LPSC dismissed the proceeding without prejudice. In July 2021, Entergy Louisiana made a filing with the LPSC to adjust Waterford 3 and River Bend decommissioning collections based on the latest site-specific decommissioning cost estimates for those plants. The filing seeks to increase Waterford 3 decommissioning collections and decrease River Bend decommissioning collections. The procedural schedule in the case has been suspended pending settlement negotiations. Management cannot predict the outcome of this filing.
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In December 2010 the PUCT approved increased decommissioning collections for the Texas share of River Bend to address previously identified funding shortfalls. In December 2018 the PUCT approved a settlement that eliminated River Bend decommissioning collections for the Texas jurisdictional share of the plant based on a determination by Entergy Texas that the existing decommissioning fund was adequate following license renewal. In July 2022, Entergy Texas filed a rate case that proposed continuation of the cessation of River Bend decommissioning collections. In December 2022, Entergy Texas filed on behalf of the parties a motion to abate the hearing on the merits to give parties additional time to finalize a settlement, which was approved by the presiding ALJ along with an order for the parties to file monthly settlement status reports. Management cannot predict the outcome of this filing.
In December 2016 the NRC issued a 20-year operating license renewal for Grand Gulf. In a 2017 filing at the FERC, System Energy stated that with the renewed operating license, Grand Gulf’s decommissioning trust was sufficiently funded, and proposed, among other things, to cease decommissioning collections for Grand Gulf effective October 1, 2017. The FERC accepted a settlement including the proposed decommissioning revenue requirement by letter order in August 2018.
Entergy currently believes its decommissioning funding will be sufficient for its nuclear plants subject to retail rate regulation, although decommissioning cost inflation and trust fund performance will ultimately determine the adequacy of the funding amounts.
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. In March 2021 filings with the NRC were made reporting on decommissioning funding for all of Entergy’s subsidiaries’ nuclear plants. Those reports showed that decommissioning funding for each of the nuclear plants met the NRC’s financial assurance requirements.
Additional information with respect to Entergy’s decommissioning costs and decommissioning trust funds is found in Note 9 and Note 16 to the financial statements.
Price-Anderson Act
The Price-Anderson Act requires that reactor licensees purchase and maintain the maximum amount of nuclear liability insurance available and participate in an industry assessment program called Secondary Financial Protection in order to protect 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 limits the contingent liability for a single nuclear incident to a maximum assessment of approximately $137.6 million per reactor (with 96 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, Entergy Louisiana, or System Energy is liable, protection is afforded through a combination of private insurance and the Secondary Financial Protection program. In addition to this, insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units is also purchased. The Price-Anderson Act and insurance applicable to the nuclear programs of Entergy are discussed in more detail in Note 8 to the financial statements.
NRC Reactor Oversight Process
The NRC’s Reactor Oversight Process is a program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response. The NRC evaluates plant performance by analyzing two distinct inputs: inspection findings resulting from the NRC’s inspection program and performance indicators reported by the licensee. The evaluations result in the placement of
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each plant in one of the NRC’s Reactor Oversight Process Action Matrix columns: “licensee response column,” or Column 1, “regulatory response column,” or Column 2, “degraded cornerstone column,” or Column 3, and “multiple/repetitive degraded cornerstone column,” or Column 4, and “unacceptable performance,” or Column 5. Plants in Column 1 are subject to normal NRC inspection activities. Plants in Column 2, Column 3, or Column 4 are subject to progressively increasing levels of inspection by the NRC. Continued plant operation is not permitted for plants in Column 5. All of the nuclear generating plants owned and operated by Entergy’s Utility business are currently in Column 1, except Waterford 3, which is in Column 2.
In September 2022 the NRC placed Waterford 3 in Column 2 based on an error associated with a radiation monitor calibration. Entergy corrected the issue with the radiation monitor in February 2022; however, Waterford 3 is expected to remain in Column 2 until third quarter 2023 based on a subsequent radiation monitor calibration issue.
Environmental Regulation
Entergy’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy’s businesses are in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted below. Because environmental regulations are subject to change, future compliance requirements and costs cannot be precisely estimated. Except to the extent discussed below, at this time compliance with federal, state, and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of Entergy’s businesses and is not expected to have a material effect on their competitive position, results of operations, cash flows, or financial position.
Clean Air Act and Subsequent Amendments
The Clean Air Act and its amendments establish several programs that currently or in the future may affect Entergy’s fossil-fueled generation facilities and, to a lesser extent, certain operations at nuclear and other facilities. Individual states also operate similar independent state programs or delegated federal programs that may include requirements more stringent than federal regulatory requirements. These programs include:
•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.
National Ambient Air Quality Standards
The Clean Air Act requires the EPA to set National Ambient Air Quality Standards (NAAQS) for ozone, carbon monoxide, lead, nitrogen dioxide, particulate matter, and sulfur dioxide, and requires periodic review of those standards. When an area fails to meet an ambient standard, it is considered to be in nonattainment and is classified as “marginal,” “moderate,” “serious,” or “severe.” When an area fails to meet the ambient air standard, the EPA requires state regulatory authorities to prepare state implementation plans meant to cause progress toward bringing the area into attainment with applicable standards.
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Ozone Nonattainment
Entergy Texas operates two fossil-fueled generating facilities (Lewis Creek and Montgomery County Power Station) in a geographic area that is not in attainment with the applicable NAAQS for ozone. The ozone nonattainment area that affects Entergy Texas is the Houston-Galveston-Brazoria area. Both Lewis Creek and the Montgomery County Power Station hold all necessary permits for operation and comply with applicable air quality program regulations. Measures enacted to return the area to ozone attainment could make these program regulations more stringent. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and nonattainment with the ozone NAAQS.
Potential SO2Nonattainment
The EPA issued a final rule in June 2010 adopting an SO2 1-hour national ambient air quality standard of 75 parts per billion. In Entergy’s utility service territory, only St. Bernard Parish and Evangeline Parish in Louisiana are designated as nonattainment. In August 2017 the EPA issued a letter indicating that East Baton Rouge and St. Charles parishes would be designated by December 31, 2020, as monitors were installed to determine compliance. In March 2021 the EPA published a final rule designating East Baton Rouge, St. Charles, St. James, and West Baton Rouge parishes in Louisiana as attainment/unclassifiable, and, in Texas, Jefferson County as attainment/unclassifiable and Orange County as unclassifiable. No challenges to these final designations were filed within the 60 day deadline. Entergy continues to monitor this situation.
Hazardous Air Pollutants
The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011, which had a compliance date, with a widely granted one-year extension, of April 2016. The required controls have been installed and are operational at all affected Entergy units. In May 2020 the EPA finalized a rule that finds that it is not “appropriate and necessary” to regulate hazardous air pollutants from electric steam generating units under the provisions of section 112(n) of the Clean Air Act. This is a reversal of the EPA’s previous finding requiring such regulation. The final appropriate and necessary finding does not revise the underlying MATS rule. Several lawsuits have been filed challenging the appropriate and necessary finding. In February 2021 the D.C. Circuit granted the EPA’s motion to hold the litigation in abeyance pending the agency’s review of the appropriate and necessary rule. In February 2022 the EPA issued a proposed rule revoking the 2020 rule and determining, again, that it is “appropriate and necessary” to regulate hazardous air pollutants. The EPA is seeking additional information, which it could use to further tighten the standard. Entergy will continue to monitor this situation.
Cross-State Air Pollution
In March 2005 the EPA finalized the Clean Air Interstate Rule (CAIR), which was intended to reduce SO2 and NOx emissions from electric generation plants in order to improve air quality in twenty-nine eastern states. The rule required a combination of capital investment to install pollution control equipment and increased operating costs through the purchase of emission allowances. Entergy began implementation in 2007, including installation of controls at several facilities and the development of an emission allowance procurement strategy. Based on several court challenges, CAIR and its subsequent versions, now known as the Cross-State Air Pollution Rule (CSAPR), have been remanded to and modified by the EPA on multiple occasions.
In April 2022 the EPA published a rule to address interstate transport for the 2015 ozone NAAQS which will increase the stringency of the CSAPR program in all four of the states where the Utility operating companies operate. If finalized as proposed, the rule will significantly reduce emission allowances and would likely require the installation of post-combustion nitrogen oxides (NOx) emissions controls on any coal or large legacy gas units that will operate beyond 2026 and are not currently equipped with such controls. Fifteen Entergy-owned units, totaling approximately 9,370 MW of total unit capacity, are identified by the EPA for selective catalytic reduction retrofits.
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Based on the EPA estimates, Entergy’s share of the capital costs would be approximately $1.6 billion if all the identified units were in fact retrofitted. Additionally, the EPA is proposing controls on certain non-electric generating NOx sources. Since releasing the proposed rule, the price for Group 3 NOx sources allowances has increased significantly, peaking at over $45,000 per allowance in late August 2022 before stabilizing in the range of $15,000 to $18,000 per allowance since September 2022. Comments on the proposed rule were due in June 2022. MISO, other impacted regional transmission organizations, and various state public service commissions all filed comments expressing reliability concerns if the rule is finalized as proposed. Entergy filed individual comments which assert, in addition to other issues, that the EPA’s proposal represents over-control of the Entergy units in Arkansas and Mississippi; the EPA should consider an alternative approach or provide flexibility for units with a limited remaining useful life; the EPA should consult with regional transmission organizations to determine the reliability impacts of the proposed rule; and the EPA should consider and incorporate current economic trends, including inflation, into any benefit-costs analysis supporting the rule.
Regional Haze
In June 2005 the EPA issued its final Clean Air Visibility Rule (CAVR) regulations that potentially could result in a requirement to install SO2 and NOx pollution control technology as Best Available Retrofit Control Technology to continue operating certain of Entergy’s fossil generation units. The rule leaves certain CAVR determinations to the states. This rule establishes a series of 10-year planning periods, with states required to develop State Implementation Plans (SIPs) for each planning period, with each SIP including such air pollution control measures as may be necessary to achieve the ultimate goal of the CAVR by the year 2064. The various states are currently in the process of developing SIPs to implement the second planning period of the CAVR, which addresses the 2018-2028 planning period.
In January and February 2018, Entergy Arkansas, Entergy Mississippi, Entergy Power, and other co-owners received 60-day notice of intent to sue letters from the Sierra Club and the National Parks Conservation Association concerning allegations of violations of new source review and permitting provisions of the Clean Air Act at the Independence and White Bluff coal-burning units, respectively. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims and reducing the risk that Entergy Arkansas, as operator of Independence and White Bluff, might be compelled under the Clean Air Act’s regional haze program to install costly emissions control technologies. Consistent with the terms of the settlement, Entergy Arkansas, along with co-owners, agreed to begin using only low-sulfur coal at Independence and White Bluff by mid-2021; agreed to cease using coal at White Bluff and Independence by the end of 2028 and 2030, respectively; agreed to cease operation of the remaining gas unit at Lake Catherine by the end of 2027; reserved the option to develop new generating sources at each plant site; and committed to installing or proposing to regulators at least 800 MWs of renewable generation by the end of 2027, with at least half installed or proposed by the end of 2022 (which includes two existing Entergy Arkansas projects) and with all qualifying co-owner projects counting toward satisfaction of the obligation. Under the settlement, the Sierra Club and the National Parks Conservation Association also waived certain potential existing claims under federal and state environmental law with respect to specified generating plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the National Parks Conservation Association, was subject to approval by the U.S. District Court for the Eastern District of Arkansas. In November 2020 the court denied motions by the Arkansas Attorney General and the Arkansas Affordable Energy Coalition to intervene and to stay the proceedings. The proposed intervenors did not appeal the ruling. The District Court approved and entered the proposed settlement in March 2021. Entergy met the settlement deadline to use low-sulfur coal and is on target to meet the other requirements of the settlement. See “Remaining Useful Lives Review” in the “State and Local Rate Regulation and Fuel-Cost Recovery” section of Entergy Arkansas, LLC and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the APSC’s proceeding related to Entergy Arkansas’s utility generation units.
The second planning period (2018-2028) for the regional haze program requires states to examine sources for impacts on visibility and to prepare SIPs by July 31, 2021 to ensure reasonable progress is being made to attain
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visibility improvements. Entergy received information collection requests from the Arkansas and Louisiana Departments of Environmental Quality requesting an evaluation of technical and economic feasibility of various NOx and SO2 control technologies for Independence, Nelson 6, Nelson Industrial Steam Company (NISCO), and Ninemile. Responses to the information collection requests have been submitted to the respective state agencies. Louisiana has issued its draft SIP which, at this time, does not propose any additional air emissions controls for the affected Entergy units in Louisiana. Some public commenters, however, believe additional air controls are cost-effective. It is not yet clear how the Louisiana Department of Environmental Quality (LDEQ) will respond in its final SIP, and the agency, like many other state agencies, did not meet the July 31, 2021 deadline to submit a SIP to the EPA for review.
Similar to the LDEQ, the Arkansas Department of Energy and Environment, Division of Environmental Quality (ADEQ) did not meet the July 31, 2021 SIP submission deadline, but subsequently submitted it to the EPA for review. The ADEQ reviewed Entergy’s Independence plant, but determined that additional air emission controls would not be cost-effective considering the facility’s commitment to cease coal-fired combustion by December 31, 2030.
The Texas Commission on Environmental Quality has completed its second-planning period SIP and submitted it to the EPA for review. There were no Entergy sources selected for additional emission controls. The Mississippi Department of Environmental Quality continues to develop its SIP, but there are no Entergy sources that are expected to be impacted.
In August 2022 the EPA issued findings of failure to submit regional haze SIPs to 15 states, including Louisiana and Mississippi. These findings were effective September 2022 and start the two-year period for the EPA to either approve a SIP submitted by the state or issue a final federal plan.
Greenhouse Gas Emissions
In July 2019 the EPA released the Affordable Clean Energy Rule (ACE), which applies only to existing coal-fired electric generating units. The ACE determines that heat rate improvements are the best system of emission reductions and lists six candidate technologies for consideration by states at each coal unit. The rule and associated rulemakings by the EPA replace the Obama administration’s Clean Power Plan, which established national emissions performance rates for existing fossil-fuel fired steam electric generating units and combustion turbines. The ACE rule provides states discretion in determining how the best system for emission reductions applies to individual units, including through the consideration of technical feasibility and the remaining useful life of the facility. The ADEQ and the LDEQ have issued information collection requests to Entergy facilities to help the states collect the information needed to determine the best system of emission reductions for each facility. Entergy responded to the requests. In January 2021 the U.S. Court of Appeals for the D.C. Circuit vacated ACE. The court held that ACE relied on an incorrect interpretation of the Clean Air Act that the statute expressly forecloses emission reduction approaches, such as emissions trading and generating shifting, that cannot be applied at and to the individual source. The court remanded ACE to the EPA for further consideration and also vacated the repeal of the Clean Power Plan. In March 2021 the D.C. Circuit issued a partial mandate vacating the ACE rule, but withheld the mandate vacating the repeal of the Clean Power Plan pending the EPA’s new rulemaking to regulate greenhouse gas emissions. Thus, there currently is no regulation in place with respect to greenhouse gas emissions from existing electric generating units and states are not expected to take further action to develop and submit plans at this time. In October 2021 the United States Supreme Court agreed to hear a challenge to the already vacated ACE rule. In June 2022 the United States Supreme Court held that the EPA could not use generation shifting as the best system of emission reduction under Section 111(d) of the Clean Air Act. The EPA does still have the authority to regulate greenhouse gas emissions, but those emissions reductions must be technology based. The EPA has announced its intent to propose a rule for existing power plants pursuant to the Clean Air Act by March 2023. The ultimate impact of the United States Supreme Court's decision cannot be determined at this time.
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In April 2021, President Biden announced a target for the United States in connection with the United Nations’ “Paris Agreement” on climate change. The target consists of a 50-52 percent reduction in economy-wide net greenhouse gas emissions from 2005 levels by 2030. President Biden has also stated that a goal of his administration is for the electric power industry to decarbonize fully by 2035. The details surrounding implementation of these targets are not finalized, and the impacts to Entergy of any potential related legislation cannot be predicted.
Entergy continues to support national legislation that would most efficiently reduce economy-wide greenhouse gas emissions and increase planning certainty for electric utilities. By virtue of its proportionally large investment in low-emitting generation technologies, Entergy has a low overall carbon dioxide emission “intensity,” or rate of carbon dioxide emitted per megawatt-hour of electricity generated. In anticipation of the imposition of carbon dioxide emission limits on the electric industry, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included a formal program to stabilize owned power plant carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in reducing emissions below 2000 levels. In 2006, Entergy started including emissions from controllable power purchases in addition to its ownership share of generation and established a second formal voluntary program to stabilize power plant carbon dioxide emissions and emissions from controllable power purchases, cumulatively over the period, at 20% below 2000 levels through 2010. In 2011, Entergy extended this commitment through 2020, which it ultimately outperformed by approximately 8% both cumulatively and on an annual basis. In 2019, in connection with a climate scenario analysis following the recommendations of the Task Force on Climate-related Financial Disclosures describing climate-related governance, strategy, risk management, and metrics and targets, Entergy announced a 2030 carbon dioxide emission rate goal focused on a 50% reduction from Entergy’s base year - 2000. Entergy now anticipates achieving this reduction several years early. In September 2020, Entergy announced a commitment to achieve net-zero greenhouse gas emissions by 2050 inclusive of all businesses, all applicable gases, and all emission scopes. In 2022, Entergy enhanced its commitment to include an interim goal of 50% carbon-free energy generating capacity by 2030 and expanded its interim emission rate goal to include all purchased power. See “Risk Factors” in Part I Item 1A for discussion of the risks associated with achieving these climate goals. Entergy’s comprehensive, third-party verified greenhouse gas inventory and progress against its voluntary goals are published on its website.
Entergy participates in the M.J. Bradley & Associates’ Annual Benchmarking Air Emissions Report, an annual analysis of the 100 largest U.S. electric power producers. The report is available on the M.J. Bradley website. Entergy participates annually in the Dow Jones Sustainability Index and in 2022 was listed on the North American Index. Entergy has been listed on the World or North American Index, or both, for 21 consecutive years. Entergy also participated in the 2022 CDP Climate Change and CDP Water Security evaluations, receiving a ‘B’ for both responses.
Potential Legislative, Regulatory, and Judicial Developments
In addition to the specific instances described above, there are a number of legislative and regulatory initiatives that are under consideration at the federal, state, and local level. Because of the nature of Entergy’s business, the imposition of any of these initiatives could affect Entergy’s operations. Entergy continues to monitor these initiatives and activities in order to analyze their potential operational and cost implications. These initiatives include:
•reconsideration and revision of ambient air quality standards downward which could lead to additional areas of nonattainment;
•designation by the EPA and state environmental agencies of areas that are not in attainment with national ambient air quality standards;
•introduction of bills in Congress and development of regulations by the EPA proposing further limits on SO2, mercury, carbon dioxide, and other air emissions. New legislation or regulations applicable to
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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 cap and trade programs to limit carbon dioxide and other greenhouse gases;
•efforts on the local, 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 polychlorinated biphenyls (PCBs);
•efforts by certain external groups to encourage reporting and disclosure of environmental, social, and governance 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;
•the regulation of the management, disposal, and beneficial reuse of coal combustion residuals; and
•the regulation of the management and disposal and recycling of equipment associated with renewable and clean energy sources such as used solar panels, wind turbine blades, hydrogen usage, or battery storage.
Clean Water Act
The 1972 amendments to the Federal Water Pollution Control Act (known as the Clean Water Act) provide the statutory basis for the National Pollutant Discharge Elimination System permit program, section 402, and the basic structure for regulating the discharge of pollutants from point sources to waters of the United States. The Clean Water Act requires virtually all discharges of pollutants to waters of the United States to be permitted. Section 316(b) of the Clean Water Act regulates cooling water intake structures, section 401 of the Clean Water Act requires a water quality certification from the state in support of certain federal actions and approvals, and section 404 regulates the dredge and fill of waters of the United States, including jurisdictional wetlands.
Federal Jurisdiction of Waters of the United States
In June 2020 the EPA’s revised definition of waters of the United States in the Navigable Waters Protection Rule (NWPR) became effective, narrowing the scope of Clean Water Act jurisdiction, as compared to a 2015 definition which had been stayed by several federal courts. In August 2021 a federal district court vacated and remanded the NWPR for further consideration. The EPA and the U.S. Army Corps of Engineers (Corps) subsequently issued a statement that the agencies would revert to pre-2015 regulations pending a new rulemaking. In December 2022 the EPA and the Corps released a final definition of waters of the United States that replaces the NWPR with a definition that is consistent with the pre-2015 regulatory regime as interpreted by several United States Supreme Court decisions. Most notably, the exclusion for waste treatment systems is retained.
Comprehensive Environmental Response, Compensation, and Liability Act of 1980
The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), authorizes the EPA to mandate clean-up by, or to collect reimbursement of clean-up costs from, owners or operators of sites at which hazardous substances may be or have been released. Certain private parties also may use CERCLA to recover response costs. Parties that transported hazardous substances to these sites or arranged for the disposal of the substances are also deemed liable by CERCLA. CERCLA has been interpreted to impose strict, joint, and several liability on responsible parties. Many states have adopted programs similar to CERCLA. Entergy subsidiaries in the Utility and Entergy Wholesale Commodities businesses have sent waste materials to various
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disposal sites over the years, and releases have occurred at Entergy facilities including nuclear facilities that have been or will be sold to decommissioning companies. In addition, environmental laws now regulate certain of Entergy’s operating procedures and maintenance practices that historically were not subject to regulation. Some disposal sites used by Entergy subsidiaries have been the subject of governmental action under CERCLA or similar state programs, resulting in site clean-up activities. Entergy subsidiaries have participated to various degrees in accordance with their respective potential liabilities in such site clean-ups and have developed experience with clean-up costs. The affected Entergy subsidiaries have established provisions for the liabilities for such environmental clean-up and restoration activities. Details of potentially material CERCLA and similar state program liabilities are discussed in the “Other Environmental Matters” section below.
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. As of December 31, 2022, Entergy has recorded asset retirement obligations related to CCR management of $27 million.
Pursuant to the EPA Rule, Entergy operates groundwater monitoring systems surrounding its coal combustion residual landfills located at White Bluff, Independence, and Nelson. Monitoring to date has detected concentrations of certain listed constituents in the area, but has not indicated that these constituents originated at the active landfill cells. Reporting has occurred as required, and detection monitoring will continue as the rule requires. In late-2017, Entergy determined that certain in-ground wastewater treatment system recycle ponds at its White Bluff and Independence facilities require management under the new EPA regulations. Consequently, in order to move away from using the recycle ponds, White Bluff and Independence each have installed a new permanent bottom ash handling system that does not fall under the CCR rule. As of November 2020, both sites are operating the new system and no longer are sending waste to the recycle ponds. Each site has commenced closure of its two recycle ponds (four ponds total), prior to the April 11, 2021 deadline under the finalized CCR rule for unlined recycle ponds. Any potential requirements for corrective action or operational changes under the new CCR rule continue to be assessed. Notably, ongoing litigation has resulted in the EPA’s continuing review of the rule. Consequently, the nature and cost of additional corrective action requirements may depend, in part, on the outcome of the EPA’s review.
Other Environmental Matters
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas
The EPA notified Entergy that the EPA believes Entergy is a PRP concerning PCB contamination at the F.J. Doyle Salvage facility in Leonard, Texas. The facility operated as a scrap salvage business during the 1970s to the 1990s. In May 2018 the EPA investigated the site surface and sub-surface soils and, in November 2018 the EPA conducted a removal action, including disposal of PCB contaminated soils. Entergy responded to the EPA’s information requests in May and July 2019. In November 2020 the EPA sent Entergy and other PRPs a demand letter seeking reimbursement for response costs totaling $4 million expended at the site. Liability and PRP
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allocation of response costs are yet to be determined. In December 2020, Entergy responded to the demand letter, without admitting liability or waiving any rights, indicating that it would engage in good faith negotiations with the EPA with respect to the demand. An initial meeting between the EPA and the PRPs took place in June 2021. Negotiations between the PRPs and the EPA are ongoing.
Litigation
Entergy uses legal and appropriate means to contest litigation threatened or filed against it, but certain states in which Entergy operates have proven to be unusually litigious environments. Judges and juries in Louisiana, Mississippi, and Texas have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. The litigation environment in these states poses a significant business risk to Entergy.
Asbestos Litigation(Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas)
See Note 8 to the financial statements for a discussion of this litigation.
Employment and Labor-related Proceedings (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
See Note 8 to the financial statements for a discussion of these proceedings.
Human Capital
Employees
Employees are an integral part of Entergy’s commitment to serving customers. As of December 31, 2022, Entergy subsidiaries employed 11,707 people.
| | | | | |
| Utility: | |
| Entergy Arkansas | 1,227 | |
| Entergy Louisiana | 1,597 | |
| Entergy Mississippi | 716 | |
| Entergy New Orleans | 296 | |
| Entergy Texas | 648 | |
| System Energy | — | |
| Entergy Operations | 3,317 | |
| Entergy Services | 3,870 | |
| Entergy Nuclear Operations | 13 | |
| Other subsidiaries | 23 | |
| Total Entergy | 11,707 | |
Approximately 3,084 employees are represented by the International Brotherhood of Electrical Workers, the United Government Security Officers of America, and the International Union, Security, Police, and Fire Professionals of America.
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Below is the breakdown of Entergy’s employees by gender and race/ethnicity:
| | | | | | | | | | | |
| Gender (%) | 2022 | | 2021 |
| Female | 22.2 | | 21.4 |
| Male | 77.8 | | 78.6 |
| | | | | | | | | | | |
| Race/Ethnicity (%) | 2022 | | 2021 |
| White | 74.8 | | 76.4 |
| Black/African American | 17.3 | | 16.4 |
| Hispanic/Latino | 3.0 | | 2.7 |
| Asian | 2.3 | | 2.0 |
| Other | 2.6 | | 2.5 |
Entergy’s Approach to Human Resources
Entergy’s people and culture enable its success; that is why acquiring, retaining, and developing talent are important components of Entergy’s human resources strategy. Entergy focuses on an approach that includes, among other things, governance and oversight; safety; organizational health, including diversity, inclusion, and belonging; and talent management.
Governance and Oversight
Ensuring that workplace processes support the desired culture and strategy begins with the Board of Directors and the Office of the Chief Executive. The Talent and Compensation Committee (formerly Personnel Committee) establishes priorities and each quarter reviews strategies and results on a range of topics covering the workforce, the workplace, and the marketplace. It oversees Entergy’s incentive plan design and administers its executive compensation plans to incentivize the behaviors and outcomes that support achievement of Entergy’s corporate objectives. Annually, it reviews executive performance, development, succession plans, and talent pipeline to align a high performing executive team with Entergy’s priorities. The Talent and Compensation Committee also oversees Entergy’s performance through regular briefings on a wide variety of human resources topics including Entergy’s safety culture and performance; organizational health; and diversity, inclusion, and belonging initiatives and performance.
The Talent and Compensation Committee’s Charter was revised in 2021 to acknowledge the committee’s responsibility for overseeing and monitoring the effectiveness of Entergy’s human capital strategies, including its workforce diversity, inclusion, and organizational health and safety strategies, programs, and initiatives. In recognition of the importance that organizational health and diversity, inclusion, and belonging play in enabling Entergy to achieve its business strategies, the committee receives periodic reports on Entergy’s organization health and diversity, inclusion, and belonging programs, strategies, and performance, including briefings at each of its regular meetings. The committee also receives updates on Entergy’s performance to date on key workforce, workplace, and marketplace measures, including progress in the representation of women and underrepresented minorities, both in the total workforce and in director level and above placements, progress in key diversity, inclusion, and belonging initiatives and diverse supplier spend.
Other committees of the Board oversee other key aspects of Entergy’s culture. For example, the Audit Committee reviews reports on enterprise risks, ethics, and compliance training and performance, as well as regular reports on calls made to Entergy’s ethics line and related investigations. To maximize the sharing of information and facilitate the participation of all Board members in these discussions, the Board schedules its regular committee meetings in a manner such that all directors can attend.
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The Office of the Chief Executive, which includes the Senior Vice President and Chief Human Resources Officer, ensures annual business plans are designed to support Entergy’s talent objectives, reviews workforce-related metrics, and regularly discusses the development, succession planning, and performance of their direct reports and other company officers.
Safety
Entergy’s safety objective is: Everyone Safe. All Day. Every Day. The continuation of the COVID-19 pandemic and another historic hurricane season presented significant challenges. Entergy employees achieved a total recordable incident rate of 0.51 in 2022, compared to 0.46 in 2021, and 0.40 in 2020. The results of 2021 unfortunately included an employee fatality. Entergy has enhanced dramatically leadership efforts and field presence to further its objective of zero fatalities, which it achieved in 2022. Also in 2022, there was a significant decrease in the number of serious injuries. The recordable incident rate equals the number of recordable incidents per 100 full-time equivalents. Recordable incidents include fatalities, lost-time accidents, restricted-duty accidents, and medical attentions and is not inclusive of potential work-related COVID-19 cases.
Organizational Health, including Diversity, Inclusion and Belonging (DIB)
Entergy believes that organizational health fosters an engaged and productive culture that positions Entergy to deliver sustainable value to its stakeholders. Entergy measures its progress through an organizational health survey coordinated by an external third party. Since initially administering the survey in 2014, Entergy improved from an initial score of 49 (fourth quartile) to a score in 2020 of 72 (second quartile), in 2021 of 63 (third quartile), and in 2022 of 61 (third quartile). Although the score declined slightly in 2022 as compared to 2021, it improved from the 2014 baseline. Management uses the results of the annual survey to design and implement strategies to positively influence organizational health. Initial employee participation of 66 percent in 2014 rose to and remains at approximately 90 percent in 2019-2022.
Entergy believes that creating a culture of diversity, inclusion, and belonging drives foundational engagement. Entergy is committed to developing and retaining a workforce that reflects the rich diversity of the communities it serves. In 2019, Entergy embarked on a three-year phased approach to enhance inclusion for individuals and teams. In 2022, Entergy continued to focus its actions to engage a diverse workforce, infusing DIB into hiring policies, practices and procedures, aligning Employee Resource Group goals to DIB goals, growing its DIB Champion network, integrating DIB into Entergy’s leadership development programs, and facilitating training from the executive leadership ranks down to the frontline. Through these efforts, Entergy aspires to create greater understanding and accountability regarding the behaviors and outcomes that are indicative of a premier utility.
Talent Management
Entergy’s focus on talent management is organized in three areas: developing and attracting a diverse pool of talent, equipping its leaders to develop the organization, and building premier utility capability through employee performance management and succession programs. Entergy believes that developing a diverse pool of local talent equipped with the skills needed, today and in the future, and reflecting the communities Entergy serves will give it a long-term competitive advantage. The focus of Entergy’s leadership development programs is to equip managers with the skills needed to effectively develop their teams and improve the leader-employee relationship. Entergy’s talent development infrastructure, which includes a combination of business function-specific and enterprise-wide learning and development programs, is designed to ensure Entergy has qualified staff with the skills, experiences, and behaviors needed to perform today and prepare for the future. Entergy strives to achieve its strategic priorities by aligning and enhancing team and individual performance with business objectives, effectively deploying talent through succession planning, and managing workforce transitions.
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Availability of SEC filings and other information on Entergy’s website
Entergy electronically files reports with the SEC, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxies, and amendments to such reports. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding registrants that file electronically with the SEC at http://www.sec.gov. Copies of the reports that Entergy files with the SEC can be obtained at the SEC’s website.
Entergy uses its website, http://www.entergy.com, as a routine channel for distribution of important information, including news releases, analyst presentations and financial information. Filings made with the SEC are posted and available without charge on Entergy’s website as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. These filings include annual and quarterly reports on Forms 10-K and 10-Q and current reports on Form 8-K (including related filings in XBRL format); proxy statements; and any amendments to those reports or statements. All such postings and filings are available on Entergy’s Investor Relations website free of charge. Entergy is providing the address to its internet site solely for the information of investors and does not intend the address to be an active link. The contents of the website are not incorporated into this report.
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Item 1A. RISK FACTORS
See “RISK FACTORS SUMMARY” in Part I Item 1 for a summary of Entergy’s and the Registrant Subsidiaries’ risk factors.
Investors should review carefully the following risk factors and the other information in this Form 10-K. The risks that Entergy faces are not limited to those in this section. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely affect Entergy’s financial condition, results of operations, and liquidity. See “FORWARD-LOOKING INFORMATION.”
Utility Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The terms and conditions of service, including electric and gas rates, of the Utility operating companies and System Energy are determined through regulatory approval proceedings that can be lengthy and subject to appeal, potentially resulting in delays in effecting rate changes, lengthy litigation, the risk of disallowance of recovery of certain costs, and uncertainty as to ultimate results.
The Utility operating companies are regulated on a cost-of-service and rate of return basis and are subject to statutes and regulatory commission rules and procedures. The rates that the Utility operating companies and System Energy charge reflect their capital expenditures, operations and maintenance costs, allowed rates of return, financing costs, and related costs of service. These rates significantly influence the financial condition, results of operations, and liquidity of Entergy and each of the Utility operating companies and System Energy. These rates are determined in regulatory proceedings and are subject to periodic regulatory review and adjustment, including adjustment upon the initiative of a regulator or, in some cases, affected stakeholders. Regulators in a future rate proceeding may alter the timing or amount of certain costs for which recovery is allowed or modify the current authorized rate of return. Rate refunds may also be required, subject to applicable law.
In addition, regulators have initiated and may initiate additional proceedings to investigate the prudence of costs in the Utility operating companies’ and System Energy’s base rates and examine, among other things, the reasonableness or prudence of the companies’ operation and maintenance practices, level of expenditures (including storm costs and costs associated with capital projects), allowed rates of return and rate base, proposed resource acquisitions, and previously incurred capital expenditures that the operating companies seek to place in rates. The regulators may disallow costs subject to their jurisdiction found not to have been prudently incurred or found not to have been incurred in compliance with applicable tariffs, creating some risk to the ultimate recovery of those costs. Regulatory proceedings relating to rates and other matters typically involve multiple parties seeking to limit or reduce rates. Traditional base rate proceedings, as opposed to formula rate plans, generally have long timelines, are primarily based on historical costs, and may or may not be limited in scope or duration by statute. The length of these base rate proceedings can cause the Utility operating companies and System Energy to experience regulatory lag in recovering costs through rates, such that the Utility operating companies may not fully recover all costs during the rate effective period and may, therefore, earn less than their allowed returns. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with rate case proceedings. For a discussion of such appeals and related litigation for both the Utility operating companies and System Energy, see Note 2 to the financial statements.
The Utility operating companies have large customer and stakeholder bases and, as a result, could be the subject of public criticism or adverse publicity focused on issues including the operation and maintenance of their assets and infrastructure, their preparedness for major storms or other extreme weather events and/or the time it takes to restore service after such events, or the quality of their service or the reasonableness of the cost of their
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service. Criticism or adverse publicity of this nature could render legislatures and other governing bodies, public service commissions and other regulatory authorities, and government officials less likely to view the applicable operating company in a favorable light and could potentially negatively affect legislative or regulatory processes or outcomes, as well as lead to increased regulatory oversight or more stringent legislative or regulatory requirements or other legislation or regulatory actions that adversely affect the Utility operating companies.
The Utility operating companies and System Energy, and the energy industry as a whole, have experienced a period of rising costs and investments and an upward trend in spending, especially with respect to infrastructure investments, which is likely to continue in the foreseeable future and could result in more frequent rate cases and requests for, and the continuation of, cost recovery mechanisms, all of which could face resistance from customers and other stakeholders especially in a rising cost environment, whether due to inflation or high fuel prices or otherwise, and/or in periods of economic decline or hardship. Significant increases in costs could increase financing needs and otherwise adversely affect Entergy, the Utility operating companies, and System Energy’s business, financial position, results of operation, or cash flows. For information regarding rate case proceedings and formula rate plans applicable to the Utility operating companies, see Note 2 to the financial statements.
Changes to state or federal legislation or regulation affecting electric generation, electric and natural gas transmission, distribution, and related activities could adversely affect Entergy and the Utility operating companies’ financial position, results of operations, or cash flows and their utility businesses.
If legislative and regulatory structures evolve in a manner that erodes the Utility operating companies’ exclusive rights to serve their regulated customers, they could lose customers and sales and their results of operations, financial position, or cash flows could be materially affected. Additionally, technological advances in energy efficiency and distributed energy resources are reducing the costs of these technologies and, together with ongoing state and federal subsidies, the increasing penetration of these technologies could result in reduced sales by the Utility operating companies. Such loss of sales, due to the methodology used to determine cost of service rates or otherwise, could put upward pressure on rates, possibly resulting in adverse regulatory actions to mitigate such effects on rates. Further, the failure of regulatory structures to evolve to accommodate the changing needs and desires of customers with respect to the sourcing and use of electricity also could diminish sales by the operating companies. Entergy and the Utility operating companies cannot predict if or when they may be subject to changes in legislation or regulation, or the extent and timing of reductions of the cost of distributed energy resources, nor can they predict the impact of these changes on their results of operations, financial position, or cash flows.
The Utility operating companies recover fuel, purchased power, and associated costs through rate mechanisms that are subject to risks of delay or disallowance in regulatory proceedings, and sudden or prolonged increases in fuel and purchased power costs could lead to increased customer arrearages or bad debt expenses.
The Utility operating companies recover their fuel, purchased power, and associated costs from their customers through rate mechanisms subject to periodic regulatory review and adjustment. Because regulatory review can result in the disallowance of incurred costs found not to have been prudently incurred or not reflected in rates as permitted by approved rate schedules and accounting rules, including the cost of replacement power purchased when generators experience outages or when planned outages are extended, with the possibility of refunds to ratepayers, there exists some risk to the ultimate recovery of those costs, particularly when there are substantial or sudden increases in such costs. Regulators also may initiate proceedings to investigate the continued usage or the adequacy and operation of the fuel and purchased power recovery clauses of the Utility operating companies and, therefore, there can be no assurance that existing recovery mechanisms will remain unchanged or in effect at all.
The Utility operating companies’ cash flows can be negatively affected by the time delays between when gas, power, or other commodities are purchased and the ultimate recovery from customers of the costs in rates. On occasion, when the level of incurred costs for fuel and purchased power rises very dramatically, some
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of the Utility operating companies may agree to defer recovery of a portion of that period’s fuel and purchased power costs for recovery at a later date, which could increase the near-term working capital and borrowing requirements of those companies. The Utility operating companies also may experience, and in some instances have experienced, an increase in customer bill arrearages and bad debt expenses due to, among other reasons, increases in fuel and purchased power costs, especially in periods of economic decline or hardship. For a description of fuel and purchased power recovery mechanisms and information regarding the regulatory proceedings for fuel and purchased power cost recovery, see Note 2 to the financial statements.
The Utility operating companies are subject to economic risks associated with participation in the MISO markets and the allocation of transmission upgrade costs. The operation of the Utility operating companies’ transmission system pursuant to the MISO RTO tariff and their participation in the MISO RTO’s wholesale markets may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
On December 19, 2013, the Utility operating companies integrated into the MISO RTO. MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their owned and controlled generating facilities into the MISO resource adequacy construct (the annual Planning Resource Auction, discussed below), as well as the day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. The Utility operating companies are subject to economic risks associated with participation in the MISO markets and resource adequacy construct. MISO tariff rules and system conditions, including transmission congestion, could affect the Utility operating companies’ ability to sell capacity, energy, and/or ancillary services in certain regions and/or the economic value of such sales, or the cost of serving the Utility operating companies’ respective loads. MISO market rules may change or be interpreted in ways that cause additional cost and risk, including compliance risk.
The Utility operating companies participate in the MISO regional transmission planning process and are subject to risks associated with planning decisions that MISO makes in the exercise of control over the planning of the Utility operating companies’ transmission assets that are under MISO’s functional control. The Utility operating companies pay transmission rates that reflect the cost of transmission projects that the Utility operating companies do not own, which could increase cash or financing needs. Further, FERC policies and regulation addressing cost responsibility for transmission projects, including transmission projects to interconnect new generation facilities, may potentially give rise to cash and financing-related risks as well as result in upward pressure on the retail rates of the Utility operating companies, which, in turn, may result in adverse actions by the Utility operating companies’ retail regulators. In addition to the cash and financing-related risks arising from the potential additional cost allocation to the Utility operating companies from transmission projects of others or changes in FERC policies or regulation related to cost responsibility for transmission projects, there is a risk that the Utility operating companies’ business and financial position could be harmed as a result of lost investment opportunities and other effects that flow from an increased number of competitive projects being approved and constructed that are interconnected with their transmission systems.
Further, the terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets, the allocation of transmission upgrade costs, the MISO-wide allowed base rate of return on equity, and any required MISO-related charges and credits are subject to regulation by the FERC. The operation of the Utility operating companies’ transmission system pursuant to the MISO tariff and their participation in the MISO wholesale markets, and the resulting costs, may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
Moreover, the resource adequacy construct provided under the MISO tariff confers certain rights and imposes certain obligations upon load-serving entities, including the Utility operating companies, that are served
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from the transmission systems subject to MISO’s functional control, including the transmission facilities of the Utility operating companies. The MISO tariff provisions governing these rights and obligations are subject to change and have recently undergone significant changes, some of which are the subject of pending litigation and/or appeals. Due to their magnitude and the speed with which they have been implemented, these changes carry risk, including compliance risk, and may result in material additional costs being passed through to the Utility operating companies’ customers in retail rates, including but not limited to additional capacity costs incurred in the annual MISO Planning Resource Auction. Also, by virtue of the Utility operating companies’ participation in MISO and the design and terms of the MISO resource adequacy construct, other load-serving entities served by the Utility operating companies’ transmission assets, which are under MISO’s functional control, may be able to circumvent reasonable resource planning obligations and avoid, in whole or in part, the full cost of procuring the resources reasonably needed to reliably supply their respective loads. In particular, the design of the current MISO resource adequacy construct and the absence of a minimum capacity obligation in MISO create a risk of other load-serving entities engaging in “free ridership” through their strategy for participation in the MISO resource adequacy construct and energy and ancillary services markets – specifically, by using energy and ancillary services available from the Utility operating companies’ owned and controlled generating units without paying a reasonable share of the cost of the capacity required to provide such energy and ancillary services. As a result, there are a variety of risks to the Utility operating companies and their customers, including the risk of bearing additional costs for resources needed to ensure reliable service, the risk of reduced reliability and the enhanced risk of outages and lost sales which, because of the methodology for establishing cost of service rates, presents the risk of upward pressure on the Utility operating companies’ rates.
In addition, orders from each of the Utility operating companies’ respective retail regulators generally require that the Utility operating companies make periodic filings, or generally allow the retail regulator to direct the making of such filings, setting forth the results of analysis of the costs and benefits realized from MISO membership as well as the projected costs and benefits of continued membership in MISO and/or requesting approval of their continued membership in MISO. These filings have been submitted periodically by each of the Utility operating companies as required by their respective retail regulators, and the outcome of the resulting proceedings may affect the Utility operating companies’ continued membership in MISO.
The continued impacts of the COVID-19 pandemic and responsive measures taken on Entergy’s and its Utility operating companies’ business, results of operations, and financial condition are highly uncertain and cannot be predicted.
The global 2019 novel coronavirus pandemic continues to be an evolving situation and could lead to further disruption of the general economy, impacts on the customers of Entergy’s Utility operating companies, and disruption of the operations of Entergy’s subsidiaries, whether due to, among other things, the emergence or spread of new variants of COVID-19, precautionary or reactionary measures, market reactions or impacts, or supply chain constraints.
Entergy and its Utility operating companies experienced an increase in arrearages and bad debt expense due to non-payment by customers. The arrearages due to COVID-19 have begun to decline, although management cannot predict the timing of the completion of collections of such arrearages. While the Utility operating companies are working with regulators to ensure ultimate recovery for those and other COVID-19 related costs, the amount, method, and timing of such recovery is subject to approval by the retail regulators.
Entergy and its Registrant Subsidiaries also could experience, and in some cases have experienced, among other challenges that originated during or have been exacerbated by the COVID-19 pandemic: supply chain, vendor, and contractor disruptions, including shortages or delays in the availability of key components, parts, and supplies such as electronic components and solar panels; delays in completion of capital or other construction projects, maintenance, and other operations activities, including prolonged or delayed refueling and maintenance outages; delays in regulatory proceedings; workforce availability challenges, including from COVID-19 infections, health, or safety issues; increased storm recovery costs; increased cybersecurity risks as a result of many employees
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telecommuting; volatility in the credit or capital markets (and any related increased cost of capital or any inability to access the capital markets or draw on available credit facilities); or other adverse impacts on their ability to execute on business strategies and initiatives.
Although the economy has been recovering, another economic decline could adversely impact Entergy’s and the Utility operating companies’ liquidity and cash flows, including through declining sales, reduced revenues, delays in receipts of customer payments, or increased bad debt expense. The Utility operating companies also may experience regulatory outcomes that require them to postpone planned investment and otherwise reduce costs due to the impact of the COVID-19 pandemic on their customers, especially in an environment of higher inflation. In addition, if the COVID-19 pandemic or related impacts create additional disruptions or turmoil in the credit or financial markets, or adversely impact Entergy’s credit metrics or ratings, such developments could adversely affect its ability to access capital on favorable terms and continue to meet its liquidity needs or cause a decrease in the value of its defined benefit pension trust funds, as well as its nuclear decommissioning trust funds, all of which are highly uncertain and cannot be predicted.
Entergy cannot predict the extent or duration of the ongoing COVID-19 pandemic, the impact of new or existing variants of COVID-19, the effectiveness of mitigation efforts, further governmental responsive measures, or the extent of the effects or ultimate impacts on the global, national or local economy, the capital markets, or its customers, suppliers, operations, financial condition, results of operations, or cash flows.
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather, the impact on customer bills of permitted storm cost recovery, or the inability to securitize future storm restoration costs could have material effects on Entergy and its Utility operating companies.
Entergy’s and its Utility operating companies’ results of operations, liquidity, and financial condition can be materially affected by the destructive effects of severe weather. Severe weather can also result in significant outages for the customers of the Utility operating companies and, therefore, reduced revenues for the Utility operating companies during the period of the outages. A delay or failure in recovering amounts for storm restoration costs incurred, inability to securitize future storm restoration costs, or loss of revenues as a result of severe weather could have a material effect on Entergy and those Utility operating companies affected by severe weather, including lower credit ratings and, thus, higher costs for future debt issuances. The inability to recover losses either excluded by insurance or in excess of the insurance limits that can be secured economically also could have a material effect on Entergy and its Utility operating companies. In addition, the recovery of major storm restoration costs from customers could effectively limit our ability to make planned capital or other investments due to the impact of such storm cost recovery on customer bills, especially in a rising cost environment.
In August 2021, Hurricane Ida caused extensive damage to the Entergy distribution and, to a lesser extent, transmission systems across Louisiana, resulting in storm costs of $2.5 billion. Entergy Louisiana began recovering a portion of these costs through securitization financings in 2022. In January 2023 the LPSC issued orders finding prudent the costs incurred by Entergy Louisiana in responding to Hurricane Ida and allowing Entergy Louisiana to securitize the remaining $1.491 billion in such costs. Because such orders are not yet final and non-appealable (due to the forty-five day appeal period) and, further, because the bond rating and marketing process has yet to occur, there is an element of risk, and Entergy Louisiana is unable to predict with certainty the ultimate success of its recovery initiatives or the timing of such recovery.
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Weather, economic conditions, technological developments, and other factors may have a material impact on electricity and gas sales and otherwise materially affect the Utility operating companies’ results of operations and system reliability.
Temperatures above normal levels in the summer tend to increase electric cooling demand and revenues, and temperatures below normal levels in the winter tend to increase electric and gas heating demand and revenues. As a corollary, mild temperatures in either season tend to decrease energy usage and resulting revenues. Higher consumption levels coupled with seasonal pricing differentials typically cause the Utility operating companies to report higher revenues in the third quarter of the fiscal year than in the other quarters. Changing weather patterns and extreme weather conditions, including hurricanes or tropical storms, flooding events, or ice storms, the frequency or intensity of which may be exacerbated by climate change, may stress the Utility operating companies’ generation facilities and transmission and distribution systems, resulting in increased maintenance and capital costs (and potential increased financing needs), limits on their ability to meet peak customer demand, increased regulatory oversight, criticism or adverse publicity, and reduced customer satisfaction. These extreme conditions could have a material effect on the Utility operating companies’ financial condition, results of operations, and liquidity.
Entergy’s electricity sales volumes are affected by a number of factors including weather and economic conditions, trends in energy efficiency, new technologies, and self-generation alternatives, including the willingness and ability of large industrial customers to develop co-generation facilities that greatly reduce their grid demand. In addition, changes to regulatory policies, such as those that allow customers to directly access the market to procure wholesale energy or those that incentivize development and utilization of new, developing, or alternative sources of generation, could, and in some instances, have reduced sales, and other non-traditional procurements, such as virtual purchase power agreements, could, and in some instances have limited growth opportunities or reduced sales at the Utility operating companies. Some of these factors are inherently cyclical or temporary in nature, such as the weather or economic conditions, and rarely have a long-lasting effect on Entergy’s operating results. Others, such as the organic turnover of appliances and lighting and their replacement with more efficient ones and adoption of newer technologies, including smart thermostats, new building codes, distributed energy resources, energy storage, demand side management, and rooftop solar, are having a more permanent effect by reducing sales growth rates from historical norms. As a result of these emerging efficiencies and technologies, the Utility operating companies may lose customers or experience lower average use per customer in the residential and commercial classes, and continuing advances have the potential to further limit sales or sales growth in the future.
The Utility operating companies also may face competition from other companies offering products and services to Entergy’s customers. Electricity sales to industrial customers, in particular, benefit from steady economic growth and favorable commodity markets; however, industrial sales are sensitive to changes in conditions in the markets in which its customers operate. Negative changes in any of these or other factors, particularly sustained economic downturns or sluggishness, have the potential to result in slower sales growth or sales declines and increased bad debt expense, which could materially affect Entergy’s and the Utility operating companies’ results of operations, financial condition, and liquidity. The Utility operating companies also may not realize anticipated or expected growth in industrial sales from electrification opportunities to help such customers achieve their environmental and sustainability goals. This could occur because of changes in customers’ goals or business priorities, competition from other companies, or decisions by such customers to seek to achieve such goals through methods not offered by Entergy.
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
Nuclear Operating, Shutdown, and Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)
Certain of the Utility operating companies and System Energy are expected to consistently operate their nuclear power plants at high capacity factors in order to be successful, and lower capacity factors could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Nuclear capacity factors significantly affect the results of operations of certain Utility operating companies and System Energy. Nuclear plant operations involve substantial fixed operating costs. Consequently, there is pressure on plant owners to operate nuclear power plants at higher capacity factors, though such operations always must be consistent with safety, reliability, and nuclear regulatory requirements. For the Utility operating companies that own nuclear plants, lower nuclear plant capacity factors can increase production costs by requiring the affected companies to generate additional energy, sometimes at higher costs, from their owned or contractually controlled facilities or purchase additional energy in the spot or forward markets in order to satisfy their supply needs.
Certain of the Utility operating companies and System Energy periodically shut down their nuclear power plants to replenish fuel. Plant maintenance and upgrades are often scheduled during such refueling outages. If refueling outages last longer than anticipated or if unplanned outages arise, Entergy’s and their results of operations, financial condition, and liquidity could be materially affected.
Outages at nuclear power plants to replenish fuel require the plant to be “turned off.” Refueling outages generally are planned to occur once every 18 to 24 months. Plant maintenance and upgrades are often scheduled during such planned outages, which may extend the planned outage duration beyond that required for only refueling activities. When refueling outages last longer than anticipated or a plant experiences unplanned outages, capacity factors decrease, and maintenance costs may increase.
Certain of the Utility operating companies and System Energy face risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication). These risks could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Based upon currently planned fuel cycles, Entergy’s nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable prices through most of 2027. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners. While there are a number of possible alternate suppliers that may be accessed to mitigate any supplier performance failure, the pricing of any such alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S. Market prices for nuclear fuel have been extremely volatile from time to time in the past and may be subject to increased volatility due to the imposition of tariffs, domestic purchase requirements or limitations on importation of uranium or uranium products from foreign countries, geopolitical conditions, or shifting trade arrangements between countries. Although Entergy’s nuclear fuel contract portfolio provides a degree of hedging against market risks for several years, costs for nuclear fuel in the future cannot be predicted with certainty due to normal inherent market uncertainties, and price changes could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.
Entergy’s ability to assure nuclear fuel supply also depends upon the performance and reliability of conversion, enrichment, and fabrication services providers. These service providers are fewer in number than uranium suppliers. For conversion and enrichment services, Entergy diversifies its supply by supplier and country and may take special measures to ensure a reliable supply of enriched uranium for fabrication into nuclear fuel. For fabrication services, each plant is dependent upon the performance of the fabricator of that plant’s nuclear fuel;
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Entergy Corporation, Utility operating companies, and System Energy
therefore, Entergy relies upon additional monitoring, inspection, and oversight of the fabrication process to assure reliability and quality of its nuclear fuel. Certain of the suppliers and service providers are located in or dependent upon foreign countries, such as Russia, and international sanctions or tariffs impacting trade with such countries could further restrict the ability of such suppliers or service providers to continue to supply fuel or provide such services at acceptable prices or at all. The inability of such suppliers or service providers to perform such obligations could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.
Certain of the Utility operating companies and System Energy face the risk that the NRC will change or modify its regulations, suspend or revoke their licenses, or increase oversight of their nuclear plants, which could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Under the Atomic Energy Act and Energy Reorganization Act, the NRC regulates the operation of nuclear power plants. The NRC may modify, suspend, or revoke licenses, shut down a nuclear facility and impose civil penalties for failure to comply with the Atomic Energy Act, related regulations, or the terms of the licenses for nuclear facilities. Interested parties may also intervene which could result in prolonged proceedings. A change in the Atomic Energy Act, other applicable statutes, or the applicable regulations or licenses, or the NRC’s interpretation thereof, may require a substantial increase in capital expenditures or may result in increased operating or decommissioning costs and could materially affect the results of operations, liquidity, or financial condition of Entergy, certain of the Utility operating companies, or System Energy. A change in the classification of a plant owned by one of these companies under the NRC’s Reactor Oversight Process, which is the NRC’s program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response, also could cause the owner of the plant to incur material additional costs as a result of the increased oversight activity and potential response costs associated with the change in classification. For additional information concerning the current classification of the plants owned by Entergy Arkansas, Entergy Louisiana, and System Energy, see “Regulation of Entergy’s Business- Regulation of the Nuclear Power Industry - NRC Reactor Oversight Process” in Part I, Item 1.
Events at nuclear plants owned by one of these companies, as well as those owned by others, may lead to a change in laws or regulations or the terms of the applicable licenses, or the NRC’s interpretation thereof, or may cause the NRC to increase oversight activity or initiate actions to modify, suspend, or revoke licenses, shut down a nuclear facility, or impose civil penalties. As a result, if an incident were to occur at any nuclear generating unit, whether an Entergy nuclear generating unit or not, it could materially affect the financial condition, results of operations, and liquidity of Entergy, certain of the Utility operating companies, or System Energy.
Certain of the Utility operating companies and System Energy are exposed to risks and costs related to operating and maintaining their nuclear power plants, and their failure to maintain operational efficiency at their nuclear power plants could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
The nuclear generating units owned by certain of the Utility operating companies and System Energy began commercial operations in the 1970s-1980s. Older equipment may require more capital expenditures to keep each of these nuclear power plants operating safely and efficiently. This equipment is also likely to require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages, or any unanticipated capital expenditures, could result in increased costs, some of which costs may not be fully recoverable by these Utility operating companies and System Energy in regulatory proceedings should there be a determination of imprudence. Operations at any of the nuclear generating units owned and operated by Entergy’s subsidiaries could degrade to the point where the affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. A decision may be made to close a unit rather than incur the expense of restarting it or returning the unit to full capacity. For these Utility operating companies and System Energy, this could result in certain costs being stranded
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
and potentially not fully recoverable in regulatory proceedings. In addition, the operation and maintenance of Entergy’s nuclear facilities require the commitment of substantial human resources that can result in increased costs.
Moreover, Entergy is becoming more dependent on fewer suppliers for key parts of Entergy’s nuclear power plants that may need to be replaced or refurbished, and in some cases, parts are no longer available and have to be reverse-engineered for replacement. In addition, certain major parts have long lead-times to manufacture if an unplanned replacement is needed. This dependence on a reduced number of suppliers and long lead-times on certain major parts for unplanned replacements could result in delays in obtaining qualified replacement parts and, therefore, greater expense for Entergy, certain of the Utility operating companies, and System Energy.
The costs associated with the storage of the spent nuclear fuel of certain of the Utility operating companies and System Energy, as well as the costs of and their ability to fully decommission their nuclear power plants, could be significantly affected by the timing of the opening of a spent nuclear fuel disposal facility, as well as interim storage and transportation requirements.
Certain of the Utility operating companies and System Energy incur costs for the on-site storage of spent nuclear fuel. The approval of a license for a national repository for the disposal of spent nuclear fuel, such as the one proposed for Yucca Mountain, Nevada, or any interim storage facility, and the timing of such facility opening, will significantly affect the costs associated with on-site storage of spent nuclear fuel. For example, while the DOE is required by law to proceed with the licensing of Yucca Mountain and, after the license is granted by the NRC, to construct the repository and commence the receipt of spent fuel, the NRC licensing of the Yucca Mountain repository is effectively at a standstill. These actions are prolonging the time before spent fuel is removed from Entergy’s plant sites. Because the DOE has not accomplished its objectives, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts, and Entergy has sued the DOE for such breach. Furthermore, Entergy is uncertain as to when the DOE will commence acceptance of spent fuel from its facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at the companies’ nuclear sites and maintenance costs on existing storage facilities, including aging management of fuel storage casks, may increase. The costs of on-site storage are also affected by regulatory requirements for such storage. In addition, the availability of a repository or other off-site storage facility for spent nuclear fuel may affect the ability to fully decommission the nuclear units and the costs relating to decommissioning. For further information regarding spent fuel storage, see the “Critical Accounting Estimates – Nuclear Decommissioning Costs – Spent Fuel Disposal” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy and Note 8 to the financial statements.
Certain of the Utility operating companies and System Energy may be required to pay substantial retrospective premiums imposed under the Price-Anderson Act and/or by Nuclear Electric Insurance Limited (NEIL) in the event of a nuclear incident, and losses not covered by insurance could have a material effect on Entergy’s and their results of operations, financial condition, or liquidity.
Accidents and other unforeseen problems at nuclear power plants have occurred both in the United States and elsewhere. As required by the Price-Anderson Act, the Utility operating companies and System Energy carry the maximum available amount of primary nuclear off-site liability insurance with American Nuclear Insurers, which is $450 million for each operating site. Claims for any nuclear incident exceeding that amount are covered under Secondary Financial Protection. The Price-Anderson Act limits each reactor owner’s public liability (off-site) for a single nuclear incident to the payment of retrospective premiums into a secondary insurance pool, which is referred to as Secondary Financial Protection, up to approximately $137.6 million per reactor. With 96 reactors currently participating, this translates to a total public liability cap of approximately $13 billion per incident. The limit is subject to change to account for the effects of inflation, a change in the primary limit of insurance coverage, and changes in the number of licensed reactors. As a result, in the event of a nuclear incident that causes damages (off-site) in excess of the primary insurance coverage, each owner of a nuclear plant reactor, including Entergy’s Utility operating companies and System Energy, regardless of fault or proximity to the incident, will be required to
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
pay a retrospective premium, equal to its proportionate share of the loss in excess of the primary insurance level, up to a maximum of approximately $137.6 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $688 million). The retrospective premium payment is currently limited to approximately $21 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $137.6 million cap.
NEIL is a utility industry mutual insurance company, owned by its members, including the Utility operating companies and System Energy. NEIL provides onsite property and decontamination coverage. All member plants could be subject to an annual assessment (retrospective premium of up to 10 times current annual premium for all policies) should the NEIL surplus (reserve) be significantly depleted due toinsured losses. As of January 1, 2023, the maximum annual assessment amounts total approximately $70 million for the Utility plants. Retrospective premium insurance available through NEIL’s reinsurance treaty can cover the potential assessments.
As mentioned above, as an owner of nuclear power plants, Entergy participates in industry self-insurance programs and could be liable to fund claims should a plant owned by a different company experience a major event. Any resulting liability from a nuclear accident may exceed the applicable primary insurance coverage and require contribution of additional funds through the industry-wide program that could significantly affect the results of operations, financial condition, or liquidity of Entergy, certain of the Utility operating companies, or System Energy.
The decommissioning trust fund assets for the nuclear power plants owned by certain of the Utility operating companies and System Energy may not be adequate to meet decommissioning obligations if market performance and other changes decrease the value of assets in the decommissioning trusts, if one or more of Entergy’s nuclear power plants is retired earlier than the anticipated shutdown date, if the plants cost more to decommission than estimated, or if current regulatory requirements change, which then could require significant additional funding.
Owners of nuclear generating plants have an obligation to decommission those plants. Certain of the Utility operating companies and System Energy maintain decommissioning trust funds for this purpose. Certain of the Utility operating companies and System Energy collect funds from their customers, which are deposited into the trusts covering the units operated for or on behalf of those companies. Those rate collections, as adjusted from time to time by rate regulators, are generally based upon operating license lives and trust fund balances as well as estimated trust fund earnings and decommissioning costs. Assets in these trust funds are subject to market fluctuations, will yield uncertain returns that may fall below projected return rates, and may result in losses resulting from the recognition of impairments of the value of certain securities held in these trust funds.
Under NRC regulations, nuclear plant owners are permitted to project the NRC-required decommissioning amount, based on an NRC formula or a site-specific estimate, and the amount that will be available in each nuclear power plant’s decommissioning trusts combined with any other decommissioning financial assurances in place. The projections are made based on the operating license expiration date and the mid-point of the subsequent decommissioning process, or the anticipated actual completion of decommissioning if a site-specific estimate is used. If the projected amount of each individual plant’s decommissioning trusts exceeds the NRC-required decommissioning amount, then its NRC license termination decommissioning obligations are considered to be funded in accordance with NRC regulations. If the projected costs do not sufficiently reflect the actual costs required to decommission these nuclear power plants, or funding is otherwise inadequate, or if the formula, formula inputs, or site-specific estimate is changed to require increased funding, additional resources or commitments would be required. Furthermore, depending upon the level of funding available in the trust funds, the NRC may not permit the trust funds to be used to pay for related costs such as the management of spent nuclear fuel that are not included in the NRC’s formula. The NRC may also require a plan for the provision of separate funding for spent fuel management costs.
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
Further, federal or state regulatory changes, including mandated increases in decommissioning funding or changes in the methods or standards for decommissioning operations, may also increase the funding requirements of, or accelerate the timing for funding of, the obligations related to the decommissioning of the nuclear generating plant owned by certain of the Utility operating companies or System Energy or may restrict the decommissioning-related costs that can be paid from the decommissioning trusts. Such changes also could result in the need for additional contributions to decommissioning trusts, or the posting of parent guarantees, letters of credit, or other surety mechanisms. As a result, under any of these circumstances, the results of operations, liquidity, and financial condition of Entergy, certain of the Utility operating companies, or System Energy could be materially affected.
An early plant shutdown (either generally or relative to current expectations), poor investment results, or higher than anticipated decommissioning costs (including as a result of changing regulatory requirements) could cause trust fund assets to be insufficient to meet the decommissioning obligations, with the result that certain of the Utility operating companies or System Energy may be required to provide significant additional funds or credit support to satisfy regulatory requirements for decommissioning, which, with respect to these Utility operating companies or System Energy, may not be recoverable from customers in a timely fashion or at all.
For further information regarding nuclear decommissioning costs, management’s decision to exit the merchant power business, and the impairment charges that resulted from such decision, see the “Critical Accounting Estimates- Nuclear Decommissioning Costs” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy, the “Entergy Wholesale Commodities Exit from the Merchant Power Business” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries, and Notes 9, 14, and 16 to the financial statements.
New or existing safety concerns regarding operating nuclear power plants and nuclear fuel could lead to restrictions upon the operation and decommissioning of Entergy’s nuclear power plants.
New and existing concerns are being expressed in public forums about the safety of nuclear generating units and nuclear fuel. These concerns have led to, and may continue to lead to, various proposals to federal regulators and governing bodies in some localities where Entergy’s subsidiaries own nuclear generating units for legislative and regulatory changes that might lead to the shutdown of nuclear units, additional requirements or restrictions related to spent nuclear fuel on-site storage and eventual disposal, or other adverse effects on owning, operating, and decommissioning nuclear generating units. Entergy vigorously responds to these concerns and proposals. If any of the existing proposals, or any proposals that may arise in the future with respect to legislative and regulatory changes, become effective, they could have a material effect on Entergy’s results of operations and financial condition.
General Business
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Entergy and its Registrant Subsidiaries depend on access to the capital markets and, at times, may face potential liquidity constraints, which could make it more difficult to handle future contingencies such as natural disasters or substantial increases in gas and fuel prices. Disruptions in the capital and credit markets may adversely affect Entergy’s and its subsidiaries’ ability to meet liquidity needs, access capital and operate and grow their businesses, and the cost of capital.
Entergy’s business is capital intensive and dependent upon its ability to access capital at reasonable rates and other terms. At times there are also spikes in the price for natural gas and other commodities that increase the liquidity requirements of the Utility operating companies. In addition, Entergy’s and the Registrant Subsidiaries’ liquidity needs could significantly increase in the event of a hurricane or other weather-related or unforeseen disaster similar to that experienced in Entergy’s service area with Hurricane Katrina and Hurricane Rita in 2005,
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Entergy Corporation, Utility operating companies, and System Energy
Hurricane Gustav and Hurricane Ike in 2008, Hurricane Isaac in 2012, Hurricane Laura, Hurricane Delta, and Hurricane Zeta in 2020, and Winter Storm Uri and Hurricane Ida in 2021. The occurrence of one or more contingencies, including an adverse decision or a delay in regulatory recovery of fuel or purchased power costs or storm restoration costs, an acceleration of payments or decreased credit lines, less cash flow from operations than expected, changes in regulation or governmental policy (including tax and trade policy), or other unknown events, could cause the financing needs of Entergy and its subsidiaries to increase. In addition, accessing the debt capital markets more frequently in these situations may result in an increase in leverage. Material leverage increases could negatively affect the credit ratings of Entergy, the Utility operating companies, and System Energy, which in turn could negatively affect access to the capital markets.
The inability to raise capital on favorable terms, particularly during times of high interest rates, and uncertainty or reduced liquidity in the capital markets, could negatively affect Entergy and its subsidiaries’ ability to maintain and to expand their businesses. Access to capital markets could be restricted and/or borrowing costs could be increased due to certain sources of debt and equity capital being unwilling to invest in offerings to fund fossil fuel projects or companies that are impacted by extreme weather events, that rely on fossil fuels, or that are impacted by risks related to climate change. Factors beyond Entergy’s control may create uncertainty that could increase its cost of capital or impair its ability to access the capital markets, including the ability to draw on its bank credit facilities. These factors include depressed economic conditions, a recession, increasing interest rates, inflation, sanctions, trade restrictions, political instability, war, terrorism, and extreme volatility in the debt, equity, or credit markets. Entergy and its subsidiaries are unable to predict the degree of success they will have in renewing or replacing their credit facilities as they come up for renewal. Moreover, the size, terms, and covenants of any new credit facilities may not be comparable to, and may be more restrictive than, existing facilities. If Entergy and its subsidiaries are unable to access the credit and capital markets on terms that are reasonable, they may have to delay raising capital, issue shorter-term securities, and/or bear an unfavorable cost of capital, which, in turn, could impact their ability to grow their businesses, decrease earnings, significantly reduce financial flexibility, and/or limit Entergy Corporation’s ability to sustain its current common stock dividend level.
A downgrade in Entergy’s or its Registrant Subsidiaries’ credit ratings could negatively affect Entergy’s and its Registrant Subsidiaries’ ability to access capital or the cost of such capital and/or could require Entergy or its subsidiaries to post collateral, accelerate certain payments, or repay certain indebtedness.
There are a number of factors that rating agencies evaluate to arrive at credit ratings for each of Entergy and the Registrant Subsidiaries, including each Registrant Subsidiary’s regulatory framework, ability to recover costs and earn returns, storm risk exposure, diversification, and financial strength and liquidity. If one or more rating agencies downgrade Entergy’s or any of the Registrant Subsidiaries’ ratings, particularly below investment grade, borrowing costs would increase, the potential pool of investors and funding sources would likely decrease, and cash or letter of credit collateral demands may be triggered by the terms of a number of commodity contracts, leases, and other agreements.
Most of Entergy’s and its subsidiaries’ suppliers and counterparties require sufficient creditworthiness to enter into transactions. If Entergy’s or the Registrant Subsidiaries’ ratings decline, particularly below investment grade, or if certain counterparties believe Entergy or the Utility operating companies are losing creditworthiness and demand adequate assurance under fuel, gas, and purchased power contracts, the counterparties may require posting of collateral in cash or letters of credit, prepayment for fuel, gas or purchased power or accelerated payment, or counterparties may decline business with Entergy or its subsidiaries.
Entergy or its Registrant Subsidiaries may be materially adversely affected by negative publicity or the inability to meet its stated goals or commitments, among other potential causes.
As with any company, Entergy’s and its Registrant Subsidiaries’ reputations are an important element of their ability to effectively conduct their business. Entergy’s and its Registrant Subsidiaries’ reputations could be harmed by a variety of factors, including: failure of a generating asset or supporting infrastructure; failure to restore
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
power after a hurricane or other severe weather event in a manner perceived as timely by regulators or customers; the incurrence of storm restoration costs perceived as excessive by regulators or customers; failure to effectively manage land and other natural resources; real or perceived violations of environmental regulations, including those related to climate change; real or perceived issues with Entergy’s safety culture or work environment; inability to meet their climate or human capital strategy goals; inability to keep their electricity rates stable; involvement in a class-action or other high-profile lawsuit; significant delays in construction projects; occurrence of or responses to cyber attacks or security vulnerabilities; acts or omissions of Entergy management or acts or omissions of a contractor or other third-party working with or for Entergy or its Registrant Subsidiaries, which actually or perceivably reflect negatively on Entergy or its Registrant Subsidiaries; measures taken to offset reductions in demand or to supply rising demand; a significant dispute with one of Entergy’s or its Registrant Subsidiaries’ customers or other stakeholders; or negative political and public sentiment resulting in a significant amount of adverse press coverage and other adverse statements affecting Entergy or its Registrant Subsidiaries.
Addressing any adverse publicity or regulatory scrutiny is time consuming and expensive and, regardless of the factual basis for the assertions being made (or lack thereof), can have a negative impact on the reputations of Entergy or its Registrant Subsidiaries, on the morale and performance of their employees, and on their relationships with their respective regulators, customers, and commercial counterparties. Adverse publicity or regulatory scrutiny may also have a negative impact on Entergy or its Registrant Subsidiaries’ ability to take timely advantage of various business or market opportunities.
Deterioration in Entergy’s or its Registrant Subsidiaries’ reputations may harm Entergy’s or its Registrant Subsidiaries’ relationships with their customers, regulators, and other stakeholders, may increase their cost of doing business, may interfere with its ability to attract and retain a qualified, inclusive, and diverse workforce, may impact Entergy’s or its Registrant Subsidiaries’ ability to raise debt capital, and may potentially lead to the enactment of new laws and regulations, or the modification of existing laws and regulations, that negatively affect the way Entergy or its Registrant Subsidiaries conduct their business, or may have a material adverse effect on their financial condition and results of operations.
Recent U.S. tax legislation may materially adversely affect Entergy’s financial condition, results of operations, and cash flows.
The Tax Cuts and Jobs Act of 2017 and CARES Act of 2020 significantly changed the U.S. Internal Revenue Code, including taxation of U.S. corporations, by, among other things, reducing the federal corporate income tax rate, limiting interest deductions, and altering the expensing of capital expenditures. The Inflation Reduction Act of 2022 further significantly changed the U.S. Internal Revenue Code by, among other things, enacting a new corporate alternative minimum tax and expanding federal tax credits for clean energy production. The interpretive guidance issued by the IRS and state tax authorities may be inconsistent with Entergy’s own interpretation and the legislation could be subject to amendments, which could lessen or increase certain impacts of the legislation. Further, changes in tax legislation or guidance, or uncertainties regarding interpretation of such tax legislation or guidance, could impact interpretation of and negotiations around certain contractual arrangements with counterparties, which could result in unfavorable changes to such arrangements or delays. In addition, the retail regulatory treatment of the expanded tax credits and corporate alternative minimum tax included in the Inflation Reduction Act of 2022 could materially impact Entergy’s future cash flows, and this legislation could result in unintended consequences not yet identified that could have a material adverse impact on Entergy’s financial results and future cash flows.
Based on initial IRS guidance and current internal forecasts, Entergy and the Registrant Subsidiaries may become subject to the corporate alternative minimum tax included in the Inflation Reduction Act of 2022 beginning in the next two to three years.
The tax rate decrease included in the Tax Cuts and Jobs Act required Entergy to record a regulatory liability for income taxes payable to customers. Such regulatory liability for income taxes is described in Note 3 to the
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
financial statements. Depending on the outcome of IRS examinations or tax positions and elections that Entergy may make, Entergy and the Registrant Subsidiaries may be required to record additional charges or credits to income tax expense.
See Note 3 to the financial statements for discussion of the effects of the Tax Cuts and Jobs Act on 2022, 2021, and 2020 results of operations and financial condition, the provisions of the Tax Cuts and Jobs Act, and the uncertainties associated with accounting for the Tax Cuts and Jobs Act, and Note 2 to the financial statements for discussion of the regulatory proceedings that have considered the effects of the Tax Cuts and Jobs Act. For further discussion of the effects of the Inflation Reduction Act of 2022, see the “Income Tax Legislation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 3 to the financial statements.
Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy’s and the Registrant Subsidiaries’ results of operations, financial condition, and liquidity.
Entergy and its subsidiaries make judgments regarding the potential tax effects of various transactions and results of operations to estimate their obligations to taxing authorities. These tax obligations include income, franchise, real estate, sales and use, and employment-related taxes. These judgments include provisions for potential adverse outcomes regarding tax positions that have been taken. Entergy and its subsidiaries also estimate their ability to utilize tax benefits, including those in the form of carryforwards for which the benefits have already been reflected in the financial statements. Changes in federal, state, or local tax laws or interpretive guidance relating thereto, adverse tax audit results or adverse tax rulings on positions taken by Entergy and its subsidiaries could negatively affect Entergy’s and the Registrant Subsidiaries’ results of operations, financial condition, and liquidity. The intended and unintended consequences of recently enacted legislation could have a material adverse impact on Entergy’s financial results and future cash flows. For further information regarding Entergy’s income taxes, see Note 3 to the financial statements.
Entergy and its subsidiaries’ ability to successfully execute on their business strategies, including their ability to complete strategic transactions, is subject to significant risks, and, as a result, they may be unable to achieve some or all of the anticipated results of such strategies, which could materially affect their future prospects, results of operations, and benefits that they anticipate from such transactions.
Entergy and its subsidiaries’ future prospects and results of operations significantly depend on their ability to successfully implement their business strategies, including achieving Entergy’s climate goals and commitments, which are subject to business, regulatory, economic, and other risks and uncertainties, many of which are beyond their control. As a result, Entergy and its subsidiaries may be unable to fully achieve the anticipated results of such strategies.
Additionally, Entergy and its subsidiaries have pursued and may continue to pursue strategic transactions including merger, acquisition, divestiture, joint venture, restructuring, or other strategic transactions. For example, a significant portion of Entergy’s utility business plan over the next several years includes the construction and/or purchase of a variety of solar facilities. These or other transactions and plans are or may become subject to regulatory approval and other material conditions or contingencies, including increased costs or delays resulting from supply chain issues. The failure to complete these transactions or plans or any future strategic transaction successfully or on a timely basis could have an adverse effect on Entergy’s or its subsidiaries’ financial condition or results of operations and the market’s perception of Entergy’s ability to execute its strategy. Further, these transactions, and any completed or future strategic transactions, involve substantial risks, including the following:
•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;
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•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 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, 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.
Entergy and its subsidiaries may not be successful in managing these or any other significant risks that they may encounter in acquiring or divesting a business, or engaging in other strategic transactions, which could have a material effect on their business, financial condition, or results of operations.
The completion of capital projects, including the construction of power generation facilities, and other capital improvements, involve substantial risks. Should such efforts be unsuccessful, the financial condition, results of operations, or liquidity of Entergy and the Utility operating companies could be materially affected.
Entergy’s and the Utility operating companies’ ability to complete capital projects, including the construction of power generation facilities, or make other capital improvements, such as transmission and distribution infrastructure replacements or upgrades, in a timely manner and within budget is contingent upon many variables and subject to substantial risks. These variables include, but are not limited to, project management expertise, escalating costs for materials, labor, and environmental compliance, reliance on suppliers for timely and satisfactory performance, continued pandemic-related delays and cost increases, and supply chains and material constraints, including those that may result from major storm events, both within and outside of Entergy’s service area. Delays in obtaining permits, challenges in securing sufficient land for the siting of solar panels, shortages in materials and qualified labor, levels of public support or opposition, suppliers and contractors not performing as expected or required under their contracts and/or experiencing financial problems that inhibit their ability to fulfill their obligations under contracts, changes in the scope and timing of projects, poor quality initial cost estimates from contractors, the inability to raise capital on favorable terms, changes in commodity prices affecting revenue, fuel costs, or materials costs, downward changes in the economy, changes in law or regulation, including environmental compliance requirements, further direct and indirect trade and tariff issues, including those associated with imported solar panels, supply chain delays or disruptions, and other events beyond the control of the Utility operating companies may occur that may materially affect the schedule, cost, and performance of these projects. If these projects or other capital improvements are significantly delayed or become subject to cost overruns or cancellation, Entergy and the Utility operating companies could incur additional costs and termination payments or face increased risk of potential write-off of the investment in the project. In addition, the Utility operating companies could be exposed to higher costs and market volatility, which could affect cash flow and cost recovery, should their respective regulators decline to approve the construction of the project or new generation needed to meet the reliability needs of customers at the lowest reasonable cost.
For further information regarding capital expenditure plans and other uses of capital in connection with capital projects, including the potential construction and/or purchase of additional generation supply sources within the Utility operating companies’ service areas, see the “Capital Expenditure Plans and Other Uses of Capital” section of Management’s Financial Discussion and Analysis for Entergy and each of the Registrant Subsidiaries.
Failure to attract, retain and manage an appropriately qualified workforce could negatively affect Entergy or its subsidiaries’ results of operations.
Entergy relies on a large and changing workforce of team members, including employees, contractors, and temporary staffing. Certain factors, such as an aging workforce, mismatching of skill sets, failing to appropriately
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anticipate future workforce needs, workforce impacts from public health concerns such as the COVID-19 pandemic and responsive measures, challenges competing with other employers offering fully remote work options, rising salary and other labor costs, or the unavailability of contract resources, may lead to operating challenges and increased costs. The challenges include inability to attract or retain talent, lack of resources, loss of knowledge base, and the time required for skill development. In this case, costs, including costs for contractors to replace employees, productivity costs, and safety costs, may increase. Failure to hire and adequately train replacement employees, or the future availability and cost of contract labor, may adversely affect the ability to manage and operate the business, especially considering the workforce needs associated with nuclear generation facilities and new skills required to develop and operate a modernized, technology-enabled, and lower carbon power grid. If Entergy and its subsidiaries are unable to successfully attract, retain, and manage an appropriately qualified workforce, their results of operations, financial position, and cash flows could be negatively affected.
Entergy and Entergy’s subsidiaries, including the Utility operating companies and System Energy, may incur substantial costs to fulfill their obligations related to environmental and other matters.
The businesses in which Entergy’s subsidiaries, including the Utility operating companies and System Energy, operate are subject to extensive environmental regulation by local, state, and federal authorities. These laws and regulations affect the manner in which the Utility operating companies and System Energy conduct their operations and make capital expenditures. These laws and regulations also affect how Entergy’s subsidiaries, including the Utility operating companies and System Energy, manage air emissions, discharges to water, wetlands impacts, solid and hazardous waste storage and disposal, cooling and service water intake, the protection of threatened and endangered species, certain migratory birds and eagles, hazardous materials transportation, and similar matters. Federal, state, and local authorities continually revise these laws and regulations, and the laws and regulations are subject to judicial interpretation and to the permitting and enforcement discretion vested in the implementing agencies. Developing and implementing plans for facility compliance with these requirements can lead to capital, personnel, and operation and maintenance expenditures. Violations of these requirements can subject the Utility operating companies and System Energy to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, remediation and clean-up costs, civil penalties, and exposure to third parties’ claims for alleged health or property damages or for violations of applicable permits or standards. In addition, Entergy and its subsidiaries, including the Utility operating companies and System Energy, are subject to potential liability under these laws for the costs of remediation of environmental contamination of property now or formerly owned or operated by the Utility operating companies and System Energy and of property potentially contaminated by hazardous substances they generate. The Utility operating companies currently are involved in proceedings relating to sites where hazardous substances have been released and may be subject to additional proceedings in the future. Entergy’s subsidiaries, including the Utility operating companies and System Energy, have incurred and expect to incur significant costs related to environmental compliance.
Emissions of nitrogen and sulfur oxides, mercury, particulates, greenhouse gases, and other regulated emissions from generating plants potentially are subject to increased regulation, controls, and mitigation expenses. In addition, existing environmental regulations and programs promulgated by the EPA often are challenged legally, or are revised or withdrawn by the EPA, sometimes resulting in large-scale changes to anticipated regulatory regimes and the resulting need to shift course, both operationally and economically, depending on the nature of the changes. Risks relating to global climate change, initiatives to regulate, or otherwise compel reductions of greenhouse gas emissions, and water availability issues are discussed below.
Entergy and its subsidiaries may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals, or if Entergy and its subsidiaries fail to obtain, maintain, or comply with any such approval, the operation of its facilities could be stopped or become subject to additional costs. For further information regarding environmental regulation and environmental matters, including Entergy’s response to climate change, see the “Regulation of Entergy’s Business– Environmental Regulation” section of Part I, Item 1.
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The Utility operating companies, System Energy, and Entergy’s non-regulated operations may incur substantial costs related to reliability standards.
Entergy’s business is subject to extensive and mandatory reliability standards. Such standards, which are established by the NERC, the SERC, and other regional enforcement entities, are approved by the FERC and frequently are reviewed, amended, and supplemented. Failure to comply with such standards could result in the imposition of fines or civil penalties, and potential exposure to third party claims for alleged violations of such standards. The standards, as well as the laws and regulations that govern them, are subject to judicial interpretation and to the enforcement discretion vested in the implementing agencies. In addition to exposure to civil penalties and fines, the Utility operating companies have incurred and expect to incur significant costs related to compliance with new and existing reliability standards, including costs associated with the Utility operating companies’ transmission system and generation assets. In addition, the retail regulators of the Utility operating companies possess the jurisdiction, and in some cases have exercised such jurisdiction, to impose standards governing the reliable operation of the Utility operating companies’ distribution systems, including penalties if these standards are not met. The changes to the reliability standards applicable to the electric power industry are ongoing, and Entergy cannot predict the ultimate effect that the reliability standards will have on its Utility and Entergy’s non-regulated operations.
Environmental and regulatory obligations intended to combat the effects of climate change, including by compelling greenhouse gas emission reductions or reporting, increasing clean or renewable energy requirements, or placing a price on greenhouse gas emissions, or the achievement of voluntary climate commitments could materially affect the financial condition, results of operations, and liquidity of Entergy and Entergy’s subsidiaries, including the Utility operating companies and System Energy.
In an effort to address climate change concerns, some federal, state, and local authorities are calling for additional laws and regulations aimed at known or suspected causes of climate change. For example, the EPA, various environmental interest groups, and other organizations have focused considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. The EPA has promulgated regulations controlling greenhouse gas emissions from certain vehicles, and from new, existing, and significantly modified stationary sources of emissions, including electric generating units. Such regulations continue to evolve. As examples of state action, in the Northeast, the Regional Greenhouse Gas Initiative establishes a cap on CO2 emissions from electric power plants and requires generators to purchase emission permits to cover their CO2 emissions, and a similar program has been developed in California. In Louisiana, the Office of the Governor announced the creation of a Climate Initiatives Task Force and issued an executive order that established a path to net-zero emissions by 2050 while the City Council of New Orleans passed a renewable and clean portfolio standard that sets a goal of net-zero emissions by 2040 and absolute zero emissions by 2050. The impact that continued changes in the governmental response to climate change risk and any judicial interpretation thereof will have on existing and pending environmental laws and regulations related to greenhouse gas emissions currently is unclear.
Developing and implementing plans for compliance with greenhouse gas emissions reduction or reporting or clean/renewable energy requirements, or for achieving voluntary climate commitments can lead to additional capital, personnel, and operation and maintenance expenditures and could significantly affect the economic position of existing facilities and proposed projects. The operations of low or non-emitting generating units (such as nuclear units) at lower than expected capacity factors could require increased generation from higher emitting units, thus increasing Entergy’s greenhouse gas emission rate. Moreover, long-term planning to meet environmental requirements can be negatively impacted and costs may increase to the extent laws and regulations change prior to full implementation. These requirements could, in turn, lead to changes in the planning or operations of balancing authorities or organized markets in areas where Entergy’s subsidiaries, including the Utility operating companies or System Energy, do business. Violations of such requirements may subject the Utility operating companies to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, civil penalties, and exposure to third parties’ claims for alleged health
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or property damages or for violations of applicable permits or standards. Further, real or perceived violations of environmental regulations, including those related to climate change, or inability to meet Entergy’s voluntary climate commitments, could adversely impact Entergy’s reputation or inhibit Entergy’s ability to pursue its decarbonization objectives. To the extent Entergy believes any of these costs are recoverable in rates, however, additional material rate increases for customers could be resisted by Entergy’s regulators and, in extreme cases, Entergy’s regulators might attempt to deny or defer timely recovery of these costs.
Future changes in regulation or policies governing the reporting or emission of CO2 and other greenhouse gases or mix of generation sources could (i) result in significant additional costs to Entergy’s Utility operating companies, their suppliers, or customers, (ii) make some of Entergy’s electric generating units uneconomical to maintain or operate, (iii) result in the early retirement of generation facilities and stranded costs if Entergy’s Utility operating companies are unable to fully recover the costs and investment in generation, and (iv) increase the difficulty that Entergy and its Utility operating companies have with obtaining or maintaining required environmental regulatory approvals, each of which could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries. In addition, lawsuits have occurred or are reasonably expected against emitters of greenhouse gases alleging that these companies are liable for personal injuries and property damage caused by climate change. These lawsuits may seek injunctive relief, monetary compensation, and punitive damages.
In March 2019, Entergy voluntarily set a climate goal to achieve a 50 percent reduction in its carbon emission rate from the year 2000 by 2030. In September 2020, Entergy voluntarily committed to achieving net zero carbon emissions by 2050. In November 2022, Entergy voluntarily set a climate goal to achieve 50 percent carbon-free energy capacity by 2030. Risks to achieving the 2030 and 2050 goals include, among other things, the ability to execute on renewable resource plans, regulatory approvals, customer demand for carbon-free energy, potential tariffs, carbon policy and regulation, and supply chain costs and constraints. Technology research and development, innovation, and advancements in carbon-free generation are also critical to Entergy’s ability to achieve its 2050 commitment. Entergy cannot predict the ultimate impact of achieving these objectives, or the various implementation aspects, on its system reliability, or its results of operations, financial condition, or liquidity.
The physical effects of climate change could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries.
Potential physical risks from climate change include an increase in sea level, wind and storm surge damages, more frequent or intense hurricanes and wildfires, wetland and barrier island erosion, flooding and changes in weather conditions (such as increases in precipitation, drought, or changes in average temperatures), and potential increased impacts of extreme weather conditions or storms. Entergy’s subsidiaries own assets in, and serve, communities that are at risk from sea level rise, changes in weather conditions, storms, and loss of the protection offered by coastal wetlands. A significant portion of the nation’s oil and gas infrastructure is located in these areas and susceptible to storm damage that could be aggravated by the physical impacts of climate change, which could give rise to fuel supply interruptions and price spikes. Entergy and its subsidiaries also face the risk that climate change could impact the availability and quality of water supplies necessary for operations.
These and other physical changes could result in changes in customer demand, increased costs associated with repairing and maintaining generation facilities and transmission and distribution systems resulting in increased maintenance and capital costs (and potential increased financing needs), limits on the Entergy system’s ability to meet peak customer demand, more frequent and longer lasting outages, increased regulatory oversight, criticism or adverse publicity, and lower customer satisfaction. Also, to the extent that climate change adversely impacts the economic health of a region or results in energy conservation or demand side management programs, it may adversely impact customer demand and revenues. Such physical or operational risks could have a material effect on Entergy’s and its subsidiaries’ financial condition, results of operations, and liquidity.
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Due in part to the recent increase in frequency and intensity of major storm activity along the Gulf Coast, Entergy is developing plans to accelerate investments that would enhance the resilience of the electric systems of the Utility operating companies to enable them to better withstand major storms or other adverse weather events, to enable more rapid restoration of electricity after major storm or other adverse events, and to deliver electricity to critical customers more immediately after such events. The need for this investment and these expenditures could give rise to liquidity, capital or other financing-related risks as well as result in upward pressure on the retail rates of the Utility operating companies, which, particularly when combined with upward pressure resulting from the recovery of the costs of recent and future storms, may result in adverse actions by the Utility operating companies’ retail regulators or effectively limit the ability to make other planned capital or other investments.
Continued and future availability and quality of water for cooling, process, and sanitary uses could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries.
Water is a vital natural resource that is also critical to Entergy and its subsidiaries. Entergy’s and its subsidiaries’ facilities use water for cooling, boiler make-up, sanitary uses, potable supply, and many other uses. Entergy’s Utility operating companies also own and/or operate hydroelectric facilities. Accordingly, water availability and quality are critical to Entergy’s and its subsidiaries’ business operations. Impacts to water availability or quality could negatively impact both operations and revenues.
Entergy and its subsidiaries secure water through various mechanisms (ground water wells, surface waters intakes, municipal supply, etc.) and operate under the provisions and conditions set forth by the provider and/or regulatory authorities. Entergy and its subsidiaries also obtain and operate in substantial compliance with water discharge permits issued under various provisions of the Clean Water Act and/or state water pollution control provisions. Regulations and authorizations for both water intake and use and for waste discharge can become more stringent in times of water shortages, low flows in rivers, low lake levels, low groundwater aquifer volumes, and similar conditions. The increased use of water by industry, agriculture, and the population at large, population growth, and the potential impacts of climate change on water resources may cause water use restrictions that affect Entergy and its subsidiaries.
Entergy and its subsidiaries may not be adequately hedged against changes in commodity prices, which could materially affect Entergy’s and its subsidiaries’ results of operations, financial condition, and liquidity.
To manage near-term and medium-term financial exposure related to commodity price fluctuations, Entergy and its subsidiaries, including the Utility operating companies, may enter into contracts to hedge portions of their purchase and sale commitments, fuel requirements, and inventories of natural gas, uranium and its conversion and enrichment, coal, refined products, and other commodities, within established risk management guidelines. As part of this strategy, Entergy and its subsidiaries may utilize fixed- and variable-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. However, Entergy and its subsidiaries normally cover only a portion of the exposure of their assets and positions to market price volatility, and the coverage will vary over time. In addition, Entergy also elects to leave certain volumes during certain years unhedged. To the extent Entergy and its subsidiaries have unhedged positions, fluctuating commodity prices can materially affect Entergy’s and its subsidiaries’ results of operations and financial position.
Although Entergy and its subsidiaries devote a considerable effort to these risk management strategies, they cannot eliminate all the risks associated with these activities. As a result of these and other factors, Entergy and its subsidiaries cannot predict with precision the impact that risk management decisions may have on their business, results of operations, or financial position.
Entergy’s over-the-counter financial derivatives are subject to rules implementing the Dodd-Frank Wall Street Reform and Consumer Protection Act that are designed to promote transparency, mitigate systemic risk, and protect against market abuse. Entergy cannot predict the impact any proposed or not fully-implemented final rules
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will have on its ability to hedge its commodity price risk or on over-the-counter derivatives markets as a whole, but such rules and regulations could have a material effect on Entergy's risk exposure, as well as reduce market liquidity and further increase the cost of hedging activities.
Entergy has guaranteed or indemnified the performance of a portion of the obligations relating to hedging and risk management activities. Reductions in Entergy’s or its subsidiaries’ credit quality or changes in the market prices of energy commodities could increase the cash or letter of credit collateral required to be posted in connection with hedging and risk management activities, which could materially affect Entergy’s or its subsidiaries’ liquidity and financial position.
The Utility operating companies and Entergy’s non-regulated operations are exposed to the risk that counterparties may not meet their obligations, which may materially affect the Utility operating companies and Entergy’s non-regulated operations.
The hedging and risk management practices of the Utility operating companies and Entergy's non-regulated operations are exposed to the risk that counterparties that owe Entergy and its subsidiaries money, energy, or other commodities will not perform their obligations. Currently, some hedging agreements contain provisions that require the counterparties to provide credit support to secure all or part of their obligations to Entergy or its subsidiaries. If the counterparties to these arrangements fail to perform, Entergy or its subsidiaries may enforce and recover the proceeds from the credit support provided and acquire alternative hedging arrangements, which credit support may not always be adequate to cover the related obligations. In such event, Entergy and its subsidiaries might incur losses in addition to amounts, if any, already paid to the counterparties. In addition, the credit commitments of Entergy’s lenders under its bank facilities may not be honored for a variety of reasons, including unexpected periods of financial distress affecting such lenders, which could materially affect the adequacy of its liquidity sources.
Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding and result in increased benefit plan costs.
The performance of the capital markets affects the values of the assets held in trust under Entergy’s pension and postretirement benefit plans. A decline in the market value of the assets may increase the funding requirements relating to Entergy’s benefit plan liabilities and also result in higher benefit costs. As the value of the assets decreases, the “expected return on assets” component of benefit costs decreases, resulting in higher benefits costs. Additionally, asset losses are incorporated into benefit costs over time, thus increasing benefits costs. Volatility in the capital markets has affected the market value of these assets, which may affect Entergy’s planned levels of contributions in the future. Additionally, changes in interest rates affect the liabilities under Entergy’s pension and postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding and recognition of higher liability carrying costs. The funding requirements of the obligations related to the pension benefit plans can also increase as a result of changes in, among other factors, retirement rates, life expectancy assumptions, or federal regulations. For further information regarding Entergy’s pension and other postretirement benefit plans, refer to the “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” section of Management’s Financial Discussion and Analysis for Entergy and each of its Registrant Subsidiaries and Note 11 to the financial statements.
The litigation environment in the states in which the Registrant Subsidiaries operate poses a significant risk to those businesses.
Entergy and its subsidiaries and related entities are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, asbestos, hazardous material and customer matters, and injuries and damages issues, among other matters. The states in which the Registrant Subsidiaries operate have proven to be unusually litigious environments. Judges and juries in these states have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort
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cases. Entergy and its subsidiaries use legal and appropriate means to contest litigation threatened or filed against them, but the litigation environment in these states poses a significant business risk.
Terrorist attacks, physical attacks, cyber attacks, system failures or data breaches of Entergy’s and its subsidiaries’ or their suppliers’ infrastructure or technology systems may adversely affect Entergy’s results of operations.
Entergy and its subsidiaries operate in a business that requires evolving information technology systems that include sophisticated data collection, processing systems, software, network infrastructure, and other technologies that are becoming more complex and may be subject to mandatory and prescriptive reliability and security standards. The functionality of Entergy’s technology systems depends on its own and its suppliers’ and their contractors’ technology. Suppliers’ and their contractors’ technology systems to which Entergy is connected directly or indirectly support a variety of business processes and activities to store sensitive data, including (i) intellectual property, (ii) proprietary business information, (iii) personally identifiable information of customers, employees, and others, and (iv) data with respect to invoicing and the collection of payments, accounting, procurement, and supply-chain activities. Any significant failure or malfunction of such information technology systems could result in loss of or inappropriate access to data or disruptions of operations.
There have been attacks and threats of attacks on energy infrastructure by cyber actors, including those associated with foreign governments. As an operator of critical infrastructure, Entergy and its subsidiaries face a heightened risk of physical attacks or acts or threats of terrorism, cyber attacks, including ransomware attacks, and data breaches, whether as a direct or indirect act against one of Entergy’s generation, transmission or distribution facilities, operations centers, infrastructure, or information technology systems used to manage, monitor, and transport power to customers and perform day-to-day business functions as well as against the systems of critical suppliers and contractors. Further, attacks may become more frequent in the future as technology becomes more prevalent in energy infrastructure. An attack could affect Entergy’s ability to operate, including its ability to operate the information technology systems and network infrastructure on which it relies to conduct business.
Given the rapid technological advancements of existing and emerging threats, Entergy’s technology systems remain inherently vulnerable despite implementations and enhancements of the multiple layers of security and controls. If Entergy’s or its subsidiaries’ technology systems, or those of critical suppliers or contractors, were compromised and unable to detect or recover in a timely fashion to a normal state of operations, Entergy or its subsidiaries could be unable to perform critical business functions that are essential to the company’s well-being and could result in a loss of or inappropriate access to its confidential, sensitive, and proprietary information, including personal information of its customers, employees, suppliers, and others in Entergy’s care.
Any such attacks, failures, or data breaches could have a material effect on Entergy’s and the Utility operating companies’ business, financial condition, results of operations or reputation. Although Entergy and the Utility operating companies purchase insurance for cyber attacks and data breaches, such insurance prices have increased substantially, and coverage may not be adequate to cover all losses that might arise in connection with these events. Such events may also expose Entergy to an increased risk of litigation (and associated damages and fines).
Entergy and the Registrant Subsidiaries are subject to risks associated with their ability to obtain adequate insurance at acceptable costs.
The global economic cost to insurers resulting from cyber attacks, natural disasters and other catastrophic events, in addition to an increased focus on climate issues could have disruptive effects on insurance markets. The availability of insurance capacity may decrease, and the insurance policies that Entergy or the Registrant Subsidiaries are able to obtain may have higher deductibles, higher premiums, and more restrictive terms and conditions. Further, the insurance policies of Entergy or the Registrant Subsidiaries may not cover all of their potential exposures or actual amounts of losses incurred.
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Significant increases in commodity prices, other materials and supplies, and operation and maintenance expenses may adversely affect Entergy's results of operations, financial condition, and liquidity.
Entergy and its subsidiaries have observed and expect future inflationary pressures related to commodity prices, other materials and supplies, and operation and maintenance expenses, including in the areas of labor, health care, and pension costs. The contracts for the construction of certain of the Utility operating companies’ generation facilities also have included, and in the future may include, price adjustment provisions that, subject to certain limitations, may enable the contractor to increase the contract price to reflect increases in certain costs of constructing the facility. These inflationary pressures could impact the ability of Entergy and its subsidiaries to control costs and/or make substantial investments in their businesses, including their ability to recover costs and investments, and to earn their allowed return on equity within frameworks established by their regulators while maintaining affordability of their services for their customers, in addition to having unpredictable effects on Entergy’s customers. Increases in commodity prices, other materials and supplies, and operation and maintenance expenses, including increasing labor costs and costs and funding requirements associated with Entergy's defined benefit retirement plans, health care plans, and other employee benefits, could increase their financing needs and otherwise adversely affect their results of operations, financial condition, and liquidity.
(Entergy New Orleans)
The effect of higher purchased gas cost charges to customers taking gas service may adversely affect Entergy New Orleans’s results of operations and liquidity.
Gas rates charged to retail gas customers are comprised primarily of purchased gas cost charges, which provide no return or profit to Entergy New Orleans, and distribution charges, which provide a return or profit to the utility. Distribution charges recover fixed costs on a volumetric basis and, thus, are affected by the amount of gas sold to customers. When purchased gas cost charges increase due to higher gas procurement costs, customer usage may decrease, especially in weaker economic times, resulting in lower distribution charges for Entergy New Orleans, which, given its relatively smaller size, could adversely affect results of operations. Purchased gas cost charges, which comprise most of a customer’s bill and may be adjusted monthly, represent gas commodity costs that Entergy New Orleans recovers from its customers. Entergy New Orleans’s cash flows can be affected by differences between the time when gas is purchased and the time when ultimate recovery from customers occurs.
(Entergy Corporation and System Energy)
System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on sales to affiliated companies for all of its revenues. Certain contractual arrangements relating to System Energy, the affiliated companies, and these revenues are the subject of ongoing litigation and regulatory proceedings. The aggregate amount of refunds claimed in these proceedings substantially exceeds the current net book value of System Energy. In the event of an adverse decision in one or more of these proceedings requiring the payment of substantial additional refunds, System Energy would be required to seek financing to pay such refunds which financing may not be available on terms acceptable to System Energy, or may not be available at all, when required. If one or more of the foregoing events occurs, System Energy may be required to explore other options or protections available to it to extend, restructure, or retire its indebtedness and to prioritize its obligations.
System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf. Charges under the Unit Power Sales Agreement are paid by the Utility operating companies (other than Entergy Texas) as consideration for their respective entitlements to receive capacity and energy. The useful economic life of Grand Gulf is finite and is limited by the terms of its operating license, which currently expires in November 2044. System Energy’s financial condition depends both on the receipt of payments from the Utility operating companies (other than Entergy Texas)
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under the Unit Power Sales Agreement and on the continued commercial operation of Grand Gulf. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC, including a challenge with respect to System Energy’s uncertain tax positions, sale leaseback arrangement, authorized return on equity and capital structure, a broader investigation of rates under the Unit Power Sales Agreement, and a prudence complaint challenging the extended power uprate completed at Grand Gulf in 2012 and the operation and management of Grand Gulf, particularly in the 2016-2020 time period.
The claims in these proceedings include claims for refunds and claims for rate adjustments. The aggregate amount of refunds claimed in these proceedings substantially exceeds the current net book value of System Energy. Entergy Corporation is not obligated to provide funding to System Energy to enable it to pay any such refunds. In the event that an adverse decision in one or more of these proceedings required the payment of substantial additional refunds, System Energy would need to source additional financing to pay such refunds. Such financing may not be available on terms acceptable to System Energy, or may not be available at all, when required. An adverse development in one or more of these proceedings also could jeopardize System Energy’s ability to finance its operations and pay its obligations, at a reasonable cost or when due. If one or more of the foregoing events occurs, System Energy may be required to explore other options or protections available to it to extend, restructure, or retire its indebtedness and to prioritize its obligations. One or more rating agencies may downgrade the ratings of System Energy or its debt securities, which could adversely affect the market prices of System Energy’s debt securities and otherwise adversely affect System Energy’s financial condition.
In addition, an order requiring System Entergy to pay substantial additional refunds could result in a default and, in certain cases, acceleration under one or more of System Energy’s existing bond indentures, credit agreements, or other financing arrangements. Certain events constituting events of default under System Energy’s financing agreements may also result in defaults under, or acceleration with respect to, financing arrangements involving certain credit agreement and guarantee obligations of Entergy Corporation.
These proceedings are pending before their respective adjudicators and no final decisions have been reached. Thus, Entergy cannot predict with certainty the outcome of any of these proceedings, or the magnitude of any refunds or rate adjustments, and an adverse outcome in any of them could have a material adverse effect on Entergy’s or System Energy’s results of operations, financial condition, or liquidity. In particular, in connection with the uncertain tax position proceeding and related December 2022 FERC order and System Energy’s compliance report filed in January 2023, if the FERC were to order additional refunds at a level consistent with the position of the LPSC, the APSC, and the City Council on the remedy for the formerly uncertain tax positions, System Energy’s continued financial viability would be jeopardized. See Note 2 to the financial statements for further discussion of the proceedings. The Utility operating companies (other than Entergy Texas) have agreed to implement certain protocols for providing retail regulators with information regarding rates billed under the Unit Power Sales Agreement.
For information regarding the Unit Power Sales Agreement, the sale and leaseback transactions and certain other agreements relating to certain Entergy System companies’ support of System Energy, see Notes 5 and 8 to the financial statements and the “Utility - System Energy and Related Agreements” section of Part I, Item 1.
(Entergy Corporation)
Entergy’s non-regulated operations are subject to substantial governmental regulation and may be adversely affected by legislative, regulatory, or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
Entergy’s non-regulated operations are subject to regulation under federal, state, and local laws. Compliance with the requirements under these various regulatory regimes may cause Entergy’s non-regulated operations to incur significant additional costs, and failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of liens, fines, and/or civil or criminal liability.
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Public utilities under the Federal Power Act are required to obtain FERC acceptance of their rate schedules for wholesale sales of electricity. Entergy’s non-regulated operations include legal entities that meet the definition of a “public utility” under the Federal Power Act by virtue of making wholesale sales of electric energy and/or owning wholesale electric transmission facilities. The FERC has granted those entities the authority to sell electricity at market-based rates. The FERC’s orders that grant those entities market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that those entities can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, market-based sales are subject to certain market behavior rules, and if one of those entities were deemed to have violated one of those rules, they would be subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority and potential penalties of up to $1.29 million per day per violation. If one of those entities were to lose their market-based rate authority, it would be required to obtain the FERC’s acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have an adverse effect on the rates those entities charge for power from its facilities.
Entergy’s non-regulated operations are also affected by legislative and regulatory changes, as well as by changes to market design, market rules, tariffs, cost allocations, and bidding rules imposed by the existing Independent System Operator. The Independent System Operator that oversees the relevant wholesale power market may impose, and in the future may continue to impose, mitigation, including price limitations, offer caps and other mechanisms, to address some of the volatility and the potential exercise of market power in that market. These types of price limitations and other regulatory mechanisms may have an adverse effect on the profitability of Entergy’s non-regulated operations’ generation facilities that sell energy and capacity into the wholesale power markets.
The regulatory environment applicable to the electric power industry is subject to changes as a result of restructuring initiatives at both the state and federal levels. Entergy cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on Entergy’s non-regulated operations. In addition, in some of these markets, interested parties have proposed material market design changes, including the elimination of a single clearing price mechanism, have raised claims that the competitive marketplace is not working, and have made proposals to re-regulate the markets, impose a generation tax, or require divestitures by generating companies to reduce their market share. Other proposals to re-regulate may be made and legislative or other attention to the electric power market restructuring process may delay or reverse the deregulation process, which could require material changes to business planning models. If competitive restructuring of the electric power markets is reversed, modified, discontinued, or delayed, Entergy’s non-regulated operations’ results of operations, financial condition, and liquidity could be materially affected.
As a holding company, Entergy Corporation depends on cash distributions from its subsidiaries to meet its debt service and other financial obligations and to pay dividends on its common stock, and has provided, and may continue to provide, capital contributions or debt financing to its subsidiaries, which would reduce the funds available to meet its other financial obligations.
Entergy Corporation is a holding company with no material revenue generating operations of its own or material assets other than the stock of its subsidiaries. Accordingly, all of its operations are conducted by its subsidiaries. Entergy Corporation has provided, and may continue to provide, capital contributions or debt financing to its subsidiaries, which would reduce the funds available to meet its financial obligations, including making interest and principal payments on outstanding indebtedness, and to pay dividends on Entergy’s common stock. Entergy Corporation’s ability to satisfy its financial obligations, including the payment of interest and principal on its outstanding debt, and to pay dividends on its common stock depends on the payment to it of dividends or distributions by its subsidiaries. The subsidiaries of Entergy Corporation are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any dividends or make distributions to Entergy Corporation. The ability of such subsidiaries to make payments of dividends or distributions to Entergy
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
Corporation depends on their results of operations and cash flows and other items affecting retained earnings, and on any applicable legal, regulatory, or contractual limitations on subsidiaries’ ability to pay such dividends or distributions. Prior to providing funds to Entergy Corporation, such subsidiaries have financial and regulatory obligations that must be satisfied, including among others, debt service and, in the case of Entergy Utility Holding Company and Entergy Texas, dividends and distributions on preferred securities. Any distributions from the Registrant Subsidiaries other than Entergy Texas and System Energy are paid directly to Entergy Utility Holding Company and are therefore subject to prior payment of distributions on its preferred securities.
Item 1B. Unresolved Staff Comments
None.
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
2022 Compared to 2021
Earnings Applicable to Member’s Equity
Earnings decreased $19.3 million primarily due to higher other operation and maintenance expenses, the reversal in 2021 of the remaining $38.8 million regulatory liability for the formula rate plan 2019 historical year netting adjustment, higher depreciation and amortization expenses, higher interest expense, and higher taxes other than income taxes, partially offset by higher retail electric price and higher volume/weather.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 2022 to 2021:
| | | | | |
| Amount |
| (In Millions) |
| 2021 operating revenues | $2,338.6 | |
| Fuel, rider, and other revenues that do not significantly affect net income | 209.2 | |
| Retail electric price | 70.0 | |
| Volume/weather | 47.4 | |
| Return of unprotected excess accumulated deferred income taxes to customers | 8.0 | |
| 2022 operating revenues | $2,673.2 | |
Entergy Arkansas’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.
The retail electric price variance is primarily due to an increase in formula rate plan rates effective January 2022. See Note 2 to the financial statements for further discussion of the 2021 formula rate plan filing.
The volume/weather variance is primarily due to the effect of more favorable weather on residential sales and an increase in demand charges as a result of an updated contract with an industrial customer in the primary metals industry, partially offset by a decrease in weather-adjusted residential usage.
The return of unprotected excess accumulated deferred income taxes to customers resulted from the return of unprotected excess accumulated deferred income taxes through a tax adjustment rider beginning in April 2018. In 2021, $8 million was returned to customers. There was no effect on net income as the reduction in operating revenues was offset by a reduction in income tax expense. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Total electric energy sales for Entergy Arkansas for the years ended December 31, 2022 and 2021 are as follows:
| | | | | | | | | | | | | | | | | |
| 2022 | | 2021 | | % Change |
| (GWh) | | |
| Residential | 8,147 | | | 7,914 | | | 3 | |
| Commercial | 5,615 | | | 5,491 | | | 2 | |
| Industrial | 8,493 | | | 8,466 | | | — | |
| Governmental | 218 | | | 225 | | | (3) | |
| Total retail | 22,473 | | | 22,096 | | | 2 | |
| Sales for resale: | | | | | |
| Associated companies | 1,906 | | | 2,254 | | | (15) | |
| Non-associated companies | 6,520 | | | 6,151 | | | 6 | |
| Total | 30,899 | | | 30,501 | | | 1 | |
See Note 19 to the financial statements for additional discussion of Entergy Arkansas’s operating revenues.
Other Income Statement Variances
Other operation and maintenance expenses increased primarily due to:
•an increase of $24.1 million in power delivery expenses primarily due to higher vegetation maintenance costs, higher safety and training costs, and higher reliability costs, partially offset by a decrease in meter reading expenses as a result of the deployment of advanced metering systems;
•an increase of $17 million in nuclear generation expenses primarily due to a higher scope of work performed in 2022 as compared to 2021 and higher nuclear labor costs;
•an increase of $11.6 million in non-nuclear generation expenses primarily due to a higher scope of work, including during plant outages, performed in 2022 as compared to 2021 and higher costs associated with materials and supplies in 2022 as compared to 2021;
•an increase of $7.9 million in energy efficiency expenses primarily due to the timing of recovery from customers, partially offset by lower energy efficiency costs; and
•an increase of $4.6 million in customer service center support costs primarily due to higher contract costs.
Taxes other than income taxes increased primarily due to increases in ad valorem taxes resulting from higher assessments and millage rate increases, increases in employment taxes, and increases in local franchise taxes.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including the Searcy Solar facility, which was placed in service in December 2021.
Other regulatory charges (credits) - net includes the reversal in first quarter 2021 of the remaining $38.8 million regulatory liability for the 2019 historical year netting adjustment as part of its 2020 formula rate plan proceeding. See Note 2 to the financial statements for discussion of the 2020 formula rate plan filing. In addition, Entergy Arkansas records a regulatory charge or credit for the difference between asset retirement obligation-related expenses and nuclear decommissioning trust earnings plus asset retirement obligation-related costs collected in revenue.
Other income decreased primarily due to changes in decommissioning trust fund activity, including portfolio rebalancing of the decommissioning trust funds in 2021.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Interest expense increased primarily due to the issuance of $200 million of 4.20% Series mortgage bonds in March 2022 and the issuance of $400 million of 3.35% Series mortgage bonds in March 2021, partially offset by the repayment of $350 million of 3.75% Series mortgage bonds in February 2021.
Net loss attributable to noncontrolling interest reflects the earnings or losses attributable to the noncontrolling interest partner of the tax equity partnership for the Searcy Solar facility under HLBV accounting. Entergy Arkansas recorded regulatory charges of $4.5 million in 2022 compared to $18.1 million in 2021 to defer the difference between the losses allocated to the tax equity partner under the HLBV method of accounting and the earnings/loss that would have been allocated to the tax equity partner under its respective ownership percentage in the partnership. See Note 1 to the financial statements for discussion of the HLBV method of accounting.
The effective income tax rates were 21.6% for 2022 and 20.1% for 2021. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates, and for additional discussion regarding income taxes.
2021 Compared to 2020
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy Arkansas’s Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC onFebruary 25, 2022, for discussion of results of operations for 2021 compared to 2020.
Income Tax Legislation
See the “Income Tax Legislation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the Inflation Reduction Act of 2022.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2022, 2021, and 2020 were as follows:
| | | | | | | | | | | | | | | | | | |
| | 2022 | | 2021 | | 2020 | |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period | $12,915 | | | $192,128 | | | $3,519 | | |
| | | | | | |
| Net cash provided by (used in): | | | | | | |
| Operating activities | 699,732 | | | 549,216 | | | 659,818 | | |
| Investing activities | (852,794) | | | (898,193) | | | (795,709) | | |
| Financing activities | 145,425 | | | 169,764 | | | 324,500 | | |
| Net increase (decrease) in cash and cash equivalents | (7,637) | | | (179,213) | | | 188,609 | | |
| | | | | | |
| Cash and cash equivalents at end of period | $5,278 | | | $12,915 | | | $192,128 | | |
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2022 Compared to 2021
Operating Activities
Net cash flow provided by operating activities increased $150.5 million in 2022 primarily due to:
•higher collections from customers;
•the timing of recovery of fuel and purchased power costs. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery; and
•a decrease in spending of $23.6 million on nuclear refueling outages in 2022.
The increase was partially offset by:
•payments to vendors, including timing and increase in cost of operations;
•an increase of $26.3 million in pension contributions in 2022. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding; and
•a decrease of $16.2 million in income tax refunds. Entergy Arkansas received income tax refunds in 2022 and 2021, each in accordance with an intercompany income tax allocation agreement.
Investing Activities
Net cash flow used in investing activities decreased $45.4 million in 2022 primarily due to:
•the purchase of the Searcy Solar facility by the tax equity partnership in December 2021 for approximately $131.8 million. See Note 14 to the financial statements for further discussion of the Searcy Solar facility purchase; and
•a decrease of $16.6 million in non-nuclear generation construction expenditures primarily due to a lower scope of work on projects performed in 2022 as compared to 2021.
The decrease was partially offset by:
•an increase of $78.7 million in distribution construction expenditures primarily due to higher capital expenditures for storm restoration in 2022 and increased investment in the reliability and infrastructure of Entergy Arkansas’s distribution system, partially offset by lower spending in 2022 on advanced metering infrastructure;
•an increase of $27.2 million in decommissioning trust fund investment activity; and
•an increase of $19 million in transmission construction expenditures primarily due to a higher scope of work on projects performed in 2022 as compared to 2021.
Financing Activities
Net cash flow provided by financing activities decreased $24.3 million in 2022 primarily due to:
•the issuance of $400 million of 3.35% Series mortgage bonds in March 2021;
•money pool activity;
•capital contributions of $51.2 million received in 2021 from the noncontrolling tax equity investor in AR Searcy Partnership, LLC and used by the partnership to acquire the Searcy Solar facility. See Note 14 to the financial statements for discussion of the Searcy Solar facility purchase;
•lower prepaid deposits of $50.9 million related to contributions-in-aid-of-construction reimbursement agreements in 2022 as compared to 2021; and
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
•an increase of $36 million in common equity distributions paid in 2022 as compared to 2021 in order to maintain Entergy Arkansas’s capital structure.
The decrease was partially offset by:
•the repayment, at maturity, of $350 million of 3.75% Series mortgage bonds in February 2021;
•the issuance of $200 million of 4.20% Series mortgage bonds in March 2022; and
•the repayment, at maturity, of $45 million of 2.375% Series governmental bonds in January 2021.
Increases in Entergy Arkansas’s payable to the money pool are a source of cash flow, and Entergy Arkansas’s payable to the money pool increased $40.9 million in 2022 compared to increasing by $139.9 million in 2021. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
See Note 5 to the financial statements for further details of long-term debt.
2021 Compared to 2020
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Arkansas’s Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 25, 2022, for discussion of operating, investing, and financing cash flow activities for 2021 compared to 2020.
Capital Structure
Entergy Arkansas’s debt to capital ratio is shown in the following table.
| | | | | | | | | | | |
| | December 31,
2022 | | December 31,
2021 |
| Debt to capital | 52.5 | % | | 52.6 | % |
| Effect of subtracting cash | — | % | | — | % |
| Net debt to net capital (non-GAAP) | 52.5 | % | | 52.6 | % |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. Entergy Arkansas uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition. The net debt to net capital ratio is a non-GAAP measure. Entergy Arkansas also uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition because net debt indicates Entergy Arkansas’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Arkansas seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a distribution, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Arkansas may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reducing distributions, Entergy Arkansas may receive equity contributions to maintain its capital structure.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Uses of Capital
Entergy Arkansas requires capital resources for:
•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.
Following are the amounts of Entergy Arkansas’s planned construction and other capital investments.
| | | | | | | | | | | | | | | | | |
| | 2023 | | 2024 | | 2025 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation | $255 | | | $1,175 | | | $910 | |
| Transmission | 110 | | | 160 | | | 135 | |
| Distribution | 285 | | | 425 | | | 350 | |
| Utility Support | 105 | | | 65 | | | 90 | |
| Total | $755 | | | $1,825 | | | $1,485 | |
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Arkansas includes investments in generation projects to modernize, decarbonize, and diversify Entergy Arkansas’s portfolio, including Walnut Bend Solar, West Memphis Solar, and Driver Solar; investments in ANO 1 and 2; distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to drive reliability and resilience while also supporting renewables expansion; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, government actions, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.
While Entergy Arkansas is still assessing the effect on its planned solar projects, the investigation by the U.S. Department of Commerce into potential circumvention of duties and tariffs may result in increased duties or tariffs on imported solar panels and has exacerbated previously existing supply chain disruptions, which have negatively affected the timing and cost of completion of these projects.
Following are the amounts of Entergy Arkansas’s existing debt and lease obligations (includes estimated interest payments).
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2023 | | 2024 | | 2025 | | 2026-2027 | | After 2027 |
| | (In Millions) |
| Long-term debt (a) | $432 | | | $504 | | | $123 | | | $898 | | | $5,060 | |
| Operating leases (b) | $16 | | | $14 | | | $12 | | | $16 | | | $2 | |
| Finance leases (b) | $3 | | | $3 | | | $3 | | | $4 | | | $2 | |
(a)Long-term debt is discussed in Note 5 to the financial statements.
(b)Lease obligations are discussed in Note 10 to the financial statements.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Other Obligations
Entergy Arkansas currently expects to contribute approximately $54.5 million to its qualified pension plans and approximately $526 thousand to its other postretirement health care and life insurance plans in 2023, although the 2023 required pension contributions will be known with more certainty when the January 1, 2023 valuations are completed, which is expected by April 1, 2023. See “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Entergy Arkansas has $175.4 million of unrecognized tax benefits net of unused tax attributes plus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition, Entergy Arkansas enters into fuel and purchased power agreements that contain minimum purchase obligations. Entergy Arkansas has rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations. See Note 8 to the financial statements for discussion of Entergy Arkansas’s obligations under the Unit Power Sales Agreement.
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Arkansas pays distributions from its earnings at a percentage determined monthly.
Renewables
Walnut Bend Solar
In October 2020, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 100 MW Walnut Bend Solar facility is in the public interest. Entergy Arkansas primarily requested cost recovery through the formula rate plan rider. In July 2021 the APSC granted Entergy Arkansas’s petition and approved the acquisition of the resource and cost recovery through the formula rate plan rider. In addition, the APSC directed Entergy Arkansas to file a report within 180 days detailing its efforts to obtain a tax equity partnership. In January 2022, Entergy Arkansas filed its tax equity partnership status report and will file subsequent reports until a tax equity partnership is obtained or a tax equity partnership is no longer sought. Closing was expected to occur in 2022. The counter-party notified Entergy Arkansas that it was terminating the project, though it was willing to consider an alternative for the site. Entergy Arkansas disputed the right of termination. Negotiations are ongoing, including with respect to cost and schedule and to updates arising as a result of the Inflation Reduction Act of 2022, and the updates would require additional APSC approval. At this time, the project, if approved, is expected to achieve commercial operation in 2024.
West Memphis Solar
In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 180 MW West Memphis Solar facility is in the public interest. In October 2021 the APSC granted Entergy Arkansas’s petition and approved the acquisition of the West Memphis Solar facility and cost recovery through the formula rate plan rider. In addition, the APSC directed Entergy Arkansas to file a report within 180 days detailing its efforts to obtain a tax equity partnership. In April 2022, Entergy Arkansas filed its tax equity partnership status report and will file subsequent reports until a tax equity partnership is obtained or a tax equity partnership is no longer sought. Closing had been expected to occur in 2023. In March 2022 the counter-party notified Entergy Arkansas that it was seeking changes to certain terms of the build-own-transfer agreement, including both cost and schedule. In January 2023, Entergy Arkansas filed a supplemental application with the APSC seeking approval for a change in the transmission route and updates to the cost and schedule that were previously approved by the APSC. The project is expected to achieve commercial operation in 2024.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Driver Solar
In April 2022, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 250 MW Driver Solar facility is in the public interest and requested cost recovery through the formula rate plan rider. The APSC established a procedural schedule with a hearing scheduled in June 2022, but the parties later agreed to waive the hearing and submit the matter to the APSC for a decision consistent with the filed record. In August 2022 the APSC granted Entergy Arkansas’s petition and approved the acquisition of Driver Solar and cost recovery through the formula rate plan rider. In addition, the APSC directed Entergy Arkansas to inform the APSC as to the status of a tax equity partnership once construction is commenced. The parties are evaluating the effects of certain matters related to the Inflation Reduction Act of 2022, including the viability of a tax equity partnership. The project is expected to achieve commercial operation in 2024.
Sources of Capital
Entergy Arkansas’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•the Entergy System money pool;
•debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations, Entergy Arkansas expects to continue, when economically feasible, to retire higher-cost debt and replace it with lower-cost debt if market conditions permit.
All debt and common and preferred membership interest issuances by Entergy Arkansas require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in Entergy Arkansas’s bond indenture and other agreements. Entergy Arkansas has sufficient capacity under these tests to meet its foreseeable capital needs for the next twelve months and beyond.
Entergy Arkansas’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
| | | | | | | | | | | | | | | | | | | | |
| 2022 | | 2021 | | 2020 | | 2019 |
| (In Thousands) |
| ($180,795) | | ($139,904) | | $3,110 | | ($21,634) |
See Note 4 to the financial statements for a description of the money pool.
Entergy Arkansas has a credit facility in the amount of $150 million scheduled to expire in June 2027. Entergy Arkansas also has a $25 million credit facility scheduled to expire in April 2023. The $150 million credit facility includes fronting commitments for the issuance of letters of credit against $5 million of the borrowing capacity of the facility. As of December 31, 2022, there were no cash borrowings and no letters of credit outstanding under the credit facilities. In addition, Entergy Arkansas is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2022, $5.6 million in
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
letters of credit were outstanding under Entergy Arkansas’s uncommitted letter of credit facility. See Note 4 to the financial statements for further discussion of the credit facilities.
The Entergy Arkansas nuclear fuel company variable interest entity has a credit facility in the amount of $80 million scheduled to expire in June 2025. As of December 31, 2022, there were no loans outstanding under the credit facility for the Entergy Arkansas nuclear fuel company variable interest entity. See Note 4 to the financial statements for further discussion of the nuclear fuel company variable interest entity credit facility.
Entergy Arkansas obtained authorization from the FERC through October 2023 for short-term borrowings not to exceed an aggregate amount of $250 million at any time outstanding and borrowings by its nuclear fuel company variable interest entity. See Note 4 to the financial statements for further discussion of Entergy Arkansas’s short-term borrowing limits. The long-term securities issuances of Entergy Arkansas are limited to amounts authorized by the FERC. The APSC has concurrent jurisdiction over Entergy Arkansas’s first mortgage bond/secured issuances. Entergy Arkansas has obtained long-term financing authorization from the FERC that extends through October 2023. Entergy Arkansas has obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2023.
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy Arkansas charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Arkansas is regulated, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the APSC, is primarily responsible for approval of the rates charged to customers.
Retail Rates
2020 Formula Rate Plan Filing
In July 2020, Entergy Arkansas filed with the APSC its 2020 formula rate plan filing to set its formula rate for the 2021 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2021, as amended through subsequent filings in the proceeding, and a netting adjustment for the historical year 2019. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2021 projected year is 8.22% resulting in a revenue deficiency of $64.3 million. The earned rate of return on common equity for the 2019 historical year was 9.07% resulting in a $23.9 million netting adjustment. The total proposed revenue change for the 2021 projected year and 2019 historical year netting adjustment was $88.2 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $74.3 million. As part of the formula rate plan tariff the calculation for the revenue constraint was updated based on actual revenues which had the effect of reducing the initially-proposed $74.3 million revenue requirement increase to $72.6 million. In October 2020, Entergy Arkansas filed with the APSC a unanimous settlement agreement reached with the other parties that resolved all but one issue. As a result of the settlement agreement, Entergy Arkansas’s requested revenue increase was $68.4 million, including a $44.5 million increase for the projected 2021 year and a $23.9 million netting adjustment. The remaining issue litigated concerned the methodology used to calculate the netting adjustment within the formula rate plan. In December 2020 the APSC issued an order rejecting the netting adjustment method used by Entergy Arkansas. Applying the approach ordered by the APSC changed the netting adjustment for the 2019 historical year from a $23.9 million deficiency to $43.5 million excess. Overall, the decision reduced Entergy Arkansas’s revenue adjustment for 2021 to $1 million. In December 2020, Entergy Arkansas filed a petition for rehearing of the APSC’s decision in the 2020 formula rate plan proceeding regarding the 2019 netting adjustment, and in January 2021 the APSC granted further consideration of Entergy Arkansas’s petition. Based on the progress of the proceeding at that point, in December 2020, Entergy Arkansas recorded a regulatory liability of $43.5 million to reflect the netting adjustment for 2019, as included in the APSC’s December 2020 order, which would be returned
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
to customers in 2021. Entergy Arkansas also requested an extension of the formula rate plan rider for a second five-year term. In March 2021 the Arkansas Governor signed HB1662 into law (Act 404). Act 404 clarified aspects of the original formula rate plan legislation enacted in 2015, including with respect to the extension of a formula rate plan, the methodology for the netting adjustment, and debt and equity levels; it also reaffirmed the customer protections of the original formula rate plan legislation, including the cap on annual formula rate plan rate changes. Pursuant to Act 404, Entergy Arkansas’s formula rate plan rider was extended for a second five-year term. Entergy Arkansas filed a compliance tariff in its formula rate plan docket in April 2021 to effectuate the netting provisions of Act 404, which reflected a net change in required formula rate plan rider revenue of $39.8 million, effective with bills rendered on and after the first billing cycle of May 2021. In April 2021 the APSC issued an order approving the compliance tariff and recognizing the formula rate plan extension. Also in April 2021, Entergy Arkansas filed for approval of modifications to the formula rate plan tariff incorporating the provisions in Act 404, and the APSC approved the tariff modifications in April 2021. Given the APSC general staff’s support for the expedited approval of these filings by the APSC, Entergy Arkansas supported an amendment to Act 404 to achieve a reduced return on equity from 9.75% to 9.65% to apply for years applicable to the extension term; that amendment was signed by the Arkansas Governor in April 2021 and is now Act 894. Based on the APSC’s order issued in April 2021, in the first quarter 2021, Entergy Arkansas reversed the remaining regulatory liability for the netting adjustment for 2019. In June 2021, Entergy Arkansas filed another compliance tariff in its formula rate plan proceeding to effectuate the additional provisions of Act 894, and the APSC approved the second compliance tariff filing in July 2018.2021.
2021 Formula Rate Plan Filing
In July 2021, Entergy Arkansas filed with the APSC its 2021 formula rate plan filing to set its formula rate for the 2022 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2022 and a netting adjustment for the historical year 2020. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2022 projected year is 7.65% resulting in a revenue deficiency of $89.2 million. The earned rate of return on common equity for the 2020 historical year was 7.92% resulting in a $19.4 million netting adjustment. The total proposed revenue change for the 2022 projected year and 2020 historical year netting adjustment is $108.7 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase is limited to $72.4 million. In October 20192021, Entergy Arkansas filed with the LPSC staff issuedAPSC a settlement agreement reached with other parties resolving all issues in the proceeding. As a result of the settlement agreement, the total proposed revenue change is $82.2 million, including a $62.8 million increase for the projected 2022 year and a $19.4 million netting adjustment. Because Entergy Arkansas’s revenue requirement exceeded the constraint, the resulting increase is limited to $72.1 million. In December 2021 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 2022.
2022 Formula Rate Plan Filing
In July 2022, Entergy Arkansas filed with the APSC its report finding2022 formula rate plan filing to set its formula rate for the 2023 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2023 and a netting adjustment for the historical year 2021. The filing showed that Entergy Louisiana’sArkansas’s earned rate of return on common equity for the 2023 projected year is 7.40% resulting in a revenue deficiency of $104.8 million. The earned rate of return on common equity for the 2021 historical year was 8.38% resulting in a $15.2 million netting adjustment. The total proposed revenue change for the 2023 projected year and 2021 historical year netting adjustment is $119.9 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement was subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $79.3 million. In October 2022 other parties filed their testimony recommending various adjustments to Entergy Arkansas’s overall proposed revenue deficiency, and Entergy Arkansas filed a response including an update to actual revenues through August 2022, which raised the constraint to $79.8 million. In November 2022, Entergy Arkansas filed with the APSC a settlement agreement reached with other parties resolving all issues in the
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
proceeding. As a result of the settlement agreement, the total revenue change was $102.8 million, including a $87.7 million increase for the 2023 projected year and a $15.2 million netting adjustment. Because Entergy Arkansas’s revenue requirement exceeded the constraint, the resulting increase was limited to $79.8 million. In December 2022 the APSC approved the settlement agreement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2023.
Green Promise Renewable Tariff
In July 2021, Entergy Arkansas filed a proposed green tariff designed to help participating customers meet their renewable and sustainability goals and to enhance economic development efforts in Arkansas. The total proposed amount of solar capacity requested to be available under this tariff was up to 200 MW. In September and October 2021 the APSC general staff and two net metering developer intervenors filed responses indicating opposition to the tariff as proposed. The tariff was supported by certain commercial and industrial customers that have indicated an interest in subscribing to the tariff. In October 2021, Entergy Arkansas, Walmart, and industrial customers filed a non-unanimous settlement agreement supporting that the tariff should be approved as filed by Entergy Arkansas; the Arkansas Attorney General stated it did not oppose the settlement. In January 2022 the APSC general staff filed in opposition to the non-unanimous settlement agreement, and one of the net metering developer intervenors withdrew from the proceeding. In January 2022 the parties agreed to a paper hearing with written responses to the APSC’s questions being filed in February and March 2022. In May 2022 the APSC found Entergy Arkansas’s proposal for the tariff to be just and reasonable for an initial offering of 100 MW of solar capacity, and in June 2022 the APSC approved Entergy Arkansas’s compliance tariff filing.
Energy Cost Recovery Rider
Entergy Arkansas’s retail rates include an energy cost recovery rider to recover fuel and purchased energy costs in monthly customer bills. The rider utilizes the prior calendar-year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over- or under-recovery, including carrying charges, of the energy costs for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs.
In January 2014, Entergy Arkansas filed a motion with the APSC relating to its upcoming energy cost rate redetermination filing that was made in March 2014. In that motion, Entergy Arkansas requested that the APSC authorize Entergy Arkansas to exclude from the redetermination of its 2014 energy cost rate $65.9 million of incremental fuel and replacement energy costs incurred in 2013 as a result of the ANO stator incident. Entergy Arkansas requested that the APSC authorize Entergy Arkansas to retain that amount in its deferred fuel balance, with recovery to be reviewed in a later period after more information was available regarding various claims associated with the ANO stator incident. In February 2014 the APSC approved Entergy Arkansas’s request to retain that amount in its deferred fuel balance. In July 2017, Entergy Arkansas filed for a change in rates pursuant to its formula rate plan rider. In that proceeding, the APSC approved a settlement agreement agreed upon by the parties, including a provision that requires Entergy Arkansas to initiate a regulatory proceeding for the purpose of recovering funds currently withheld from rates and related to the stator incident, including the $65.9 million of deferred fuel and purchased energy costs and costs related to the incremental oversight previously noted, subject to certain timelines and conditions set forth in the settlement agreement, including the resolution of civil litigation currently pending regarding the stator incident by the Circuit Court of Pope County, Arkansas. A trial date was established by the circuit court for March 1, 2023, but has been continued. In December 2022 the APSC approved Entergy Arkansas’s request for an additional extension of the deadline for initiating a regulatory proceeding for the purpose of recovering funds related to the stator incident to no later than sixty days after the circuit court issues a final order in the civil litigation proceedings. See the “ANO Damage, Outage, and NRC Reviews” section in Note 8 to the financial statements for further discussion of the ANO stator incident.
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Management’s Financial Discussion and Analysis
In March 2017, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01164 per kWh to $0.01547 per kWh. The APSC staff filed testimony in March 2017 recommending that the redetermined rate be implemented with the first billing cycle of April 2017 under the normal operation of the tariff. Accordingly, the redetermined rate went into effect on March 31, 2017 pursuant to the tariff. In July 2017 the Arkansas Attorney General requested additional information to support certain of the costs included in Entergy Arkansas’s 2017 energy cost rate redetermination.
In March 2018, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01547 per kWh to $0.01882 per kWh. The Arkansas Attorney General filed a response to Entergy Arkansas’s annual redetermination filing requesting that the APSC suspend the proposed tariff to investigate the amount of the redetermination or, alternatively, to allow recovery subject to refund. Among the reasons the Attorney General cited for suspension were questions pertaining to how Entergy Arkansas forecasted sales and potential implications of the Tax Cuts and Jobs Act. Entergy Arkansas replied to the Attorney General’s filing and stated that, to the extent there are questions pertaining to its load forecasting or the operation of the energy cost recovery rider, those issues exceed the scope of the instant rate redetermination. Entergy Arkansas also stated that potential effects of the Tax Cuts and Jobs Act are appropriately considered in the APSC’s separate proceeding regarding potential implications of the tax law. The APSC general staff filed a reply to the Attorney General’s filing and agreed that Entergy Arkansas’s filing complied with the terms of the energy cost recovery rider. The redetermined rate stabilization plan but recommendingbecame effective with the first billing cycle of April 2018. Subsequently in April 2018 the APSC issued an additionalorder 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 $0.7Entergy 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 2020, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $0.01462 per kWh to $0.01052 per kWh. The redetermined rate became effective with the first billing cycle in April 2020 through the normal operation of the tariff.
In March 2021, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $0.01052 per kWh to $0.00959 per kWh. The redetermined rate calculation also included an adjustment to account for a portion of the increased fuel costs resulting from the February 2021 winter storms. The redetermined rate became effective with the first billing cycle in April 2021 through the normal operation of the tariff.
In March 2022, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase from $0.00959 per kWh to $0.01785 per kWh. The primary reason for the rate increase is a large under-recovered balance as a result of higher natural gas prices in 2021, particularly in the fourth quarter 2021. At the request of the APSC general staff, Entergy Arkansas deferred its request for recovery of $32 million from the under-recovery related to the Tax Act. A procedural schedule has not been established.2021 February winter storms until the 2023 energy cost rate redetermination, unless a request for an interim adjustment to the energy cost recovery rider is necessary. This resulted in a redetermined rate of $0.016390 per kWh, which became effective with the first billing cycle in April 2022 through the normal operation of the tariff. In February 2023 the APSC issued orders initiating proceedings with the utilities to address the prudence of costs incurred and appropriate cost allocation of the 2021 February winter storms. With respect to any prudence review of Entergy Arkansas fuel costs, as part of the APSC’s
2018 Rate Stabilization Plan FilingEntergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
draft report issued in its 2021 February winter storm investigation docket, the APSC included findings that the load shedding plans of the investor-owned utilities and some cooperatives were appropriate and comprehensive, and, further, that Entergy Arkansas’s emergency plan was comprehensive and had a multilayered approach supported by a system-wide response plan, which is considered an industry standard.
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 2019, Entergy Louisiana2011 filed with the FERC exceptions to the decision.
The FERC issued a decision in June 2012 and held that, while the System Agreement is ambiguous, it does provide authority for individual Utility operating companies to make opportunity sales for their own account and Entergy Arkansas made and priced these sales in good faith. The FERC found, however, that the System Agreement does not provide authority for an individual Utility operating company to allocate the energy associated with such opportunity sales as part of its load but provides a different allocation authority. The FERC further found that the after-the-fact accounting methodology used to allocate the energy used to supply the sales was inconsistent with the System Agreement. The FERC in its decision established further hearing procedures to quantify the effect of repricing the opportunity sales in accordance with the FERC’s June 2012 decision. The hearing was held in May 2013 and the ALJ issued an initial decision in August 2013. The LPSC, the APSC, the City Council, and FERC staff filed briefs on exceptions and/or briefs opposing exceptions. Entergy filed a brief on exceptions requesting that the FERC reverse the initial decision and a brief opposing certain exceptions taken by the LPSC and FERC staff.
In April 2016 the FERC issued orders addressing requests for rehearing filed in July 2012 and the ALJ’s August 2013 initial decision. The first order denied Entergy’s request for rehearing and affirmed the FERC’s earlier rulings that Entergy’s original methodology for allocating energy costs to the opportunity sales was incorrect and, as a result, Entergy Arkansas must make payments to the other Utility operating companies to put them in the same position that they would have been in absent the incorrect allocation. The FERC clarified that interest should be included with the payments. The second order affirmed in part, and reversed in part, the rulings in the ALJ’s August 2013 initial decision regarding the methodology that should be used to calculate the payments Entergy Arkansas is to make to the other Utility operating companies. The FERC affirmed the ALJ’s ruling that a full re-run of intra-system bills should be performed but required that methodology be modified so that the sales have the same priority for purposes of energy allocation as joint account sales. The FERC reversed the ALJ’s decision that any payments by Entergy Arkansas should be reduced by 20%. The FERC also reversed the ALJ’s decision that adjustments to other System Agreement service schedules and excess bandwidth payments should not be taken into account when calculating the payments to be made by Entergy Arkansas. The FERC held that such adjustments and excess bandwidth payments should be taken into account but ordered further proceedings before an ALJ to address
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whether a cap on any reduction due to bandwidth payments was necessary and to implement the other adjustments to the calculation methodology.
In May 2016, Entergy Services filed a request for rehearing of the FERC’s April 2016 order arguing that payments made by Entergy Arkansas should be reduced as a result of the timing of the LPSC’s approval of certain contracts. Entergy Services also filed a request for clarification and/or rehearing of the FERC’s April 2016 order addressing the ALJ’s August 2013 initial decision. The APSC and the LPSC also filed requests for rehearing of the FERC’s April 2016 order. In September 2017 the FERC issued an order denying the request for rehearing on the issue of whether any payments by Entergy Arkansas to the other Utility operating companies should be reduced due to the timing of the LPSC’s approval of Entergy Arkansas’s wholesale baseload contract with Entergy Louisiana. In November 2017 the FERC issued an order denying all of the remaining requests for rehearing of the April 2016 order. In November 2017, Entergy Services filed a petition for review in the D.C. Circuit of the FERC’s orders in the first two phases of the opportunity sales case. In December 2017 the D.C. Circuit granted Entergy Services’ request to hold the appeal in abeyance pending final resolution of the related proceeding before the FERC. In January 2018 the APSC and the LPSC filed separate petitions for review in the D.C. Circuit, and the D.C. Circuit consolidated the appeals with Entergy Services’ appeal.
The hearing required by the FERC’s April 2016 order was held in May 2017. In July 2017 the ALJ issued an initial decision addressing whether a cap on any reduction due to bandwidth payments was necessary and whether to implement the other adjustments to the calculation methodology. In August 2017 the Utility operating companies, the LPSC, the APSC, and FERC staff filed individual briefs on exceptions challenging various aspects of the initial decision. In September 2017 the Utility operating companies, the LPSC, the APSC, the MPSC, the City Council, and FERC staff filed separate briefs opposing exceptions taken by various parties.
Based on testimony previously submitted in the case and its gas rate stabilization planassessment 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 test year endedincreased 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 30, 2018.2000 should be included in the calculation of Entergy Arkansas’s payment. The filingFERC affirmed on other grounds the ALJ’s rejection of the evaluation reportLPSC’s claim that certain joint account sales should be accounted for the test year 2018 reflected an earned return on common equity of 2.69%. This earned return is below the earning sharing bandas part of the gas rate stabilization plancalculation of Entergy Arkansas’s payment. In November 2018 the LPSC requested rehearing of the FERC’s October 2018 decision. In December 2019 the FERC denied the LPSC’s request for rehearing. In January 2020 the LPSC appealed the December 2019 decision to the D.C. Circuit.
Entergy Arkansas, LLC and results in a rate increase of $2.8 million.Subsidiaries
Management’s Financial Discussion and Analysis
In December 2018, Entergy Louisiana made a compliance filing in response to the FERC’s October 2018 order. The compliance filing provided a final calculation of Entergy Arkansas’s payments to the other Utility operating companies, including interest. No protests were filed in response to the December 2018 compliance filing. Refunds and interest in the following amounts were paid by Entergy Arkansas to the other operating companies in December 2018:
| | | | | | | | | | | |
| | Total refunds including interest |
| Payment/(Receipt) |
| | (In Millions) |
| Principal | Interest | Total |
| Entergy Arkansas | $68 | $67 | $135 |
| Entergy Louisiana | ($30) | ($29) | ($59) |
| Entergy Mississippi | ($18) | ($18) | ($36) |
| Entergy New Orleans | ($3) | ($4) | ($7) |
| Entergy Texas | ($17) | ($16) | ($33) |
Entergy Arkansas previously recognized a regulatory asset with a balance of $116 million as of December 31, 2018 for a portion of the payments due as a result of this proceeding.
As described above, the FERC’s opportunity sales orders have been appealed to the D.C. Circuit. In February 2020 all of the appeals were consolidated and in April 2020 the D.C. Circuit established a briefing schedule. Briefing was completed in September 2020 and oral argument was heard in December 2020. In July 2021 the D.C. Circuit issued a decision denying all of the petitions for review filed in response to the FERC’s opportunity sales orders.
In February 2019 the LPSC filed a new complaint relating to two issues that were raised in the opportunity sales proceeding, but that, in its October 2018 order, the FERC held were outside the scope of the proceeding. In March 2019, Entergy Services filed an answer and rates were implemented duringmotion to dismiss the new complaint. In November 2019 the FERC issued an order denying the LPSC’s complaint. The order concluded that the settlement agreement approved by the FERC in December 2015 terminating the System Agreement barred the LPSC’s new complaint. In December 2019 the LPSC requested rehearing of the FERC’s November 2019 order, and in July 2020 the FERC issued an order dismissing the LPSC’s request for rehearing. In September 2020 the LPSC appealed to the D.C. Circuit the FERC’s orders dismissing the new opportunity sales complaint. In November 2020 the D.C. Circuit issued an order establishing that briefing will occur in January 2021 through April 2021. Oral argument was held in September 2021. In December 2021 the D.C. Circuit denied the LPSC’s Petition for Review of the new opportunity sales complaint. The opportunity sales cases are complete at FERC and at the D.C. Circuit and no additional refund amounts are owed by Entergy Arkansas.
In May 2019, Entergy Arkansas filed an application and supporting testimony with the APSC requesting approval of a special rider tariff to recover the costs of these payments from its retail customers over a 24-month period. The application requested that the APSC approve the rider to take effect within 30 days or, if suspended by the APSC as allowed by commission rule, approve the rider to take effect in the first billing cycle of Maythe first month occurring 30 days after issuance of the APSC’s order approving the rider. In June 2019 subjectthe APSC suspended Entergy Arkansas’s tariff and granted Entergy Arkansas’s motion asking the APSC to refund and final LPSC review. Theestablish the proceeding is currentlyas the single designated proceeding in its discovery phase.
Gas Rate Stabilization Plan Extension Request
In August 2019, Entergy Louisiana submitted an applicationwhich interested parties may assert claims related to the LPSC seeking extensionappropriate retail rate treatment of the gas rate stabilization plan forFERC’s October 2018 order and related FERC orders in the 2019-2021 test years onopportunity sales proceeding. In January 2020 the same terms as those approved for the 2018 test year. The LPSC establishedAPSC adopted a procedural schedule to address this request with a hearing scheduledin 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
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Management’s Financial Discussion and Analysis
arguments, including demonstrating that the claims in this proceeding differ substantially from those the APSC addressed previously and that the payment resulting from a FERC tariff violation for which Entergy Arkansas seeks retail cost recovery in this proceeding differs materially from the refunds resulting from a FERC tariff amendment that the APSC previously rejected on filed rate doctrine and the retroactive ratemaking grounds. In addition, in January 2020 the Attorney General and Arkansas Electric Energy Consumers, Inc. filed testimony opposing the recovery by Entergy Arkansas of the opportunity sales payment but also claiming that certain components of the payment should be segregated and refunded to customers. In March 2020, Entergy Arkansas filed rebuttal testimony.
In July 2020 the APSC issued a decision finding that Entergy Arkansas’s application is not in the public interest. The order also directed Entergy Arkansas to refund to its retail customers within 30 days of the order the FERC-determined over-collection of $13.7 million, plus interest, associated with a recalculated bandwidth remedy. In addition to these primary findings, the order also denied the Attorney General’s request for Entergy Arkansas to prepare a compliance filing detailing all of the retail impacts from the opportunity sales and denied a request by the Arkansas Electric Energy Consumers to recalculate all costs using the revised responsibility ratio. Entergy Arkansas filed a motion for temporary stay of the 30-day requirement to allow Entergy Arkansas a reasonable opportunity to seek rehearing of the APSC order, but in July 2020 the APSC denied Entergy Arkansas’s request for a stay and directed Entergy Arkansas to refund to its retail customers the component of the total FERC-determined opportunity sales payment that was associated with increased bandwidth remedy payments of $13.7 million, plus interest. The refunds were issued in the August 2020 billing cycle. While the APSC denied Entergy Arkansas’s stay request, Entergy Arkansas believes its actions were prudent and, therefore, the costs, including the $13.7 million, plus interest, are recoverable. In July 2020, Entergy Arkansas requested rehearing of the APSC order, which rehearing was denied by the APSC in August 2020. In September 2020, Entergy Arkansas filed a complaint in the U.S. District Court for the Eastern District of Arkansas challenging the APSC’s order denying Entergy Arkansas’s request to recover the costs of these payments. In October 2020 the APSC filed a motion to dismiss Entergy Arkansas’s complaint, to which Entergy Arkansas responded. Also in December 2020, Entergy Arkansas and the APSC held a pre-trial conference, and filed a report with the court in January 2021. The court held a hearing in February 2021 regarding issues addressed in the pre-trial conference report, and in June 2021 the court stayed all discovery until it rules on pending motions, after which the court will issue an amended schedule if necessary. In March 2022 the court denied the APSC’s motion to dismiss, and, in April 2022, issued a scheduling order including a trial date in February 2023. In June 2022, Entergy Arkansas filed a motion asserting that it is entitled to summary judgment because Entergy Arkansas’s position that the APSC’s order is pre-empted by the filed rate doctrine and violates the Dormant Commerce Clause is premised on facts that are not subject to genuine dispute. In July 2022, Arkansas Electric Energy Consumers, Inc., an industrial customer association, filed a motion to intervene and to hold Entergy Arkansas’s motion for summary judgment in abeyance pending a ruling on the motion to intervene. Entergy Arkansas filed a consolidated opposition to both motions. In August 2022 the APSC filed a motion for summary judgment arguing that there is no genuine issue as to any material fact and the APSC is entitled to judgment as a matter of law. In September 2022, Entergy Arkansas filed an opposition to the motion. In October 2022 the APSC filed a motion asking the court to hold further proceedings in abeyance pending a decision on the motions for summary judgment filed by Entergy Arkansas and the APSC. Also in October 2022, Entergy Arkansas filed an opposition to the motion, and the APSC filed a reply in support of its motion for summary judgment. In January 2023 the judge assigned to the case, on her own motion, identified facts that may present a conflict and recused herself; a new judge was assigned to the case, but he also recused due to a conflict. The case again was reassigned to a new judge. In January 2023 the court denied all pending motions (including those described above) except for a motion by the APSC to exclude certain testimony and further ruled that the matter would proceed to trial. In January 2023, Arkansas Electric Energy Consumers, Inc. filed a notice of appeal of the court’s order denying its motion to intervene to the United States Court of Appeals for the Eighth Circuit and a motion with the district court to stay the proceedings pending the appeal, which was denied. In February 2023, Arkansas Electric Energy Consumers, Inc. filed a motion with the United States Court of Appeals for the Eighth District to stay the proceedings pending the appeal, which also was denied. The trial was held in February 2023. Following the trial, Entergy Arkansas filed a motion with the United States Court of Appeals for the Eighth District
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to expedite the appeal filed by Arkansas Electric Energy Consumers, Inc. The court granted Entergy Arkansas’s request.
Net Metering Legislation
An Arkansas law was enacted effective July 2019 that, among other things, expands the definition of a “net metering customer” to include two additional types of customers: (1) customers that lease net metering facilities, subject to certain leasing arrangements, and (2) government entities or other entities exempt from state and federal income taxes that enter into a service contract for a net metering facility. The latter provision allows eligible entities, many of whom are small and large general service customers, to purchase renewable energy directly from third party providers and receive bill credits for these purchases. The APSC was given authority under this law to address certain matters, such as cost shifting and the appropriate compensation for net metered energy and initiated proceedings for this purpose. Because of the size and number of customers eligible under this new law, there is a risk of loss of load and the shifting of costs to customers. A hearing was held in December 2019, with utilities, including Entergy Arkansas, cooperatives, the Arkansas Attorney General, and industrial customers advocating the need for establishment of a reasonable rate structure that takes into account impacts to non-net metering customers; an additional hearing was conducted in February 2020 for purposes of public comment only. The APSC issued an order in June 2020, and in July 2020 several parties, including Entergy Arkansas, filed for rehearing on multiple grounds, including for the reasons that it imposes an unreasonable rate structure and allows facilities to net meter that do not meet the statutory definition of net metering facilities. After granting the rehearing requests, the APSC issued an order in September 2020 largely upholding its June 2020 order. In October 2020, Entergy Arkansas and several other parties filed an appeal of the APSC’s September 2020 order. In January 2021, Entergy Arkansas, pursuant to an APSC order, filed an updated net metering tariff, which was approved in February 2021. In May 2021, Entergy Arkansas filed a motion to dismiss its pending judicial appeal of the APSC’s September 2020 order on rehearing in the proceeding addressing its net metering rules. In June 2021 the Arkansas Court of Appeals granted the motion and dismissed Entergy Arkansas’s appeal, although other appeals of the September 2020 APSC order remained before the court. In May 2022 the court issued an order affirming the APSC’s decision in part and reversing in part. In June 2022 the APSC sought rehearing from the court with respect to the court’s ruling on a grid charge, which the court of appeals denied in July 2022. One of the cooperative appellants filed a further appeal to the Arkansas Supreme Court in July 2022, which the court decided not to hear.
Separately, as directed by the APSC general staff, the APSC opened a proceeding to compel utilities to amend their net metering tariffs to incorporate the provisions of the legislation that the APSC general staff considered “black letter law.” Entergy Arkansas, the Arkansas Attorney General, and other intervenors opposed this directive pending the development of the rules for implementation that are being considered in the separate net metering rulemaking docket. Nevertheless, reserving its rights, Entergy Arkansas has complied with the directive to amend its tariffs. Asserting procedural and due process violations, in January 2020, Entergy Arkansas and the Arkansas Attorney General separately appealed certain APSC orders in the proceeding. In December 2021 the Arkansas Court of Appeals dismissed the appeal on procedural grounds and without prejudice.
Since the enactment of the net metering legislation, the APSC has approved numerous applications allowing Entergy Arkansas customers to enter into purchase power agreements with third parties and to utilize these purchase power agreements to offset power usage by Entergy Arkansas, despite the lack of proximity between the purchase power agreement and the end-use customer. The APSC also has allowed the aggregation of accounts by net metering customers. These decisions by the APSC have created subsidies in favor of eligible net metering customers to the detriment of non-participating customers. The level of this subsidy continues to grow as additional net metering applications are approved by the APSC.
In September 2022 the APSC opened a rulemaking concerning proposed amendments to the net metering rules to address the expiration on December 31, 2022 of the automatic grandfathering of the existing net metering rate structure. Entergy Arkansas and other utility parties filed initial briefs and comments setting forth that the statute imposing the expiration of the automatic grandfathering is not ambiguous and that the APSC does not have
Entergy Arkansas, LLC and Subsidiaries
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the authority to extend the grandfathering period, and the hearing was held in October 2022. In December 2022 the APSC issued an order attempting to modify the net metering rules and purporting to allow for the potential for grandfathering after December 31, 2022. More than thirty applicants filed individual net metering applications in December 2022 seeking to be considered under the APSC’s order, although the APSC issued an order in January 2023 holding those applications in abeyance. Several parties, including Entergy Arkansas, sought rehearing, and the Arkansas’s Governor’s executive order limiting new rulemakings calls into question how the APSC’s order to adopt new rules may be effectuated.
Also in September 2022 the APSC opened another proceeding to investigate the issue of potential cost shifting arising as a result of net metering. Investor owned utilities and some cooperatives were required to make and did make filings in October 2022 with supporting documentation as to the amount and extent of cost shifting and the manner in which they would design tariffs to recover those costs on behalf of non-net metering customers. Responses to the utility and cooperative filings were filed in January 2023, and utilities filed their further responses in February 2023.
COVID-19 Orders
In April 2020, in light of the COVID-19 pandemic, the APSC issued an order requiring utilities, to the extent they had not already done so, to suspend service disconnections during the remaining pendency of the Arkansas Governor’s emergency declaration or until the APSC rescinds the directive. The order also authorized utilities to establish a regulatory asset to record costs resulting from the suspension of service disconnections, directed that in future proceedings the APSC will consider whether the request for recovery of these regulatory assets is reasonable and necessary, and required utilities to track and report the costs and any savings directly attributable to suspension of disconnects. In May 2020 the APSC approved Entergy Arkansas expanding deferred payment agreements to assist customers during the COVID-19 pandemic. Quarterly reporting began in August 2020 and the APSC ordered additional reporting in October 2020 regarding utilities’ transitional plans for ending the moratorium on service disconnects. In March 2021 the APSC issued an order confirming the lifting of the moratorium on service disconnects effective in May 2020.2021. In August 2021 the APSC general staff filed a report recommending that utilities with a formula rate plan discontinue capturing any additional direct costs and savings as a regulatory asset and seek cost recovery through the formula rate plan. The APSC general staff further recommended that uncollectible amounts should be determined as of the end of its write-off period, approximately December 2021, and recovered in the next formula rate plan filing over one year. In November 2021 the APSC found the APSC general staff’s recommendation to be premature and asked utilities to report on the continued need for a regulatory asset. Entergy LouisianaArkansas reported a continued need for a regulatory asset due to a variety of factors including the unusually long terms of the customer delayed payment agreements. As of December 31, 2022, Entergy Arkansas had a regulatory asset of $39 million for costs associated with the COVID-19 pandemic.
Remaining Useful Lives Review
In response to recent legislation, the APSC opened a proceeding in December 2022 to establish a procedure to evaluate life extensions of all utility generation units and opened a separate docket to evaluate life extensions for White Bluff, Independence, and Lake Catherine. In January 2023, Entergy Arkansas and one other party filed for rehearing of the order in the general proceeding, and Entergy Arkansas moved to dismiss the separate docket. In February 2023 the APSC granted rehearing in the general proceeding. For additional discussion related to these plants, see “Regulation of Entergy’s Business - Environmental Regulation - National Ambient Air Quality Standards - Regional Haze” in Part I, Item 1.
Federal Regulation
See the “Rate, Cost-recovery, and Other Regulation– Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.
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Nuclear Matters
Entergy Arkansas owns and, through an affiliate, operates the ANO 1 and 2 nuclear power plants. Entergy Arkansas is, therefore, subject to the risks related to owning and operating nuclear plants. These include risks related to: the use, storage, and handling and disposal of high-level and low-level radioactive materials; the substantial financial requirements, both for capital investments and operational needs, to position Entergy’s nuclear fleet to meet its operational goals; the performance and capacity factors of these nuclear plants including the financial requirements to address emerging issues related to equipment reliability; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license amendments, and decommissioning; the availability of interim or permanent sites for the disposal of spent nuclear fuel and nuclear waste, including the fees charged for such disposal; the sufficiency of nuclear decommissioning trust fund assets and earnings to complete decommissioning of each site when required; and limitations on the amounts and types of insurance commercially available for losses in connection with nuclear plant operations and catastrophic events such as a nuclear accident. In the event of an unanticipated early shutdown of either ANO 1 or 2, Entergy Arkansas may be required to file with the APSC a rate mechanism to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. ANO 1’s operating license expires in 2034 and ANO 2’s operating license expires in 2038.
Environmental Risks
Entergy Arkansas’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Arkansas is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of Entergy Arkansas’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the LPSC staff recently submittedpotential for future changes in the assumptions and measurements that could produce estimates that would have a joint stipulation that recommends approvalmaterial effect on the presentation of Entergy Arkansas’s financial position or results of operations.
Nuclear Decommissioning Costs
See “Nuclear Decommissioning Costs” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the requested extensionestimates inherent in accounting for nuclear decommissioning costs.
Utility Regulatory Accounting
See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Impairment of Long-lived Assets
See “Impairment of Long-lived Assets” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with certain modificationsthe impairment of long-lived assets.
Taxation and Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.
Qualified Pension and Other Postretirement Benefits
Entergy Arkansas’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Costs and Sensitivities
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2023 Qualified Pension Cost | | Impact on 2022 Qualified Projected Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $1,301 | | $26,969 |
| Rate of return on plan assets | | (0.25%) | | $2,600 | | $— |
| Rate of increase in compensation | | 0.25% | | $1,081 | | $5,122 |
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2023 Postretirement Benefit Cost | | Impact on 2022 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $78 | | $4,097 |
| Health care cost trend | | 0.25% | | $287 | | $3,365 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Costs and Employer Contributions
Total qualified pension cost for Entergy Arkansas in 2022 was $74.8 million, including $36.4 million in settlement costs. Entergy Arkansas anticipates 2023 qualified pension cost to be $34.1 million. Entergy Arkansas contributed $93 million to its qualified pension plans in 2022 and estimates pension contributions will be approximately $54.5 million in 2023, although the 2023 required pension contributions will be known with more certainty when the January 1, 2023 valuations are completed, which is expected by April 1, 2023.
Total other postretirement health care and life insurance benefit income for Entergy Arkansas in 2022 was $5.7 million. Entergy Arkansas expects 2023 postretirement health care and life insurance benefit income of approximately $1.9 million. Entergy Arkansas contributed $1.6 million to its other postretirement plans in 2022 and estimates 2023 contributions will be approximately $526 thousand.
Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the member and Board of Directors of
Entergy Arkansas, LLC and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy Arkansas, LLC and Subsidiaries (the “Company”) as of December 31, 2022 and 2021, the related consolidated statements of income, cash flows and changes in equity (pages 340 through 344 and applicable items in pages 53 through 245), for each of the three years in the period ended December 31, 2022, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current terms,period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Rate and Regulatory Matters —Entergy Arkansas, LLC and Subsidiaries — Refer to Note 2 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Arkansas Public Service Commission (the “APSC”), which has jurisdiction with respect to the rates of electric companies in Arkansas, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.
The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the APSC and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a 9.8%reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the APSC and the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs, including costs related to the Opportunity Sales Proceeding and refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the APSC and the FERC, involved specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and significant auditor judgment to evaluate management estimates and the subjectivity of audit evidence.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the APSC and the FERC included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation period costof 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 Company’s disclosures related to the impacts of rate for common equityregulation, including the balances recorded and provisionsregulatory developments.
• We read relevant regulatory orders issued by the APSC and the FERC for the returnCompany, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the excess accumulated deferredAPSC’s 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.
• For regulatory matters in process, including the Opportunity Sales Proceeding, we inspected the Company’s filings with the APSC and the FERC, including the annual formula rate plan filing, and considered the filings with the APSC and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.
• We obtained an analysis from management and support 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 not yet addressed in a regulatory order, including the Opportunity Sales Proceeding, to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 24, 2023
We have served as the Company’s auditor since 2001.
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | |
| | | For the Years Ended December 31, |
| | | 2022 | | 2021 | | 2020 |
| | | (In Thousands) |
| | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | | $2,673,194 | | | $2,338,590 | | | $2,084,494 | |
| | | | | | |
| OPERATING EXPENSES | | | | | | |
| Operation and Maintenance: | | | | | | |
| Fuel, fuel-related expenses, and gas purchased for resale | | 640,344 | | | 347,166 | | | 271,896 | |
| Purchased power | | 201,726 | | | 280,504 | | | 187,690 | |
| Nuclear refueling outage expenses | | 53,438 | | | 51,141 | | | 55,737 | |
| Other operation and maintenance | | 754,293 | | | 687,418 | | | 669,518 | |
| Decommissioning | | 82,326 | | | 77,696 | | | 73,319 | |
| Taxes other than income taxes | | 136,565 | | | 127,249 | | | 121,057 | |
| Depreciation and amortization | | 386,272 | | | 361,479 | | | 338,029 | |
| Other regulatory charges (credits) - net | | (89,418) | | | (31,501) | | | (35,310) | |
| TOTAL | | 2,165,546 | | | 1,901,152 | | | 1,681,936 | |
| | | | | | |
| OPERATING INCOME | | 507,648 | | | 437,438 | | | 402,558 | |
| | | | | | |
| OTHER INCOME | | | | | | |
| Allowance for equity funds used during construction | | 17,787 | | | 15,273 | | | 15,019 | |
| Interest and investment income | | 19,554 | | | 76,953 | | | 35,579 | |
| Miscellaneous - net | | (27,348) | | | (22,278) | | | (21,908) | |
| TOTAL | | 9,993 | | | 69,948 | | | 28,690 | |
| | | | | | |
| INTEREST EXPENSE | | | | | | |
| Interest expense | | 150,928 | | | 140,348 | | | 144,834 | |
| Allowance for borrowed funds used during construction | | (7,070) | | | (6,641) | | | (6,595) | |
| TOTAL | | 143,858 | | | 133,707 | | | 138,239 | |
| | | | | | |
| INCOME BEFORE INCOME TAXES | | 373,783 | | | 373,679 | | | 293,009 | |
| | | | | | |
| Income taxes | | 80,896 | | | 75,195 | | | 47,777 | |
| | | | | | |
| NET INCOME | | 292,887 | | | 298,484 | | | 245,232 | |
| | | | | | |
| Net loss attributable to noncontrolling interest | | (4,358) | | | (18,092) | | | — | |
| | | | | | |
| EARNINGS APPLICABLE TO MEMBER'S EQUITY | | $297,245 | | | $316,576 | | | $245,232 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | |
| | | For the Years Ended December 31, |
| | | 2022 | | 2021 | | 2020 |
| | | (In Thousands) |
| | | | | | |
| OPERATING ACTIVITIES | | | | | | |
| Net income | | $292,887 | | | $298,484 | | | $245,232 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 532,291 | | | 503,539 | | | 490,457 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 78,958 | | | 100,459 | | | 87,019 | |
| Changes in assets and liabilities: | | | | | | |
| Receivables | | (73,579) | | | 17,682 | | | (24,507) | |
| Fuel inventory | | (252) | | | (7,081) | | | (10,066) | |
| Accounts payable | | 64,944 | | | 27,967 | | | (22,773) | |
| Taxes accrued | | 10,936 | | | 7,753 | | | 6 | |
| Interest accrued | | 1,708 | | | (5,637) | | | (43) | |
| Deferred fuel costs | | (31,009) | | | (162,458) | | | (1,186) | |
| Other working capital accounts | | (29,789) | | | (53,343) | | | (11,061) | |
| Provisions for estimated losses | | 2,914 | | | 6,915 | | | 6,289 | |
| Other regulatory assets | | (120,603) | | | 142,706 | | | (165,534) | |
| Other regulatory liabilities | | (264,054) | | | 21,066 | | | 106,878 | |
| | | | | | |
| Pension and other postretirement liabilities | | (67,783) | | | (175,863) | | | 42,576 | |
| Other assets and liabilities | | 302,163 | | | (172,973) | | | (83,469) | |
| Net cash flow provided by operating activities | | 699,732 | | | 549,216 | | | 659,818 | |
| INVESTING ACTIVITIES | | | | | | |
| Construction expenditures | | (785,168) | | | (722,628) | | | (775,595) | |
| Allowance for equity funds used during construction | | 17,787 | | | 15,273 | | | 15,019 | |
| Nuclear fuel purchases | | (98,635) | | | (84,302) | | | (100,678) | |
| Proceeds from sale of nuclear fuel | | 37,198 | | | 16,279 | | | 30,638 | |
| | | | | | |
| Proceeds from nuclear decommissioning trust fund sales | | 248,191 | | | 530,628 | | | 321,360 | |
| Investment in nuclear decommissioning trust funds | | (269,497) | | | (524,783) | | | (336,392) | |
| Payment for purchase of assets | | (1,044) | | | (131,770) | | | (5,988) | |
| Changes in money pool receivable - net | | — | | | 3,110 | | | (3,110) | |
| | | | | | |
| | | | | | |
| | | | | | |
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | — | | | — | | | 55,001 | |
| | | | | | |
| | | | | | |
| Other | | (1,626) | | | — | | | 4,036 | |
| Net cash flow used in investing activities | | (852,794) | | | (898,193) | | | (795,709) | |
| FINANCING ACTIVITIES | | | | | | |
| Proceeds from the issuance of long-term debt | | 232,731 | | | 719,284 | | | 1,071,121 | |
| Retirement of long-term debt | | (28,521) | | | (728,917) | | | (632,175) | |
| | | | | | |
| Capital contributions from noncontrolling interest | | — | | | 51,202 | | | — | |
| | | | | | |
| Changes in money pool payable - net | | 40,891 | | | 139,904 | | | (21,634) | |
| | | | | | |
| | | | | | |
| Common equity distributions paid | | (86,000) | | | (50,000) | | | (95,000) | |
| | | | | | |
| Other | | (13,676) | | | 38,291 | | | 2,188 | |
| Net cash flow provided by financing activities | | 145,425 | | | 169,764 | | | 324,500 | |
| Net increase (decrease) in cash and cash equivalents | | (7,637) | | | (179,213) | | | 188,609 | |
| Cash and cash equivalents at beginning of period | | 12,915 | | | 192,128 | | | 3,519 | |
| Cash and cash equivalents at end of period | | $5,278 | | | $12,915 | | | $192,128 | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | |
| Cash paid (received) during the period for: | | | | | | |
| Interest - net of amount capitalized | | $147,060 | | | $143,561 | | | $140,735 | |
| Income taxes | | ($2,753) | | | ($18,933) | | | ($21,971) | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
| | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | |
| | | December 31, |
| | | 2022 | | 2021 |
| | | (In Thousands) |
| | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | | $1,911 | | | $8,155 | |
| Temporary cash investments | | 3,367 | | | 4,760 | |
| Total cash and cash equivalents | | 5,278 | | | 12,915 | |
| | | | |
| Accounts receivable: | | | | |
| Customer | | 140,513 | | | 154,412 | |
| Allowance for doubtful accounts | | (6,528) | | | (13,072) | |
| Associated companies | | 45,336 | | | 29,587 | |
| Other | | 101,096 | | | 51,064 | |
| Accrued unbilled revenues | | 116,816 | | | 101,663 | |
| Total accounts receivable | | 397,233 | | | 323,654 | |
| | | | |
| Deferred fuel costs | | 139,739 | | | 108,862 | |
| Fuel inventory - at average cost | | 51,144 | | | 50,892 | |
| Materials and supplies - at average cost | | 288,260 | | | 247,980 | |
| Deferred nuclear refueling outage costs | | 56,443 | | | 65,318 | |
| | | | |
| | | | |
| Prepayments and other | | 26,576 | | | 14,863 | |
| | | | |
| TOTAL | | 964,673 | | | 824,484 | |
| | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | |
| Decommissioning trust funds | | 1,199,860 | | | 1,438,416 | |
| | | | |
| Other | | 2,414 | | | 947 | |
| TOTAL | | 1,202,274 | | | 1,439,363 | |
| | | | |
| UTILITY PLANT | | | | |
| Electric | | 14,077,844 | | | 13,578,297 | |
| | | | |
| Construction work in progress | | 417,244 | | | 241,127 | |
| Nuclear fuel | | 176,174 | | | 182,055 | |
| TOTAL UTILITY PLANT | | 14,671,262 | | | 14,001,479 | |
| Less - accumulated depreciation and amortization | | 5,729,304 | | | 5,472,296 | |
| UTILITY PLANT - NET | | 8,941,958 | | | 8,529,183 | |
| | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | |
| Regulatory assets: | | | | |
| | | | |
| Other regulatory assets | | 1,810,281 | | | 1,689,678 | |
| Deferred fuel costs | | 68,883 | | | 68,751 | |
| Other | | 18,507 | | | 13,660 | |
| TOTAL | | 1,897,671 | | | 1,772,089 | |
| | | | |
| TOTAL ASSETS | | $13,006,576 | | | $12,565,119 | |
| | | | |
| See Notes to Financial Statements. | | | | |
| | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | |
| | | December 31, |
| | | 2022 | | 2021 |
| | | (In Thousands) |
| | | | |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | | $290,000 | | | $— | |
| | | | |
| Accounts payable: | | | | |
| Associated companies | | 276,362 | | | 217,310 | |
| Other | | 310,339 | | | 190,476 | |
| Customer deposits | | 102,799 | | | 92,511 | |
| Taxes accrued | | 100,526 | | | 89,590 | |
| | | | |
| Interest accrued | | 18,816 | | | 17,108 | |
| | | | |
| | | | |
| Other | | 43,394 | | | 38,901 | |
| TOTAL | | 1,142,236 | | | 645,896 | |
| | | | |
| NON-CURRENT LIABILITIES | | | | |
| Accumulated deferred income taxes and taxes accrued | | 1,498,234 | | | 1,416,201 | |
| Accumulated deferred investment tax credits | | 28,472 | | | 29,299 | |
| Regulatory liability for income taxes - net | | 435,157 | | | 431,655 | |
| Other regulatory liabilities | | 475,758 | | | 743,314 | |
| Decommissioning | | 1,472,736 | | | 1,390,410 | |
| Accumulated provisions | | 79,998 | | | 77,084 | |
| Pension and other postretirement liabilities | | 118,020 | | | 185,789 | |
| Long-term debt | | 3,876,500 | | | 3,958,862 | |
| Other | | 97,650 | | | 110,754 | |
| TOTAL | | 8,082,525 | | | 8,343,368 | |
| | | | |
| Commitments and Contingencies | | | | |
| | | | |
| | | | |
| | | | |
| EQUITY | | | | |
| Member's equity | | 3,753,990 | | | 3,542,745 | |
| Noncontrolling interest | | 27,825 | | | 33,110 | |
| TOTAL | | 3,781,815 | | | 3,575,855 | |
| | | | |
| TOTAL LIABILITIES AND EQUITY | | $13,006,576 | | | $12,565,119 | |
| | | | |
| See Notes to Financial Statements. | | | | |
| | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| For the Years Ended December 31, 2022, 2021, and 2020 |
| | | | | |
| | Noncontrolling Interest | | Member's Equity | | Total |
| | (In Thousands) |
| | | | | |
| Balance at December 31, 2019 | $— | | | $3,125,937 | | | $3,125,937 | |
| Net income | — | | | 245,232 | | | 245,232 | |
| | | | | |
| | | | | |
| Common equity distributions | — | | | (95,000) | | | (95,000) | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Balance at December 31, 2020 | $— | | | $3,276,169 | | | $3,276,169 | |
| Net income (loss) | (18,092) | | | 316,576 | | | 298,484 | |
| | | | | |
| | | | | |
| Common equity distributions | — | | | (50,000) | | | (50,000) | |
| | | | | |
| | | | | |
| Capital contributions from noncontrolling interest | 51,202 | | | — | | | 51,202 | |
| | | | | |
| Balance at December 31, 2021 | $33,110 | | | $3,542,745 | | | $3,575,855 | |
| Net income (loss) | (4,358) | | | 297,245 | | | 292,887 | |
| | | | | |
| | | | | |
| Common equity distributions | — | | | (86,000) | | | (86,000) | |
| | | | | |
| | | | | |
| | | | | |
| Distributions to noncontrolling interest | (927) | | | — | | | (927) | |
| | | | | |
| Balance at December 31, 2022 | $27,825 | | | $3,753,990 | | | $3,781,815 | |
| | | | | |
| See Notes to Financial Statements. | | | | | |
ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
2022 Compared to 2021
Net Income
Net income increased $201.9 million primarily due to the net effects of Entergy Louisiana’s storm cost securitization, including a $290 million reduction in income tax expense, partially offset by a $224.4 million ($165.4 million net-of-tax) regulatory charge to reflect its obligation to share the benefits of the securitization with customers. Also contributing to the net income increase was higher volume/weather and higher retail electric price, partially offset by higher other operation and maintenance expenses, higher depreciation and amortization expenses, lower other income, higher interest expense, and higher taxes other than income taxes. See Note 2 to the financial statements for further discussion of the securitization.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 2022 to 2021:
| | | | | |
| Amount |
| (In Millions) |
| 2021 operating revenues | $5,068.4 | |
| Fuel, rider, and other revenues that do not significantly affect net income | 1,013.0 | |
| Retail electric price | 111.7 | |
| Volume/weather | 108.2 | |
| Storm restoration carrying costs | 37.5 | |
| 2022 operating revenues | $6,338.8 | |
Entergy Louisiana’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.
The retail electric price variance is primarily due to increases in formula rate plan revenues, including increases in the distribution and transmission recovery mechanisms, effective September 2021 and September 2022. See Note 2 to the financial statements for further discussion of the formula rate plan proceedings.
The volume/weather variance is primarily due to an increase of 2,934 GWh, or 5%, in electricity usage across all customer classes, including the effect of more favorable weather on residential sales. The increase in commercial usage was primarily due to the effect of the COVID-19 pandemic on businesses in 2021. The increase in industrial usage was primarily due to an increase in demand from expansion projects, primarily in the chemicals, petroleum refining, and transportation industries, an increase in demand from cogeneration and small industrial customers, and an increase in demand from existing customers, primarily in the chemicals and pulp and paper industries as a result of prior year temporary plant shutdowns. The increased usage from these industrial customers has a relatively smaller effect on operating revenues because a dollar for dollar basis in a manner consistent with IRS normalization rules. The LPSC approvedlarger portion of the joint stipulation in January 2020.revenues from those customers comes from fixed charges.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2019
Total electric energy sales for Entergy Louisiana for the years ended December 31, 2022 and 2021 are as follows:
| | | | | | | | | | | | | | | | | |
| 2022 | | 2021 | | % Change |
| (GWh) | | |
| Residential | 14,119 | | | 13,445 | | | 5 | |
| Commercial | 10,927 | | | 10,388 | | | 5 | |
| Industrial | 31,666 | | | 29,978 | | | 6 | |
| Governmental | 820 | | | 787 | | | 4 | |
| Total retail | 57,532 | | | 54,598 | | | 5 | |
| Sales for resale: | | | | | |
| Associated companies | 5,416 | | | 4,950 | | | 9 | |
| Non-associated companies | 3,423 | | | 2,764 | | | 24 | |
| Total | 66,371 | | | 62,312 | | | 7 | |
See Note 19 to the financial statements for additional discussion of Entergy Louisiana’s operating revenues.
Other Income Statement Variances
Other operation and maintenance expenses increased primarily due to:
•an increase of $27.7 million in power delivery expenses primarily due to higher vegetation maintenance costs, higher reliability costs, and higher safety and training costs, partially offset by a decrease in meter reading expenses as a result of the deployment of advanced metering systems;
•an increase of $19 million in nuclear generation expenses primarily due to a higher scope of work performed in 2022 as compared to 2021 and higher nuclear labor costs;
•an increase of $10.3 million in bad debt expense, primarily due to the deferral in 2021 of bad debt expense resulting from the COVID-19 pandemic. See Note 2 to the financial statements for discussion of regulatory activity associated with the COVID-19 pandemic;
•an increase of $9.8 million due to a $14.8 million gain on the sale of a pipeline recorded in 2021 as compared to a $5 million contingent gain recorded on the 2021 sale in 2022;
•an increase of $7.5 million in customer service center support costs primarily due to higher contract costs;
•an increase of $6.6 million in non-nuclear generation expenses primarily due to higher costs associated with materials and supplies in 2022 as compared to 2021;
•an increase of $5.1 million in loss provisions;
•an increase of $4.8 million in energy efficiency expenses due to the timing of recovery from customers, partially offset by lower energy efficiency costs; and
•several individually insignificant items.
Taxes other than income taxes increased primarily due to increases in franchise taxes, increases in employment taxes, and increases in ad valorem taxes resulting from higher assessments.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Other regulatory charges (credits) - net includes a regulatory charge of $224 million, recorded in second quarter 2022, to reflect Entergy Louisiana’s obligation to provide credits to its customers in recognition of obligations related to an LPSC ancillary order issued in the Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida securitization regulatory proceeding. See Note 2 to the financial statements for discussion of the securitization. In addition, Entergy Louisiana records a regulatory charge or credit for the difference between asset retirement obligation-related expenses and nuclear decommissioning trust earnings plus asset retirement obligation related costs collected in revenue.
Other income decreased primarily due to:
•changes in decommissioning trust fund activity, including portfolio rebalancing of the decommissioning trust funds in 2022 and 2021; and
•a $31.6 million charge for the LURC’s 1% beneficial interest in the storm trust established as part of the Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida securitization.
The decrease was partially offset by:
•an increase of $58.2 million in affiliated dividend income resulting from the storm trust’s investment of securitization proceeds in affiliated preferred membership interests, partially offset by the liquidation of Entergy Louisiana’s investment in affiliated preferred membership interests acquired in connection with previous securitizations of storm restoration costs; and
•an increase of $16.8 million due to the recognition of storm restoration carrying costs, primarily related to Hurricane Ida.
See Note 2 to the financial statements for discussion of the securitization.
Interest expense increased primarily due to:
•the issuances of $500 million of 2.35% Series mortgage bonds and $500 million of 3.10% Series mortgage bonds, each in March 2021;
•the issuance of $1 billion of 0.95% Series mortgage bonds in October 2021;
•the $1.2 billion unsecured term loan drawn in January 2022. The term loan was repaid in June 2022; and
•the issuance of $500 million of 4.75% Series mortgage bonds in August 2022.
The increase was partially offset by the repayment of $200 million of 4.8% Series mortgage bonds in May 2021.
The effective income tax rates were (23.5%) for 2022 and 15.5% for 2021. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates, and for additional discussion regarding income taxes.
2021 Compared to 2020
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy Louisiana’s Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 25, 2022, for discussion of results of operations for 2021 compared to 2020.
Income Tax Legislation
See the “Income Tax Legislation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the Inflation Reduction Act of 2022.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2022, 2021, and 2020 were as follows:
| | | | | | | | | | | | | | | | | |
| | 2022 | | 2021 | | 2020 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period | $18,573 | | | $728,020 | | | $2,006 | |
| | | | | |
| Net cash provided by (used in): | | | | | |
| Operating activities | 1,177,508 | | | 1,052,526 | | | 1,072,986 | |
| Investing activities | (4,707,711) | | | (3,700,199) | | | (1,944,671) | |
| Financing activities | 3,568,243 | | | 1,938,226 | | | 1,597,699 | |
| Net increase (decrease) in cash and cash equivalents | 38,040 | | | (709,447) | | | 726,014 | |
| | | | | |
| Cash and cash equivalents at end of period | $56,613 | | | $18,573 | | | $728,020 | |
2022 Compared to 2021
Operating Activities
Net cash flow provided by operating activities increased $125 million in 2022 primarily due to:
•a decrease of $221.9 million in storm spending, primarily due to Hurricane Ida, Hurricane Laura, Hurricane Delta, and Hurricane Zeta restoration efforts in 2021;
•an increase of $64 million in income tax refunds in 2022 as a result of an intercompany income tax allocation agreement; and
•higher collections from customers.
The increase was partially offset by:
•increased fuel costs. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery;
•an increase of $23.5 million in spending on nuclear refueling outages;
•an increase of $15.8 million in interest paid in 2022; and
•payments to vendors, including timing and an increase in cost of operations.
Investing Activities
Net cash flow used in investing activities increased $1,007.5 million in 2022 primarily due to:
•an increase in investments in affiliates due to the $3,163.6 million purchase by the storm trust of preferred membership interests issued by an Entergy affiliate, partially offset by the $1,390.6 million redemption of preferred membership interests. See Note 2 to the financial statements for a discussion of the securitization;
•net payments to storm reserve escrow accounts of $293.4 million in 2022;
•an increase of $100.4 million in nuclear construction expenditures primarily due to increased spending on various nuclear projects in 2022 and higher capital expenditures for storm restoration in 2022;
•an increase of $23.1 million in non-nuclear generation construction expenditures primarily due to a higher scope of work on projects performed in 2022 as compared to 2021, including during plant outages;
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
•an increase of $13.3 million in information technology capital expenditures primarily due to increased spending on various technology projects in 2022; and
•an increase of $12.2 million as a result of fluctuations in nuclear fuel activity, primarily due to variations from year to year in the timing and pricing of fuel reload requirements, materials and services deliveries, and the timing of cash payments during the nuclear fuel cycle.
The increase was partially offset by:
•a decrease of $856.2 million in distribution construction expenditures primarily due to lower capital expenditures for storm restoration in 2022 and lower spending in 2022 on advanced metering infrastructure, partially offset by higher capital expenditures as a result of increased development in Entergy Louisiana’s service area, and increased investment in the reliability and infrastructure of Entergy Louisiana’s distribution system;
•a decrease of $328.5 million in transmission construction expenditures primarily due to lower capital expenditures for storm restoration in 2022;
•a decrease of $25.3 million in nuclear decommissioning trust fund activity as a result of a lump sum contribution in 2021 for amounts collected over a 17-month period. See Note 2 to the financial statements for a discussion of nuclear decommissioning expense recovery; and
•money pool activity.
Decreases in Entergy Louisiana’s receivables from the money pool are a source of cash flow, and Entergy Louisiana’s receivable from the money pool decreased $14.5 million in 2022 compared to increasing by $1.1 million in 2021. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Financing Activities
Net cash flow provided by financing activities increased $1,630 million in 2022 primarily due to:
•proceeds from securitization of $3.2 billion received by the storm trust in 2022;
•a capital contribution of $1 billion received indirectly from Entergy Corporation in May 2022 to finance the establishment of the storm escrow account for Hurricane Ida costs;
•the issuance of $500 million of 4.75% Series mortgage bonds in August 2022;
•money pool activity;
•the repayment, at maturity, of $200 million of 4.80% Series mortgage bonds in May 2021;
•the repayment, at maturity, of Entergy Louisiana Waterford VIE’s $40 million of 3.92% Series H secured notes in February 2021; and
•higher prepaid deposits of $32 million related to contributions-in-aid-of-construction reimbursement agreements in 2022 as compared to 2021.
The increase was partially offset by:
•the issuance of $500 million of 2.35% Series mortgage bonds and $500 million of 3.10% Series mortgage bonds, each in March 2021;
•the issuance of $1 billion of 0.95% Series mortgage bonds in October 2021;
•an increase of $564 million in common equity distributions in 2022 primarily to return to Entergy Corporation the $125 million capital contribution received in December 2021 to assist in paying for costs associated with Hurricane Ida and to maintain Entergy Louisiana’s targeted capital structure;
•the repayment, prior to maturity, in May 2022 of $435 million, a portion of the outstanding principal, of 0.62% Series mortgage bonds due November 2023;
•the repayment, at maturity, of $200 million of 3.3% Series mortgage bonds in December 2022;
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
•net repayments of $75 million in 2022 compared to net borrowings of $125 million in 2021 on Entergy Louisiana’s revolving credit facility;
•a capital contribution of $125 million received from Entergy Corporation in December 2021 in order to assist in paying costs associated with Hurricane Ida; and
•net repayments of long-term borrowings of $8.4 million in 2022 compared to net long-term borrowings of $24.1 million in 2021 on the nuclear fuel company variable interest entities’ credit facilities.
Increases in Entergy Louisiana’s payable to the money pool are a source of cash flow, and Entergy Louisiana’s payable to the money pool increased $226.1 million in 2022.
See Note 5 to the financial statements for details of long-term debt.
2021 Compared to 2020
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Louisiana’s Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 25, 2022, for discussion of operating, investing, and financing cash flow activities for 2021 compared to 2020.
Capital Structure
Entergy Louisiana’s debt to capital ratio is shown in the following table. The decrease in the debt to capital ratio for Entergy Louisiana is primarily due to the $1.0 billion capital contribution received indirectly from Entergy Corporation in May 2022.
| | | | | | | | | | | |
| | December 31,
2022 | | December 31,
2021 |
| Debt to capital | 53.0 | % | | 57.2 | % |
| | | |
| | | |
| Effect of subtracting cash | (0.1 | %) | | 0.0 | % |
| Net debt to net capital (non-GAAP) | 52.9 | % | | 57.2 | % |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and common equity. Net capital consists of capital less cash and cash equivalents. Entergy Louisiana uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Louisiana’s financial condition. The net debt to net capital ratio is a non-GAAP measure. Entergy Louisiana also uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Louisiana’s financial condition because net debt indicates Entergy Louisiana’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Louisiana seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a distribution, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Louisiana may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reducing distributions, Entergy Louisiana may receive equity contributions to maintain its capital structure.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Uses of Capital
Entergy Louisiana requires capital resources for:
•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.
Following are the amounts of Entergy Louisiana’s planned construction and other capital investments.
| | | | | | | | | | | | | | | | | |
| | 2023 | | 2024 | | 2025 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation | $405 | | | $435 | | | $1,305 | |
| Transmission | 245 | | | 545 | | | 490 | |
| Distribution | 445 | | | 545 | | | 635 | |
| Utility Support | 175 | | | 110 | | | 120 | |
| Total | $1,270 | | | $1,635 | | | $2,550 | |
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Louisiana includes specific investments in generation projects to modernize, decarbonize, and diversify Entergy Louisiana’s portfolio, including the St. Jacques Facility; investments in River Bend and Waterford 3; distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to drive reliability and resilience while also supporting renewables expansion; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, government actions, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.
While Entergy Louisiana is still assessing the effect on its planned solar projects, the investigation by the U.S. Department of Commerce into potential circumvention of duties and tariffs may result in increased duties or tariffs on imported solar panels and has exacerbated previously existing supply chain disruptions, which have negatively affected the timing and cost of completion of these projects.
Following are the amounts of Entergy Louisiana’s existing debt and lease obligations (includes estimated interest payments).
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2023 | | 2024 | | 2025 | | 2026-2027 | | After 2027 |
| | (In Millions) |
| Long-term debt (a) | $1,362 | | | $2,029 | | | $655 | | | $1,733 | | | $10,288 | |
| Operating leases (b) | $15 | | | $12 | | | $10 | | | $10 | | | $2 | |
| Finance leases (b) | $5 | | | $4 | | | $4 | | | $5 | | | $2 | |
| | | | | | | | | |
(a)Long-term debt is discussed in Note 5 to the financial statements.
(b)Lease obligations are discussed in Note 10 to the financial statements.
Other Obligations
Entergy Louisiana currently expects to contribute approximately $44.6 million to its qualified pension plans and approximately $15.4 million to its other postretirement health care and life insurance plans in 2023, although the 2023 required pension contributions will be known with more certainty when the January 1, 2023 valuations are
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
completed, which is expected by April 1, 2023. See “Critical Accounting Estimates- Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Entergy Louisiana has $21.9 million of unrecognized tax benefits net of unused tax attributes plus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition, Entergy Louisiana enters into fuel and purchased power agreements that contain minimum purchase obligations. Entergy Louisiana has rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations. See Note 8 to the financial statements for discussion of Entergy Louisiana’s obligations under the Unit Power Sales Agreement and the Vidalia purchased power agreement.
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Louisiana pays distributions from its earnings at a percentage determined monthly.
2021 Solar Certification and the Geaux Green Option
In November 2021, Entergy Louisiana filed an application with the LPSC seeking certification of and approval for the addition of four new solar photovoltaic resources with a combined nameplate capacity of 475 megawatts (the 2021 Solar Portfolio) and the implementation of a new green tariff, the Geaux Green Option (Rider GGO). The 2021 Solar Portfolio consists of four resources that are expected to provide $242 million in net benefits to Entergy Louisiana’s customers. These resources, all of which would be constructed in Louisiana, include (i) the Vacherie Facility, a 150 megawatt resource in St. James Parish; (ii) the Sunlight Road Facility, a 50 megawatt resource in Washington Parish; (iii) the St. Jacques Facility, a 150 megawatt resource in St. James Parish; and (iv) the Elizabeth Facility, a 125 megawatt resource in Allen Parish. The St. Jacques Facility would be acquired through a build-own-transfer agreement; the remaining resources involve power purchase agreements. The Sunlight Road Facility and the Elizabeth Facility have estimated in service dates in 2024, and the Vacherie Facility and the St. Jacques Facility have estimated in service dates in 2025. The filing proposed to recover the costs of the power purchase agreements through the fuel adjustment clause and the formula rate plan and the acquisition costs through the formula rate plan.
The proposed Rider GGO is a voluntary rate schedule that will enhance Entergy Louisiana’s ability to help customers meet their sustainability goals by allowing customers to align some or all of their electricity requirements with renewable energy from the resources. Because subscription fees from Rider GGO participants would help to offset the cost of the resources, the design of Rider GGO also preserves the benefits of the 2021 Solar Portfolio for non-participants by providing them with the reliability and capacity benefits of locally-sited solar generation at a discounted price.
In March 2022 direct testimony from Walmart, the Louisiana Energy Users Group (LEUG), and the LPSC staff was filed. Each party recommended that the LPSC approve the resources proposed in Entergy Louisiana’s application, and the LPSC staff witness indicated that the process through which Entergy Louisiana solicited or obtained the proposals for the resources complied with applicable LPSC orders. The LPSC staff and LEUG’s witnesses made recommendations to modify the proposed Rider GGO and Entergy Louisiana’s proposed rate relief. In April 2022 the LPSC staff and LEUG filed cross-answering testimony concerning each other’s proposed modifications to Rider GGO and the proposed rate recovery. Entergy Louisiana filed rebuttal testimony in June 2022. In August 2022 the parties reached a settlement certifying the 2021 Solar Portfolio and approving implementation of Rider GGO. In September 2022 the LPSC approved the settlement. Following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities until the later
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
of March 2023 or the completion of an environmental and economic impact study, which is ongoing. This development may potentially affect the size and final in service dates of the Vacherie and St. Jacques facilities.
System Resilience and Storm Hardening
In December 2022, Entergy Louisiana filed an application seeking a public interest finding regarding Phase I of Entergy Louisiana’s Future Ready resilience plan and approval of a rider mechanism to recover the program’s costs. Phase I reflects the first five years of a ten-year resilience plan and includes investment of approximately $5 billion, including hardening investment, transmission dead-end structures, enhanced vegetation management, and telecommunications improvement. A procedural schedule has not yet been adopted in this docket.
Sources of Capital
Entergy Louisiana’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•the Entergy System money pool;
•storm reserve escrow accounts;
•debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations, Entergy Louisiana expects to continue, when economically feasible, to retire higher-cost debt and replace it with lower-cost debt if market conditions permit.
All debt and common and preferred membership interest issuances by Entergy Louisiana require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in its bond indentures and other agreements. Entergy Louisiana has sufficient capacity under these tests to meet its foreseeable capital needs for the next twelve months and beyond.
Entergy Louisiana’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
| | | | | | | | | | | | | | | | | | | | |
| 2022 | | 2021 | | 2020 | | 2019 |
| (In Thousands) |
| ($226,114) | | $14,539 | | $13,426 | | ($82,826) |
See Note 4 to the financial statements for a description of the money pool.
Entergy Louisiana has a credit facility in the amount of $350 million scheduled to expire in June 2027. The credit facility includes fronting commitments for the issuance of letters of credit against $15 million of the borrowing capacity of the facility. As of December 31, 2022, there were $50 million of cash borrowings and no letters of credit outstanding under the credit facility. In addition, Entergy Louisiana is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2022, $20 million in letters of credit were outstanding under Entergy Louisiana’s uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
The Entergy Louisiana nuclear fuel company variable interest entities have two separate credit facilities, each in the amount of $105 million and scheduled to expire in June 2025. As of December 31, 2022, $13.1 million of loans were outstanding under the credit facility for the Entergy Louisiana River Bend nuclear fuel company variable interest entity. As of December 31, 2022, $60.8 million in loans were outstanding under the Entergy Louisiana Waterford nuclear fuel company variable interest entity credit facility. See Note 4 to the financial statements for additional discussion of the nuclear fuel company variable interest entity credit facilities.
Entergy Louisiana had $293.4 million in its storm reserve escrow account at December 31, 2022.
Entergy Louisiana obtained authorizations from the FERC through October 2023 for the following:
•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.
See Note 4 to the financial statements for further discussion of Entergy Louisiana’s short-term borrowing limits.
Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida
In August 2020 and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of Entergy Louisiana’s service area. The storms resulted in widespread outages, significant damage to distribution and transmission infrastructure, and the loss of sales during the outages. Additionally, as a result of Hurricane Laura’s extensive damage to the grid infrastructure serving the impacted area, large portions of the underlying transmission system required nearly a complete rebuild.
In October 2020, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments in connection with the issuance of shorter-term mortgage bonds to provide interim financing for restoration costs associated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta. Subsequently, Entergy Louisiana and the LPSC staff filed a joint motion seeking approval to exclude from the derivation of Entergy Louisiana’s capital structure and cost rate of debt for ratemaking purposes, including the allowance for funds used during construction, shorter-term debt up to $1.1 billion issued by Entergy Louisiana to fund costs associated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta costs on an interim basis. In November 2020 the LPSC issued an order approving the joint motion, and Entergy Louisiana issued $1.1 billion of 0.62% Series mortgage bonds due November 2023. Also in November 2020, Entergy Louisiana withdrew $257 million from its funded storm reserves.
In February 2021 two winter storms (collectively, Winter Storm Uri) brought freezing rain and ice to Louisiana. Ice accumulation sagged or downed trees, limbs, and power lines, causing damage to Entergy Louisiana’s transmission and distribution systems. The additional weight of ice caused trees and limbs to fall into power lines and other electric equipment. When the ice melted, it affected vegetation and electrical equipment, causing additional outages. As discussed in the “Fuel and purchased power recovery” section of Note 2 to the financial statements, Entergy Louisiana recovered the incremental fuel costs associated with Winter Storm Uri over a five-month period from April 2021 through August 2021.
In April 2021, Entergy Louisiana filed an application with the LPSC relating to Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri restoration costs and in July 2021, Entergy Louisiana made a supplemental filing updating the total restoration costs. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by these storms were estimated to be approximately $2.06 billion, including approximately $1.68 billion in capital costs and approximately $380 million in non-capital costs. Including carrying costs through January 2022, Entergy Louisiana sought an LPSC determination that $2.11 billion was prudently incurred and, therefore, was eligible for recovery from customers. Additionally, Entergy Louisiana requested that the LPSC determine that re-establishment of a storm escrow account to the previously authorized
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
amount of $290 million was appropriate. In July 2021, Entergy Louisiana supplemented the application with a request regarding the financing and recovery of the recoverable storm restoration costs. Specifically, Entergy Louisiana requested approval to securitize its restoration costs pursuant to Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021.
In August 2021, Hurricane Ida caused extensive damage to Entergy Louisiana’s distribution and, to a lesser extent, transmission systems resulting in widespread power outages. In September 2021, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments in connection with the issuance of approximately $1 billion of shorter-term mortgage bonds to provide interim financing for restoration costs associated with Hurricane Ida, which bonds were issued in October 2021. Also in September 2021, Entergy Louisiana sought approval for the creation and funding of a $1 billion restricted escrow account for Hurricane Ida related restoration costs, subject to a subsequent prudence review.
After filing of testimony by the LPSC staff and intervenors, which generally supported or did not oppose Entergy Louisiana’s requests in regard to Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida, the parties negotiated and executed an uncontested stipulated settlement which was filed with the LPSC in February 2022. The settlement agreement contained the following key terms: $2.1 billion of restoration costs from Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri were prudently incurred and were eligible for recovery; carrying costs of $51 million were recoverable; a $290 million cash storm reserve should be re-established; a $1 billion reserve should be established to partially pay for Hurricane Ida restoration costs; and Entergy Louisiana was authorized to finance $3.186 billion utilizing the securitization process authorized by Act 55, as supplemented by Act 293. The LPSC issued an order approving the settlement in March 2022. As a result of the financing order, Entergy Louisiana reclassified $1.942 billion from utility plant to other regulatory assets.
In May 2022 the securitization financing closed, resulting in the issuance of $3.194 billion principal amount of bonds by Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA), a political subdivision of the State of Louisiana. The securitization was authorized pursuant to the Louisiana Utilities Restoration Corporation Act, Part VIII of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana legislature approved in 2021. The LCDA loaned the proceeds to the LURC. Pursuant to Act 293, the LURC contributed the net bond proceeds to a State legislatively authorized and LURC-sponsored trust, Restoration Law Trust I (the storm trust).
Pursuant to Act 293, the net proceeds of the bonds were used by the storm trust to purchase 31,635,718.7221 Class A preferred, non-voting membership interest units (the preferred membership interests) issued by Entergy Finance Company, LLC, a majority-owned indirect subsidiary of Entergy. Entergy Finance Company is required to make annual distributions (dividends) commencing on December 15, 2022 on the preferred membership interests issued to the storm trust. These annual dividends received by the storm trust will be distributed to Entergy Louisiana and the LURC, as beneficiaries of the storm trust. Specifically, 1% of the annual dividends received by the storm trust will be distributed to the LURC, for the benefit of customers, and 99% will be distributed to Entergy Louisiana, net of storm trust expenses. The preferred membership interests have a stated annual cumulative cash dividend rate of 7% and a liquidation price of $100 per unit. The terms of the preferred membership interests include certain financial covenants to which Entergy Finance Company is subject.
Entergy and Entergy Louisiana do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA. The bonds are secured by system restoration property, which is the right granted by law to the LURC to collect a system restoration charge from customers. The system restoration charge is adjusted at least semi-annually to ensure that it is sufficient to service the bonds. Entergy Louisiana collects the system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee. Entergy Louisiana began collecting the system restoration charge effective with the first billing cycle of June 2022 and the system restoration charge is expected to remain in place up to 15 years. Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as a billing and collection agent for the LCDA and the LURC. In the remote possibility that the system restoration charge, as well as any funds in the
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
excess subaccount and funds in the debt service reserve account, are insufficient to service the bonds resulting in a payment default, the storm trust is required to liquidate Entergy Finance Company preferred membership interests in an amount equal to what would be required to cure the default. The estimated value of this indirect guarantee is immaterial.
From the proceeds from the issuance of the preferred membership interests, Entergy Finance Company distributed $1.4 billion to its parent, Entergy Holdings Company, LLC, a company wholly-owned and consolidated by Entergy. Subsequently, Entergy Holdings Company liquidated, distributing the $1.4 billion it received from Entergy Finance Company to Entergy Louisiana as holder of 6,843,780.24 units of Class A, 4,126,940.15 units of Class B, and 2,935,152.69 units of Class C preferred membership interests. Entergy Louisiana had acquired these preferred membership interests with proceeds from previous securitizations of storm restoration costs. Entergy Finance Company loaned the remaining $1.7 billion from the preferred membership interests proceeds to Entergy which used the cash to redeem $650 million of 4.00% Series senior notes due July 2022 and indirectly contributed $1 billion to Entergy Louisiana as a capital contribution.
Entergy Louisiana used the $1 billion capital contribution to fund its Hurricane Ida escrow account and subsequently withdrew the $1 billion from the escrow account. With a portion of the $1 billion withdrawn from the escrow account and the $1.4 billion from the Entergy Holdings Company liquidation, Entergy Louisiana deposited $290 million in a restricted escrow account as a storm damage reserve for future storms, used $1.2 billion to repay its unsecured term loan due June 2023, and used $435 million to redeem a portion of its 0.62% Series mortgage bonds due November 2023.
As discussed in Note 3 to the financial statements, the securitization resulted in recognition of a reduction of income tax expense of approximately $290 million by Entergy Louisiana. Entergy’s recognition of reduced income tax expense was partially offset by other tax charges resulting in a net reduction of income tax expense of $283 million. In recognition of obligations related to an LPSC ancillary order issued as part of the securitization regulatory proceeding, Entergy Louisiana recorded a $224 million ($165 million net-of-tax) regulatory charge and a corresponding regulatory liability to reflect its obligation to share the benefits of the securitization with customers.
As discussed in Note 17 to the financial statements, Entergy Louisiana consolidates the storm trust as a variable interest entity and the LURC’s 1% beneficial interest is shown as noncontrolling interest in the financial statements. In second quarter 2022, Entergy Louisiana recorded a charge of $31.6 million in other income to reflect the LURC’s beneficial interest in the trust.
In April 2022, Entergy Louisiana filed an application with the LPSC relating to Hurricane Ida restoration costs. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by Hurricane Ida currently are estimated to be approximately $2.54 billion, including approximately $1.96 billion in capital costs and approximately $586 million in non-capital costs. Including carrying costs of $57 million through December 2022, Entergy Louisiana is seeking an LPSC determination that $2.60 billion was prudently incurred and, therefore, is eligible for recovery from customers. As part of this filing, Entergy Louisiana also is seeking an LPSC determination that an additional $32 million in costs associated with the restoration of Entergy Louisiana’s electric facilities damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta as well as Winter Storm Uri was prudently incurred. This amount is exclusive of the requested $3 million in carrying costs through December 2022. In total, Entergy Louisiana is requesting an LPSC determination that $2.64 billion was prudently incurred and, therefore, is eligible for recovery from customers. As discussed above, in March 2022 the LPSC approved financing of a $1 billion storm escrow account from which funds were withdrawn to finance costs associated with Hurricane Ida restoration. In June 2022, Entergy Louisiana supplemented the application with a request regarding the financing and recovery of the recoverable storm restoration costs. Specifically, Entergy Louisiana requested approval to securitize its restoration costs pursuant to Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021. In October 2022 the LPSC staff recommended a finding that the requested storm restoration costs of $2.64 billion, including associated carrying costs of $59.1 million, were prudently incurred and are eligible for recovery from customers. The LPSC staff further recommended approval of
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Louisiana’s plans to securitize these costs, net of the $1 billion in funds withdrawn from the storm escrow account described above. The parties negotiated and executed an uncontested stipulated settlement which was filed with the LPSC in December 2022. The settlement agreement contains the following key terms: $2.57 billion of restoration costs from Hurricane Ida, Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri were prudently incurred and were eligible for recovery; carrying costs of $59.2 million were recoverable; and Entergy Louisiana was authorized to finance $1.657 billion utilizing the securitization process authorized by Act 55, as supplemented by Act 293. A procedural motion to consider the uncontested settlement at the December 2022 LPSC meeting did not pass and the settlement was not voted on. In January 2023 an ALJ with the LPSC conducted a settlement hearing to receive the uncontested settlement and supporting testimony into evidence and issued a report of proceedings, which allows the LPSC to consider the uncontested settlement without the procedural motion that did not pass in December. In January 2023, the LPSC staff approved the stipulated settlement subject to certain modifications. These modifications include the recognition of accumulated deferred income tax benefits related to damaged assets and system restoration costs as a reduction of the amount authorized to be financed utilizing the securitization process authorized by Act 55, as supplemented by Act 293, from $1.657 billion to $1.491 billion. These modifications do not affect the staff’s conclusion that all system restoration costs sought by Entergy Louisiana were reasonable and prudent. The LPSC order is not yet final and non-appealable due to the forty-five day appeal period. In February 2023 the Louisiana Bond Commission voted to authorize the LCDA to issue the bonds authorized in the LPSC’s financing order; the bond rating and marketing process has yet to occur.
State and Local Rate StabilizationRegulation and Fuel-Cost Recovery
The rates that Entergy Louisiana charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Louisiana is regulated, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the LPSC, is primarily responsible for approval of the rates charged to customers.
Retail Rates - Electric
Filings with the LPSC
2017 Formula Rate Plan Filing
In JanuaryJune 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 Cuts and Jobs 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 Cuts and Jobs 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
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Louisiana. Intervenors also objected to Entergy Louisiana’s treatment of the regulatory asset related to certain special orders by the LPSC. In August 2021 the LPSC staff issued a letter updating its objections/reservations for the 2017 test year formula rate plan evaluation report. In its letter, the LPSC staff reiterated its original objections/reservations pertaining to Entergy Louisiana’s proposed rate adjustments associated with the return of excess accumulated deferred income taxes pursuant to the Tax Cuts and Jobs Act and the treatment of accumulated deferred income taxes related to reductions of rate base, specifically how the accumulated deferred income taxes associated with uncertain tax positions have been accounted for, and test year expenses billed from Entergy Services to Entergy Louisiana. The LPSC staff further reserved its rights for future proceedings and to dispute future proposed adjustments to the 2017 test year formula rate plan evaluation report. The LPSC staff withdrew all other objections/reservations. 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.
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 decreased as a result of this filing, overall formula rate plan revenues increased by approximately $118.7 million. This outcome was 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.
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 the Willow Glen Power Station reflected in the evaluation report and to the August 2019 compliance update, which was made primarily to update the capital additions reflected in the formula rate plan’s transmission recovery mechanism, based on limited time to review it. Additionally, since the completion of certain transmission projects, the LPSC staff issued supplemental data requests addressing the prudence of Entergy Louisiana’s expenditures in connection with those projects. Entergy Louisiana responded to all such requests. In August 2021 the LPSC staff issued a letter updating its objections/reservations for the 2018 test year formula rate plan evaluation report. In its letter, the LPSC staff reiterated its original objection/reservation pertaining to test year expenses billed from Entergy Services to Entergy Louisiana and outstanding issues from the 2017 test year formula rate plan evaluation report. The LPSC staff withdrew all other objections/reservations.
Commercial operation at Lake Charles Power Station commenced in March 2020. In March 2020, Entergy Louisiana filed an update to its 2018 formula rate plan evaluation report to include the estimated first-year revenue requirement of $108 million associated with the Lake Charles Power Station. The resulting interim adjustment to rates became effective with the first billing cycle of April 2020.
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In an effort to narrow the remaining issues in formula rate plan test years 2017 and 2018, Entergy Louisiana provided notice to the parties in October 2020 that it was withdrawing its request to combine residential rates. Entergy Louisiana noted that the withdrawal is without prejudice to Entergy Louisiana’s right to seek to combine residential rates in a future proceeding.
2019 Formula Rate Plan Filing
In May 2020, Entergy Louisiana filed with the LPSC its gasformula rate stabilization plan for the test year ended September 30, 2019. The filing of the evaluation report for theits 2019 calendar year operations. The 2019 test year 2019 reflectedevaluation report produced an earned return on common equity of 10.78%9.66%. As such, no change to base rider formula rate plan revenue is required. Although base rider formula rate plan revenue did not change as a result of this filing, overall formula rate plan revenues increased by approximately $103 million. This outcome is driven by the removal of prior year credits associated with the sale of the Willow Glen Power Station and an increase in the transmission recovery mechanism. Also contributing to the overall change was an increase in legacy formula rate plan revenue requirements driven by legacy Entergy Louisiana capacity cost true-ups and higher annualized legacy Entergy Gulf States Louisiana revenues due to higher billing determinants, offset by reductions in MISO cost recovery mechanism and tax reform adjustment mechanism revenue requirements. In August 2020 the LPSC staff submitted a list of items for which it needs additional information to confirm the accuracy and compliance of the 2019 test year evaluation report. The LPSC staff objected to a proposed revenue neutral adjustment regarding a certain rider as being beyond the scope of permitted formula rate plan adjustments. Rates reflected in the May 2020 filing, with the exception of a revenue neutral rider adjustment, and as updated in an August 2020 filing, were implemented in September 2020, subject to refund. Entergy Louisiana is in the process of providing additional information and details on the May 2020 filing as requested by the LPSC staff. In August 2021 the LPSC staff issued a letter updating its objections/reservations for the 2019 test year formula rate plan filing. In its letter, the LPSC staff disputes Entergy Louisiana’s exclusion of approximately $251 thousand of interest income allocated from Entergy Operations and Entergy Services to Entergy Louisiana to the extent that there are other adjustments that would move Entergy Louisiana out of the formula rate plan deadband. The LPSC staff reserved the right to further contest the issue in future proceedings. The LPSC staff further reserved outstanding issues from the 2017 and 2018 formula rate plan evaluation reports and withdrew all other remaining objections/reservations.
In November 2020, Entergy Louisiana accepted ownership of the Washington Parish Energy Center and filed an update to its 2019 formula rate plan evaluation report to include the estimated first-year revenue requirement of $35 million associated with the Washington Parish Energy Center. The resulting interim adjustment to rates became effective with the first billing cycle of December 2020. In January 2021, Entergy Louisiana filed an update to its 2019 formula rate plan evaluation report to include the implementation of a scheduled step-up in its nuclear decommissioning revenue requirement and a true-up for under-collections of nuclear decommissioning expenses. The total rate adjustment increased formula rate plan revenues by approximately $1.2 million. The resulting interim adjustment to rates became effective with the first billing cycle of February 2021.
Request for Extension and Modification of Formula Rate Plan
In May 2020, Entergy Louisiana filed with the LPSC its application for authority to extend its formula rate plan. In its application, Entergy Louisiana sought to maintain a 9.8% return on equity, with a bandwidth of 60 basis points above and below the midpoint, with a first-year midpoint reset. The parties reached a settlement in April 2021 regarding Entergy Louisiana’s proposed formula rate plan extension. In May 2021 the LPSC approved the uncontested settlement. Key terms of the settlement include: a three year term (test years 2020, 2021, and 2022) covering a rate-effective period of September 2021 through August 2024; a 9.50% return on equity, with a smaller, 50 basis point deadband above and below (9.0%-10.0%); elimination of sharing if earnings are outside the deadband; a $63 million rate increase for test year 2020 (exclusive of riders); continuation of existing riders (transmission, additional capacity, etc.); addition of a distribution recovery mechanism permitting $225 million per year of distribution investment above a baseline level to be recovered dollar for dollar; modification of the tax mechanism to allow timely rate changes in the event the federal corporate income tax rate is changed from 21%; a
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cumulative rate increase limit of $70 million (exclusive of riders) for test years 2021 and 2022; and deferral of up to $7 million per year in 2021 and 2022 of expenditures on vegetation management for outside of right of way hazard trees.
2020 Formula Rate Plan Filing
In June 2021, Entergy Louisiana filed its formula rate plan evaluation report for its 2020 calendar year operations. The 2020 test year evaluation report produced an earned return exceedson common equity of 8.45%, with a base formula rate plan revenue increase of $63 million. Certain reductions in formula rate plan revenue driven by lower sales volumes, reductions in capacity cost and net MISO cost, and higher credits resulting from the earning sharing band ofTax Cuts and Jobs Act offset the gasbase formula rate stabilization plan revenue increase, leading to a net increase in formula rate reductionplan revenue of approximately $256 thousand.$50.7 million. The report also included multiple new adjustments to account for, among other things, the calculation of distribution recovery mechanism revenues. The effects of the changes to total formula rate plan revenue were different for each legacy company, primarily due to differences in the legacy companies’ capacity cost changes, including the effect of true-ups. Legacy Entergy Louisiana formula rate plan revenues increased by $27 million and legacy Entergy Gulf States Louisiana formula rate plan revenues increased by $23.7 million. Subject to refund and LPSC review, the resulting changes became effective for bills rendered during the first billing cycle of September 2021. Discovery commenced in the proceeding. In August 2021, Entergy Louisiana submitted an update to its evaluation report to account for various changes. Relative to the June 2021 filing, the total formula rate plan revenue increased by $14.2 million to an updated total of $64.9 million. Legacy Entergy Louisiana formula rate plan revenues increased by $32.8 million and legacy Entergy Gulf States Louisiana formula rate plan revenues increased by $32.1 million. The results of the 2020 test year evaluation report bandwidth calculation were unchanged as there was no change in the earned return on common equity of 8.45%. In September 2021 the LPSC staff filed a letter with a general statement of objections/reservations because it had not completed its review and indicated it would update the letter once its review was complete. Should the parties be unable to resolve any objections, those issues will be set for hearing, with recovery of the associated costs subject to refund.
2021 Formula Rate Plan Filing
In May 2022, Entergy Louisiana filed its formula rate plan evaluation report for its 2021 calendar year operations. The 2021 test year evaluation report produced an earned return on common equity of 8.33%, with a base formula rate plan revenue increase of $65.3 million. Other increases in formula rate plan revenue driven by reductions in Tax Cut and Jobs Act credits and additions to transmission and distribution plant in service reflected through the transmission recovery mechanism and distribution recovery mechanism are partly offset by an increase in net MISO revenues, leading to a net increase in formula rate plan revenue of $152.9 million. The effects of the changes to total formula rate plan revenue are different for each legacy company, primarily due to differences in the legacy companies’ capacity cost changes, including the effect of true-ups. Legacy Entergy Louisiana formula rate plan revenues increased by $86 million and legacy Entergy Gulf States Louisiana formula rate plan revenues increased by $66.9 million. In August 2022 the LPSC staff filed a list of objections/reservations, including outstanding issues from the test years 2017-2020 formula rate plan filings, utilizing the extraordinary cost mechanism to address one-time changes such as state tax rate changes, and failing to include an adjustment for revenues not received as a result of Hurricane Ida. Subject to refund and LPSC review, the resulting changes to formula rate plan revenues became effective for bills rendered during the first billing cycle of September 2022.
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.
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Management’s Financial Discussion and Analysis
Fuel and purchased power cost recovery
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 2014February 2021, Entergy Louisiana incurred extraordinary fuel costs associated with the February 2021 winter storms. To mitigate the effect of these costs on customer bills, in March 2021, Entergy Louisiana requested and the LPSC approved the deferral and recovery of $166 million in incremental fuel costs over five months beginning in April 2021. The incremental fuel costs remain subject to review for reasonableness and eligibility for recovery through the fuel adjustment clause mechanism. The final amount of incremental fuel costs is subject to change through the resettlement process. At its April 2021 meeting, the LPSC authorized its staff to initiate an auditreview the prudence of the February 2021 fuel adjustment clause filingscosts incurred by Entergy Gulf States Louisiana, whose business was combined with Entergy Louisianaall LPSC-jurisdictional utilities, including both gas and electric utilities. At its June 2021 meeting, the LPSC approved the hiring of consultants to assist its staff 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.this review. In January 2019,May 2022 the LPSC staff consultant issued its audit report. In its report, the LPSC staff consultant recommended that Entergy Louisiana refund approximately $900,000, plus interest, to customers based upon the imputation of a claim of vendor fault in servicing its nuclear plant. Entergy Louisiana recorded a provision in 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 ofreport regarding Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed by Entergy Louisiana through(for its fuel adjustment clause for the period from 2010 through 2013. In January 2019, the LPSC staff consultant issued its audit report. In its report, the LPSC staff consultant recommended that Entergy Louisiana refund approximately $7.3 million, plus interest, to customers based upon the imputation of a claim of vendor fault in servicing its nuclear plant. Entergy Louisiana 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.electric operations) recommending no financial disallowances, but including several prospective recommendations. Responsive testimony was filed by one intervenor and the parties agreed to suspend any procedural schedule and move toward settlement discussions to close the matter. Also in May 2022 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 2019issued 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 will also include a review of charges to legacy Entergy Gulf States Louisiana customers prior to the business combination. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2014 through 2015 and charges flowed throughreport regarding 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.
charges (for its gas operations) that did not propose any financial disallowances. The LPSC staff and Entergy Louisiana LLCsubmitted a joint report on the audit report and Subsidiariesdraft order to the LPSC concluding that Entergy Louisiana’s gas distribution operations and fuel costs were not significantly adversely affected by the February 2021 winter storms and the resulting increase in natural gas prices. The LPSC issued an order approving the joint report in October 2022.
Management’s Financial Discussion and Analysis
In May 2018March 2021 the LPSC staff provided notice of auditsan audit of Entergy Louisiana’s purchased gas adjustment clause filings.filings covering the period January 2018 through December 2020. 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.that period. Discovery commenced in September 2018. Nois ongoing, and no audit report of audit has been issued.filed.
To mitigate high electric bills, primarily driven by high summer usage and elevated gas prices, Entergy Louisiana has deferred approximately $225 million of fuel expense incurred in April, May, June, July, August, and September 2022 (as reflected on June, July, August, September, October, and November 2022 bills). These deferrals were included in the over/under calculation of the fuel adjustment clause, which is intended to recover the full amount of the costs included on a rolling twelve-month basis.
COVID-19 Orders
In April 2020 the LPSC issued an order authorizing utilities to record as a regulatory asset expenses incurred from the suspension of disconnections and collection of late fees imposed by LPSC orders associated with the COVID-19 pandemic. In addition, utilities may seek future recovery, subject to LPSC review and approval, of losses and expenses incurred due to compliance with the LPSC’s COVID-19 orders. The suspension of late fees and disconnects for non-pay was extended until the first billing cycle after July 16, 2020. In January 2021, Entergy Louisiana resumed disconnections for customers in all customer classes with past-due balances that had not made payment arrangements. Utilities seeking to recover the regulatory asset must formally petition the LPSC to do so, identifying the direct and indirect costs for which recovery is sought. Any such request is subject to LPSC review and approval. As of December 31, 2022, Entergy Louisiana had a regulatory asset of $47.8 million for costs associated with the COVID-19 pandemic.
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Net Metering Rulemaking
In September 2019 the LPSC issued an order modifying its rules regarding net metering installations. Among other things, the rule provides for 2-channel billing for net metering with excess energy put to the grid being compensated at the utility’s avoided cost. However, the rule does provide that net meter installations in place as of December 31, 2019 will be subject to 1:1 net metering with excess energy put to the grid being compensated at the full retail rate for a period of 15 years (through December 31, 2034), after which those installations will be subject to 2-channel billing. The rule also eliminates the existing limit on the cumulative number of net meter installations.
Industrial and Commercial Customers
Entergy Louisiana’s large industrial and commercial customers continually explore ways to reduce their energy costs. In particular, cogeneration is an option available to a portion of Entergy Louisiana’s industrial customer base. Entergy Louisiana responds by working with industrial and commercial customers and negotiating electric service contracts to provide competitive rates that match specific customer needs and load profiles. Entergy Louisiana actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand, from both new and existing customers.
Federal Regulation
See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.
Nuclear Matters
Nuclear Matters
Entergy Louisiana owns and, through an affiliate, operates the River Bend and Waterford 3 nuclear power plants. Entergy Louisiana is, therefore, subject to the risks related to owning and operating nuclear plants. These include risks related to: the use, storage, and handling and disposal of high-level and low-level radioactive materials; the substantial financial requirements, both for capital investments and operational needs, including the financial requirements to address emerging issues related to equipment reliability, to position Entergy’s nuclear fleet to meet its operational goals, includinggoals; the financial requirements to address emerging issues like stress corrosion crackingperformance and capacity factors of certain materials within the plant systems and the Fukushima event;these nuclear plants; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license renewal and amendments, and decommissioning; the performance and capacity factors of these nuclear plants; the availability of interim or permanent sites for the disposal of spent nuclear fuel and nuclear waste, including the fees charged for such disposal; the sufficiency of nuclear decommissioning trust fund assets and earnings to complete decommissioning of each site when required; and limitations on the amounts and types of insurance commercially available for losses in connection with nuclear plant operations and catastrophic events such as a nuclear accident. In the event of an unanticipated early shutdown of River Bend or Waterford 3, Entergy Louisiana may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. Waterford 3’s operating license expires in 2044 and River Bend’s operating license expires in 2045.
NRC Reactor Oversight Process
The NRC’s Reactor Oversight Process is a program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response. The NRC evaluates plant performance by analyzing two distinct inputs: inspection findings resulting from the NRC’s inspection program and performance indicators reported by the licensee. The evaluations result in the placement of each plant in one of the NRC’s Reactor Oversight Process Action Matrix columns: “licensee response column,” or Column 1, “regulatory response column,” or Column 2, “degraded cornerstone column,” or Column 3, “multiple/repetitive degraded cornerstone column,” or Column 4, and “unacceptable performance,” or Column 5. Plants in Column 1 are subject to normal NRC inspection activities. Plants in Column 2, Column 3, or Column 4 are subject
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
to progressively increasing levels of inspection by the NRC with, in general, progressively increasing levels of associated costs. Continued plant operation is not permitted for plants in Column 5. River Bend is currently in Column 1, and Waterford 3 is currently in Column 2.
In September 2022 the NRC placed Waterford 3 in Column 2 based on an error associated with a radiation monitor calibration. Entergy corrected the issue with the radiation monitor in February 2022; however, Waterford 3 is expected to remain in Column 2 until third quarter 2023 based on a subsequent radiation monitor calibration issue.
Environmental Risks
Entergy Louisiana’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Louisiana is in substantial compliance with environmental
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of Entergy Louisiana’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements that could produce estimates that would have a material effect on the presentation of Entergy Louisiana’s financial position or results of operations.
Nuclear Decommissioning Costs
See “Nuclear Decommissioning Costs” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.
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 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.
Utility Regulatory Accounting
See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.
Impairment of Long-lived Assets and Trust Fund Investments
See “Impairment of Long-lived Assets and Trust Fund Investments” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the impairment of long-lived assets and trust fund investments.assets.
Taxation and Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Qualified Pension and Other Postretirement Benefits
Entergy Louisiana’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Cost Sensitivity
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2023 Qualified Pension Cost | | Impact on 2022 Projected Qualified Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $1,554 | | $29,524 |
| Rate of return on plan assets | | (0.25%) | | $2,785 | | $— |
| Rate of increase in compensation | | 0.25% | | $1,276 | | $6,545 |
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2020 Qualified Pension Cost | | Impact on 2019 Projected Qualified Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $3,308 | | $47,877 |
| Rate of return on plan assets | | (0.25%) | | $3,201 | | $— |
| Rate of increase in compensation | | 0.25% | | $2,095 | | $10,727 |
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2023 Postretirement Benefit Cost | | Impact on 2022 Accumulated postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $273 | | $4,653 |
| Health care cost trend | | 0.25% | | $750 | | $3,868 |
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2020 Postretirement Benefit Cost | | Impact on 2019 Accumulated postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $715 | | $7,953 |
| Health care cost trend | | 0.25% | | $989 | | $5,985 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Employer Contributions
Total qualified pension cost for Entergy Louisiana in 20192022 was $48.6 million.$100.6 million, including $58.6 million in settlement costs. Entergy Louisiana anticipates 20202023 qualified pension cost to be $63.4$29.2 million. Entergy Louisiana contributed $65$53.7 million to its qualified pension plans in 20192022 and estimates pension contributions will be approximately $38.8$44.6 million in 2020,2023, although the 20202023 required pension contributions will be known with more certainty when the January 1, 20202023 valuations are completed, which is expected by April 1, 2020.2023.
Total postretirement health care and life insurance benefit costs for Entergy Louisiana in 20192022 were $7.3$6 million. Entergy Louisiana expects 20202023 postretirement health care and life insurance benefit costs of approximately $8.7$1.4 million. Entergy Louisiana contributed $14.3$16.2 million to its other postretirement plans in 20192022 and estimates that 20202023 contributions will be approximately $18.5$15.4 million.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the member and Board of Directors of
Entergy Louisiana, LLC and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy Louisiana, LLC and Subsidiaries (the “Company”) as of December 31, 20192022 and 2018,2021, the related consolidated statements of income, comprehensive income, cash flows, and changes in equity (pages 343370 through 348376 and applicable items in pages 4953 through 236)245), for each of the three years in the period ended December 31, 2019,2022, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20192022 and 2018,2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2022, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Rate and Regulatory Matters —Entergy Louisiana, LLC and Subsidiaries — Refer to Note 2 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Louisiana Public Service Commission (the “LPSC”), which has jurisdiction with respect to the rates of electric companies in Louisiana, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.
The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the LPSC and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the LPSC and the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs, and refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the LPSC and the FERC involved specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and significant auditor judgment to evaluate management estimates and the subjectivity of audit evidence.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the LPSC and the FERC included the following, among others:
•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 Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
• We read relevant regulatory orders issued by the LPSC and the FERC for the Company, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the LPSC’s 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.
• For regulatory matters in process, we inspected the Company’s filings with the LPSC and the FERC, including the annual formula rate plan filing, and considered the filings with the LPSC and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.
• We obtained an analysis from management and support 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 not yet addressed in a regulatory order, to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
Securitization Financing - Storm Cost Recovery Filings with Retail Regulators —Entergy Louisiana, LLC and Subsidiaries — Refer to Note 2 to the financial statements
Critical Audit Matter Description
Hurricane Laura, Hurricane Delta, and Hurricane Zeta in 2020 and Winter Storm Uri and Hurricane Ida in 2021 caused significant damage to portions of the Company’s service area within the state of Louisiana. In March 2022, the LPSC issued a Financing Order authorizing financing of $3.186 billion of system restoration costs utilizing the securitization process authorized by Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021 (“Act 55, as supplemented by Act 293”). In May 2022, the securitization financing closed, resulting in the issuance of $3.194 billion principal amount bonds by Louisiana Local Government Environmental Facilities and Community Development Authority (“LCDA”), a political subdivision of the State of Louisiana. The LCDA loaned the proceeds to the Louisiana Utilities Restoration Corporation (“LURC”), and the
LURC contributed the net bond proceeds to a State legislatively authorized and LURC-sponsored trust, Restoration Law Trust I (the “storm trust”). The Company and the LURC each hold beneficial interests in the storm trust.
The Company does not report the bonds issued by the LCDA on its balance sheet because the bonds are the obligation of the LCDA. The bonds are secured by system restoration property, which is the right granted by law to the LURC to collect a system restoration charge from customers. The Company collects the system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee. The Company does not report the collection of system restoration charges as revenue because the Company is merely acting as a billing and collection agent for the LCDA and the LURC. In the remote possibility that the system restoration charge, as well as any funds in the excess subaccount and funds in the debt service reserve account, are insufficient to service the bonds resulting in a payment default, the storm trust is required to liquidate Entergy Finance Company preferred membership interests in an amount equal to what would be required to cure the default. The estimated value of this indirect guarantee is immaterial. The Company consolidates the storm trust as a variable interest entity and the LURC’s 1% beneficial interest is shown as a noncontrolling interest in the financial statements.
We identified management’s conclusion that the bonds issued by the LCDA are the obligation of the LCDA as a critical audit matter due to the significant judgments made by management to support its conclusion. Auditing management’s judgments involved especially subjective judgment and specialized knowledge of accounting for securitization financing transactions.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the Act 55, as supplemented by Act 293, securitization financing included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the accounting impact of this securitization financing transaction, including the conclusion that the bonds issued by the LCDA are the obligation of the LCDA.
•We evaluated the Company’s disclosures related to the impacts of the Act 55, as supplemented by Act 293, securitization financing, including the balances recorded.
•We read relevant regulatory and financing orders issued by the LPSC for the Company, the LURC, and the LCDA, and evaluated the external information to compare to management’s conclusions.
•We obtained an analysis from management and support from the Company’s internal and external legal counsel regarding the legal status of the bonds issued by the LCDA and the system restoration property granted to the LURC to assess management’s assertion that the bonds issued by the LCDA are the obligation of the LCDA.
•With the assistance of professionals in our firm having expertise and experience in addressing the accounting for securitization financing transactions by regulated utilities, we evaluated the Company’s conclusion, including the conclusion that the bonds issued by the LCDA are the obligation of the LCDA.
Uncertain Tax Positions —Entergy Louisiana, LLC and Subsidiaries — Refer to Note 3 to the financial statements
Critical Audit Matter Description
The Company accounts for uncertain income tax positions under a two-step approach with a more likely-than-not recognition threshold and a measurement approach based on the largest amount of tax benefit that is greater than fifty percent likely of being realized upon settlement. The Company has uncertain tax positions which require management to make significant judgments and assumptions to determine whether available information supports the assertion that the recognition threshold is met, particularly related to the technical merits and facts and circumstances of each position, as well as the probability of different potential outcomes. These uncertain tax positions could be significantly affected by events such as additional transactions contemplated or consummated by the Company as well as audits by taxing authorities of the tax positions. The net unrecognized tax benefit associated with the uncertain tax positions related to the Act 55, as supplemented by Act 293, securitization financing is $586 million at December 31, 2022. The securitization provides for a tax accounting permanent difference resulting in a net reduction of income tax expense in second quarter 2022 of approximately $290 million, after taking into account a provision for uncertain tax positions.
Given the significant judgments made by management, we identified management’s conclusion that these uncertain tax positions met the more-likely-than-not recognition threshold as a critical audit matter. Auditing management’s
judgments regarding these uncertain tax positions involved specialized knowledge of uncertain tax positions and significant auditor judgment to evaluate the subjectivity of audit evidence.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertain tax positions included the following, among others:
•We tested the effectiveness of controls related to uncertain tax positions, including those over the recognition and measurement of the income tax benefits.
•We evaluated the Company’s disclosures, and the balances recorded, related to uncertain tax positions.
•We evaluated the methods and assumptions used by management to estimate the uncertain tax positions by testing the underlying data that served as the basis for the uncertain tax position.
•With the assistance of our income tax specialists, we tested the technical merits of the uncertain tax positions 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.
•Obtaining an opinion from the Company’s external legal counsel regarding certain federal income tax consequences related to the Act 55, as supplemented by Act 293 securitization financing and evaluating whether the analysis was consistent with our interpretation of the relevant laws and circumstances.
•Considering the impact of changes or settlements in the tax environment on management’s methods and assumptions used to estimate the uncertain tax positions.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 21, 202024, 2023
We have served as the Company’s auditor since 2001.
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | |
| | | For the Years Ended December 31, |
| | | 2022 | | 2021 | | 2020 |
| | | (In Thousands) |
| | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | | $6,246,933 | | | $4,994,459 | | | $4,019,063 | |
| Natural gas | | 91,835 | | | 73,989 | | | 50,799 | |
| TOTAL | | 6,338,768 | | | 5,068,448 | | | 4,069,862 | |
| | | | | | |
| OPERATING EXPENSES | | | | | | |
| Operation and Maintenance: | | | | | | |
| Fuel, fuel-related expenses, and gas purchased for resale | | 2,002,456 | | | 1,302,291 | | | 700,152 | |
| Purchased power | | 1,076,715 | | | 768,546 | | | 596,480 | |
| Nuclear refueling outage expenses | | 59,698 | | | 49,373 | | | 55,305 | |
| Other operation and maintenance | | 1,139,605 | | | 1,034,427 | | | 969,630 | |
| Decommissioning | | 72,122 | | | 68,575 | | | 65,225 | |
| Taxes other than income taxes | | 241,908 | | | 224,079 | | | 208,902 | |
| Depreciation and amortization | | 695,204 | | | 656,132 | | | 609,931 | |
| Other regulatory charges (credits) - net | | 148,871 | | | 38,245 | | | (584) | |
| TOTAL | | 5,436,579 | | | 4,141,668 | | | 3,205,041 | |
| | | | | | |
| OPERATING INCOME | | 902,189 | | | 926,780 | | | 864,821 | |
| | | | | | |
| OTHER INCOME | | | | | | |
| Allowance for equity funds used during construction | | 26,252 | | | 28,648 | | | 38,151 | |
| Interest and investment income (loss) | | (69,144) | | | 154,606 | | | 98,033 | |
| Interest and investment income - affiliated | | 185,826 | | | 127,594 | | | 127,594 | |
| Miscellaneous - net | | 9,824 | | | (125,886) | | | (116,366) | |
| TOTAL | | 152,758 | | | 184,962 | | | 147,412 | |
| | | | | | |
| INTEREST EXPENSE | | | | | | |
| Interest expense | | 373,480 | | | 350,227 | | | 331,352 | |
| Allowance for borrowed funds used during construction | | (11,550) | | | (12,878) | | | (19,147) | |
| TOTAL | | 361,930 | | | 337,349 | | | 312,205 | |
| | | | | | |
| INCOME BEFORE INCOME TAXES | | 693,017 | | | 774,393 | | | 700,028 | |
| | | | | | |
| Income taxes | | (162,853) | | | 120,409 | | | (382,324) | |
| | | | | | |
| NET INCOME | | 855,870 | | | 653,984 | | | 1,082,352 | |
| | | | | | |
| Net income attributable to noncontrolling interest | | 1,366 | | | — | | | — | |
| | | | | | |
| EARNINGS APPLICABLE TO MEMBER'S EQUITY | | $854,504 | | | $653,984 | | | $1,082,352 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | | |
| | | For the Years Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | |
| $4,223,027 |
| |
| $4,232,541 |
| |
| $4,246,020 |
|
| Natural gas | | 62,148 |
| | 63,779 |
| | 54,530 |
|
| TOTAL | | 4,285,175 |
| | 4,296,320 |
| | 4,300,550 |
|
| | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 845,108 |
| | 915,410 |
| | 912,060 |
|
| Purchased power | | 810,462 |
| | 960,272 |
| | 980,070 |
|
| Nuclear refueling outage expenses | | 54,170 |
| | 51,626 |
| | 52,074 |
|
| Other operation and maintenance | | 994,637 |
| | 959,185 |
| | 941,604 |
|
| Decommissioning | | 59,346 |
| | 53,736 |
| | 49,457 |
|
| Taxes other than income taxes | | 194,222 |
| | 183,745 |
| | 175,359 |
|
| Depreciation and amortization | | 535,791 |
| | 492,179 |
| | 467,369 |
|
| Other regulatory charges (credits) - net | | (105,203 | ) | | 4,396 |
| | (152,080 | ) |
| TOTAL | | 3,388,533 |
| | 3,620,549 |
| | 3,425,913 |
|
| | | | | | | |
| OPERATING INCOME | | 896,642 |
| | 675,771 |
| | 874,637 |
|
| | | | | | | |
| OTHER INCOME | | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 74,023 |
| | 79,922 |
| | 51,485 |
|
| Interest and investment income | | 231,985 |
| | 141,882 |
| | 164,550 |
|
| Miscellaneous - net | | (115,427 | ) | | (27,530 | ) | | (39,756 | ) |
| TOTAL | | 190,581 |
| | 194,274 |
| | 176,279 |
|
| | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
|
| Interest expense | | 309,493 |
| | 288,658 |
| | 275,185 |
|
| Allowance for borrowed funds used during construction | | (35,430 | ) | | (39,616 | ) | | (25,914 | ) |
| TOTAL | | 274,063 |
| | 249,042 |
| | 249,271 |
|
| | | | | | | |
| INCOME BEFORE INCOME TAXES | | 813,160 |
| | 621,003 |
| | 801,645 |
|
| | | | | | | |
| Income taxes | | 121,623 |
| | (54,611 | ) | | 485,298 |
|
| | | | | | | |
| NET INCOME | |
| $691,537 |
| |
| $675,614 |
| |
| $316,347 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
| | |
| | | For the Years Ended December 31, |
| | | 2022 | | 2021 | | 2020 |
| | | (In Thousands) |
| | | | | | |
| Net Income | | $855,870 | | | $653,984 | | | $1,082,352 | |
| | | | | | |
| Other comprehensive income (loss) | | | | | | |
| Pension and other postretirement liabilities | | | | | | |
| (net of tax expense (benefit) of $17,351, $1,523, and ($83)) | | 47,092 | | | 3,951 | | | (235) | |
| Other comprehensive income (loss) | | 47,092 | | | 3,951 | | | (235) | |
| | | | | | |
| Comprehensive Income | | 902,962 | | | 657,935 | | | 1,082,117 | |
| Net income attributable to noncontrolling interest | | 1,366 | | | — | | | — | |
| Comprehensive Income Applicable to Member's Equity | | $901,596 | | | $657,935 | | | $1,082,117 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
| | | |
| | | For the Years Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| | | (In Thousands) |
| | | | | | | |
| Net Income | |
| $691,537 |
| |
| $675,614 |
| |
| $316,347 |
|
| | | | | | | |
| Other comprehensive income | | |
| | |
| | |
|
| Pension and other postretirement liabilities | | |
| | |
| | |
|
| (net of tax expense of $3,781, $17,743, and $234) | | 10,715 |
| | 50,296 |
| | 2,042 |
|
| Other comprehensive income | | 10,715 |
| | 50,296 |
| | 2,042 |
|
| | | | | | | |
| Comprehensive Income | |
| $702,252 |
| |
| $725,910 |
| |
| $318,389 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
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|
| | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | | |
| | | For the Years Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | |
| Net income | |
| $691,537 |
| |
| $675,614 |
| |
| $316,347 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 685,062 |
| | 662,390 |
| | 621,018 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 196,533 |
| | 174,063 |
| | 575,804 |
|
| Changes in working capital: | | |
| | |
| | |
|
| Receivables | | 13,942 |
| | 89,701 |
| | (53,829 | ) |
| Fuel inventory | | (7,195 | ) | | 5,310 |
| | 11,010 |
|
| Accounts payable | | (33,375 | ) | | 11,372 |
| | 58,880 |
|
| Prepaid taxes and taxes accrued | | (38,827 | ) | | 12,711 |
| | 128,261 |
|
| Interest accrued | | 4,294 |
| | 7,922 |
| | (70 | ) |
| Deferred fuel costs | | 24,234 |
| | (40,036 | ) | | 23,236 |
|
| Other working capital accounts | | (62,536 | ) | | (5,809 | ) | | (30,911 | ) |
| Changes in provisions for estimated losses | | 9,664 |
| | 8,307 |
| | (8,324 | ) |
| Changes in other regulatory assets | | (210,134 | ) | | 40,765 |
| | 492,696 |
|
| Changes in other regulatory liabilities | | (35,881 | ) | | (125,185 | ) | | 605,453 |
|
| Deferred tax rate change recognized as regulatory liability/asset | | — |
| | — |
| | (1,207,808 | ) |
| Changes in pension and other postretirement liabilities | | 35,162 |
| | (106,269 | ) | | (32,309 | ) |
| Other | | (36,478 | ) | | (15,652 | ) | | (161,909 | ) |
| Net cash flow provided by operating activities | | 1,236,002 |
| | 1,395,204 |
| | 1,337,545 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
|
| Construction expenditures | | (1,673,194 | ) | | (1,805,641 | ) | | (1,662,835 | ) |
| Allowance for equity funds used during construction | | 74,023 |
| | 79,922 |
| | 51,485 |
|
| Insurance proceeds | | 7,040 |
| | 3,480 |
| | 5,305 |
|
| Nuclear fuel purchases | | (85,984 | ) | | (111,329 | ) | | (197,829 | ) |
| Proceeds from the sale of nuclear fuel | | 11,596 |
| | 53,603 |
| | 42,634 |
|
| Payments to storm reserve escrow account | | (6,353 | ) | | (4,770 | ) | | (2,110 | ) |
| Receipts from storm reserve escrow account | | — |
| | 4 |
| | 8,835 |
|
| Changes in securitization account | | (32 | ) | | (1,655 | ) | | 880 |
|
| Proceeds from nuclear decommissioning trust fund sales | | 412,559 |
| | 1,055,690 |
| | 231,293 |
|
| Investment in nuclear decommissioning trust funds | | (442,501 | ) | | (1,097,204 | ) | | (266,592 | ) |
| Changes in money pool receivable - net | | 46,843 |
| | (35,672 | ) | | 11,330 |
|
| Proceeds from sale of assets | | — |
| | 11,987 |
| | — |
|
| Payment for purchase of assets | | — |
| | (26,623 | ) | | (9,805 | ) |
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | 2,369 |
| | — |
| | — |
|
| Net cash flow used in investing activities | | (1,653,634 | ) | | (1,878,208 | ) | | (1,787,409 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | 2,691,133 |
| | 2,319,799 |
| | 733,344 |
|
| Retirement of long-term debt | | (2,199,053 | ) | | (1,664,354 | ) | | (407,736 | ) |
| Change in money pool payable - net | | 82,826 |
| | — |
| | — |
|
| Changes in short-term borrowings - net | | — |
| | (43,540 | ) | | 39,746 |
|
| Distributions paid: | | |
| | |
| | |
|
| Common equity | | (208,000 | ) | | (128,000 | ) | | (91,250 | ) |
| Other | | 9,368 |
| | 6,556 |
| | (2,183 | ) |
| Net cash flow provided by financing activities | | 376,274 |
| | 490,461 |
| | 271,921 |
|
| Net increase (decrease) in cash and cash equivalents | | (41,358 | ) | | 7,457 |
| | (177,943 | ) |
| Cash and cash equivalents at beginning of period | | 43,364 |
| | 35,907 |
| | 213,850 |
|
| Cash and cash equivalents at end of period | |
| $2,006 |
| |
| $43,364 |
| |
| $35,907 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | |
| | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $296,842 |
| |
| $272,335 |
| |
| $266,871 |
|
| Income taxes | |
| $15,272 |
| |
| ($105,157 | ) | |
| ($234,199 | ) |
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | |
| | | For the Years Ended December 31, |
| | | 2022 | | 2021 | | 2020 |
| | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | |
| Net income | | $855,870 | | | $653,984 | | | $1,082,352 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 852,521 | | | 818,389 | | | 783,616 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | (70,379) | | | 175,700 | | | (356,256) | |
| Changes in working capital: | | | | | | |
| Receivables | | (53,434) | | | (58,466) | | | (79,451) | |
| Fuel inventory | | 1,099 | | | 7,722 | | | (9,067) | |
| Accounts payable | | (207,949) | | | 358,536 | | | 160,659 | |
| Taxes accrued | | (28,244) | | | 21,631 | | | 50,576 | |
| Interest accrued | | 8,284 | | | 803 | | | 4,505 | |
| Deferred fuel costs | | (113,809) | | | (43,124) | | | (57,895) | |
| Other working capital accounts | | (103,571) | | | (45,517) | | | (76,284) | |
| Changes in provisions for estimated losses | | 291,824 | | | (449) | | | (295,480) | |
| Changes in other regulatory assets | | 720,487 | | | (1,050,600) | | | (410,855) | |
| Changes in other regulatory liabilities | | (4,783) | | | (16,478) | | | 71,698 | |
| Effect of securitization on regulatory asset | | (1,190,338) | | | — | | | — | |
| | | | | | |
| Changes in pension and other postretirement liabilities | | (139,067) | | | (164,263) | | | 12,199 | |
| Other | | 358,997 | | | 394,658 | | | 192,669 | |
| Net cash flow provided by operating activities | | 1,177,508 | | | 1,052,526 | | | 1,072,986 | |
| INVESTING ACTIVITIES | | | | | | |
| Construction expenditures | | (2,568,113) | | | (3,621,775) | | | (1,960,787) | |
| Allowance for equity funds used during construction | | 26,252 | | | 28,648 | | | 38,151 | |
| Nuclear fuel purchases | | (122,020) | | | (85,419) | | | (92,831) | |
| Proceeds from the sale of nuclear fuel | | 37,648 | | | 13,254 | | | 44,511 | |
| | | | | | |
| | | | | | |
| Payments to storm reserve escrow account | | (1,293,633) | | | — | | | (1,488) | |
| Receipts from storm reserve escrow account | | 1,000,228 | | | — | | | 297,363 | |
| Purchase of preferred membership interests of affiliate | | (3,163,572) | | | — | | | — | |
| Redemption of preferred membership interests of affiliate | | 1,390,587 | | | — | | | — | |
| Changes in securitization account | | — | | | 2,700 | | | 951 | |
| Proceeds from nuclear decommissioning trust fund sales | | 633,100 | | | 944,703 | | | 347,021 | |
| Investment in nuclear decommissioning trust funds | | (667,947) | | | (1,004,888) | | | (372,227) | |
| Changes in money pool receivable - net | | 14,539 | | | (1,113) | | | (13,426) | |
| Proceeds from sale of assets | | 5,000 | | | 15,000 | | | — | |
| Payment for purchase of assets | | — | | | — | | | (236,999) | |
| Increase in other investments | | (5,475) | | | — | | | — | |
| Litigation proceeds from settlement agreement | | 5,695 | | | — | | | — | |
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | — | | | 8,691 | | | 5,090 | |
| Net cash flow used in investing activities | | (4,707,711) | | | (3,700,199) | | | (1,944,671) | |
| FINANCING ACTIVITIES | | | | | | |
| Proceeds from the issuance of long-term debt | | 2,942,771 | | | 3,769,166 | | | 3,675,083 | |
| | | | | | |
| Retirement of long-term debt | | (3,167,832) | | | (1,895,091) | | | (1,962,635) | |
| Proceeds from trust related to securitization | | 3,163,572 | | | — | | | — | |
| Capital contribution from parent | | 1,000,000 | | | 125,000 | | | — | |
| | | | | | |
| | | | | | |
| Changes in money pool payable - net | | 226,114 | | | — | | | (82,826) | |
| | | | | | |
| | | | | | |
| Common equity distributions paid | | (624,000) | | | (60,000) | | | (21,500) | |
| | | | | | |
| Other | | 27,618 | | | (849) | | | (10,423) | |
| Net cash flow provided by financing activities | | 3,568,243 | | | 1,938,226 | | | 1,597,699 | |
| Net increase (decrease) in cash and cash equivalents | | 38,040 | | | (709,447) | | | 726,014 | |
| Cash and cash equivalents at beginning of period | | 18,573 | | | 728,020 | | | 2,006 | |
| Cash and cash equivalents at end of period | | $56,613 | | | $18,573 | | | $728,020 | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | |
| Cash paid (received) during the period for: | | | | | | |
| Interest - net of amount capitalized | | $353,697 | | | $337,926 | | | $318,352 | |
| Income taxes | | ($82,463) | | | ($18,453) | | | ($14,714) | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | | |
| | | December 31, |
| | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | |
| $488 |
| |
| $252 |
|
| Temporary cash investments | | 1,518 |
| | 43,112 |
|
| Total cash and cash equivalents | | 2,006 |
| | 43,364 |
|
| Accounts receivable: | | |
| | |
|
| Customer | | 194,869 |
| | 199,903 |
|
| Allowance for doubtful accounts | | (1,902 | ) | | (1,813 | ) |
| Associated companies | | 77,212 |
| | 123,363 |
|
| Other | | 42,179 |
| | 60,879 |
|
| Accrued unbilled revenues | | 169,201 |
| | 167,052 |
|
| Total accounts receivable | | 481,559 |
| | 549,384 |
|
| Fuel inventory | | 41,613 |
| | 34,418 |
|
| Materials and supplies - at average cost | | 354,020 |
| | 324,627 |
|
| Deferred nuclear refueling outage costs | | 56,743 |
| | 24,406 |
|
| Prepaid taxes | | 7,959 |
| | — |
|
| Prepayments and other | | 37,837 |
| | 38,715 |
|
| TOTAL | | 981,737 |
| | 1,014,914 |
|
| | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
|
| Investment in affiliate preferred membership interests | | 1,390,587 |
| | 1,390,587 |
|
| Decommissioning trust funds | | 1,563,812 |
| | 1,284,996 |
|
| Storm reserve escrow account | | 295,875 |
| | 289,525 |
|
| Non-utility property - at cost (less accumulated depreciation) | | 312,896 |
| | 286,555 |
|
| Other | | 13,476 |
| | 14,927 |
|
| TOTAL | | 3,576,646 |
| | 3,266,590 |
|
| | | | | |
| UTILITY PLANT | | |
| | |
|
| Electric | | 22,620,365 |
| | 20,532,312 |
|
| Natural gas | | 235,678 |
| | 211,421 |
|
| Construction work in progress | | 1,383,603 |
| | 1,864,582 |
|
| Nuclear fuel | | 267,779 |
| | 298,022 |
|
| TOTAL UTILITY PLANT | | 24,507,425 |
| | 22,906,337 |
|
| Less - accumulated depreciation and amortization | | 9,118,524 |
| | 8,837,596 |
|
| UTILITY PLANT - NET | | 15,388,901 |
| | 14,068,741 |
|
| | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
|
| Regulatory assets: | | |
| | |
|
| Other regulatory assets (includes securitization property of $27,596 as of December 31, 2019 and $49,753 as of December 31, 2018) | | 1,315,211 |
| | 1,105,077 |
|
| Deferred fuel costs | | 168,122 |
| | 168,122 |
|
| Other | | 33,491 |
| | 28,371 |
|
| TOTAL | | 1,516,824 |
| | 1,301,570 |
|
| | | | | |
| TOTAL ASSETS | |
| $21,464,108 |
| |
| $19,651,815 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
| | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | |
| | | December 31, |
| | | 2022 | | 2021 |
| | | (In Thousands) |
| | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | | $50,318 | | | $195 | |
| Temporary cash investments | | 6,295 | | | 18,378 | |
| Total cash and cash equivalents | | 56,613 | | | 18,573 | |
| | | | |
| Accounts receivable: | | | | |
| Customer | | 339,291 | | | 355,265 | |
| Allowance for doubtful accounts | | (7,595) | | | (29,231) | |
| Associated companies | | 88,896 | | | 96,539 | |
| Other | | 53,241 | | | 36,674 | |
| Accrued unbilled revenues | | 199,077 | | | 174,768 | |
| Total accounts receivable | | 672,910 | | | 634,015 | |
| | | | |
| Deferred fuel costs | | 159,183 | | | 45,374 | |
| Fuel inventory | | 41,859 | | | 42,958 | |
| Materials and supplies - at average cost | | 555,860 | | | 485,325 | |
| Deferred nuclear refueling outage costs | | 53,833 | | | 39,582 | |
| | | | |
| | | | |
| Prepayments and other | | 76,646 | | | 44,187 | |
| TOTAL | | 1,616,904 | | | 1,310,014 | |
| | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | |
| Investment in affiliate preferred membership interests | | 3,163,572 | | | 1,390,587 | |
| Decommissioning trust funds | | 1,779,090 | | | 2,114,523 | |
| Storm reserve escrow account | | 293,406 | | | — | |
| Non-utility property - at cost (less accumulated depreciation) | | 350,723 | | | 337,247 | |
| Other | | 19,679 | | | 13,744 | |
| TOTAL | | 5,606,470 | | | 3,856,101 | |
| | | | |
| UTILITY PLANT | | | | |
| Electric | | 27,498,136 | | | 28,055,038 | |
| Natural gas | | 301,719 | | | 285,006 | |
| | | | |
| Construction work in progress | | 736,969 | | | 847,924 | |
| Nuclear fuel | | 212,941 | | | 209,418 | |
| TOTAL UTILITY PLANT | | 28,749,765 | | | 29,397,386 | |
| Less - accumulated depreciation and amortization | | 10,087,942 | | | 9,860,252 | |
| UTILITY PLANT - NET | | 18,661,823 | | | 19,537,134 | |
| | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | |
| Regulatory assets: | | | | |
| | | | |
| Other regulatory assets | | 2,056,179 | | | 2,776,666 | |
| Deferred fuel costs | | 168,122 | | | 168,122 | |
| Other | | 35,057 | | | 27,801 | |
| TOTAL | | 2,259,358 | | | 2,972,589 | |
| | | | |
| TOTAL ASSETS | | $28,144,555 | | | $27,675,838 | |
| | | | |
| See Notes to Financial Statements. | | | | |
| | | ENTERGY LOUISIANA, LLC AND SUBSIDIARIES | ENTERGY LOUISIANA, LLC AND SUBSIDIARIES | ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS | CONSOLIDATED BALANCE SHEETS | CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY | LIABILITIES AND EQUITY | LIABILITIES AND EQUITY |
| | | | | |
| | | December 31, | | | December 31, |
| | | 2019 | | 2018 | | | 2022 | | 2021 |
| | | (In Thousands) | | | (In Thousands) |
| | | | | | |
| CURRENT LIABILITIES | | | | | CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | |
| $320,002 |
| |
| $2 |
| Currently maturing long-term debt | | $1,010,000 | | | $200,000 | |
| | Accounts payable: | | |
| | |
| Accounts payable: | | | | |
| Associated companies | | 187,615 |
| | 102,749 |
| Associated companies | | 356,688 | | | 183,172 | |
| Other | | 357,206 |
| | 390,367 |
| Other | | 589,355 | | | 1,481,902 | |
| Customer deposits | | 153,097 |
| | 155,314 |
| Customer deposits | | 161,666 | | | 150,697 | |
| Taxes accrued | | — |
| | 30,868 |
| Taxes accrued | | 36,004 | | | 64,248 | |
| | Interest accrued | | 87,744 |
| | 83,450 |
| Interest accrued | | 101,336 | | | 93,052 | |
| Deferred fuel costs | | 55,645 |
| | 31,411 |
| |
| | Current portion of unprotected excess accumulated deferred income taxes | | 31,138 |
| | 31,457 |
| Current portion of unprotected excess accumulated deferred income taxes | | — | | | 24,291 | |
| Other | | 64,668 |
| | 49,202 |
| Other | | 72,525 | | | 68,995 | |
| TOTAL | | 1,257,115 |
| | 874,820 |
| TOTAL | | 2,327,574 | | | 2,266,357 | |
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
| NON-CURRENT LIABILITIES | | | | |
| Accumulated deferred income taxes and taxes accrued | | 2,464,513 |
| | 2,226,721 |
| Accumulated deferred income taxes and taxes accrued | | 2,374,878 | | | 2,433,854 | |
| Accumulated deferred investment tax credits | | 112,128 |
| | 116,999 |
| Accumulated deferred investment tax credits | | 97,868 | | | 102,588 | |
| Regulatory liability for income taxes - net | | 500,083 |
| | 581,001 |
| Regulatory liability for income taxes - net | | 337,836 | | | 313,693 | |
| Other regulatory liabilities | | 794,140 |
| | 748,784 |
| Other regulatory liabilities | | 1,037,962 | | | 1,042,597 | |
| Decommissioning | | 1,497,349 |
| | 1,280,272 |
| Decommissioning | | 1,736,801 | | | 1,653,198 | |
| Accumulated provisions | | 320,419 |
| | 310,755 |
| Accumulated provisions | | 316,314 | | | 24,490 | |
| Pension and other postretirement liabilities | | 677,619 |
| | 643,171 |
| Pension and other postretirement liabilities | | 389,631 | | | 528,213 | |
| Long-term debt (includes securitization bonds of $33,220 as of December 31, 2019 and $55,682 as of December 31, 2018) | | 6,983,667 |
| | 6,805,766 |
| |
| Long-term debt | | Long-term debt | | 9,688,922 | | | 10,714,346 | |
| | Other | | 459,957 |
| | 160,608 |
| Other | | 343,321 | | | 415,930 | |
| TOTAL | | 13,809,875 |
| | 12,874,077 |
| TOTAL | | 16,323,533 | | | 17,228,909 | |
| | | | | | | | | |
| Commitments and Contingencies | |
|
| |
|
| Commitments and Contingencies | |
| | | | | | |
| EQUITY | | |
| | |
| EQUITY | | | | |
| Member’s equity | | 6,392,556 |
| | 5,909,071 |
| |
| Accumulated other comprehensive income (loss) | | 4,562 |
| | (6,153 | ) | |
| Member’s equity | | Member’s equity | | 9,406,343 | | | 8,172,294 | |
| Accumulated other comprehensive income | | Accumulated other comprehensive income | | 55,370 | | | 8,278 | |
| Noncontrolling interest | | Noncontrolling interest | | 31,735 | | | — | |
| TOTAL | | 6,397,118 |
| | 5,902,918 |
| TOTAL | | 9,493,448 | | | 8,180,572 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $21,464,108 |
| |
| $19,651,815 |
| TOTAL LIABILITIES AND EQUITY | | $28,144,555 | | | $27,675,838 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| See Notes to Financial Statements. | | | | |
|
| | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| For the Years Ended December 31, 2019, 2018, and 2017 |
| | | | | |
| | | Common Equity | | |
| | | Member’s Equity | | Accumulated Other Comprehensive Income (Loss) | | Total |
| | (In Thousands) |
| | | | | | | |
| Balance at December 31, 2016 | |
| $5,130,251 |
| |
| ($48,442 | ) | |
| $5,081,809 |
|
| Net income | | 316,347 |
| | — |
| | 316,347 |
|
| Other comprehensive income | | — |
| | 2,042 |
| | 2,042 |
|
| Distributions declared on common equity | | (91,250 | ) | | — |
| | (91,250 | ) |
| Other | | (144 | ) | | — |
| | (144 | ) |
| Balance at December 31, 2017 | |
| $5,355,204 |
| |
| ($46,400 | ) | |
| $5,308,804 |
|
| Net income | | 675,614 |
| | — |
| | 675,614 |
|
| Other comprehensive income | | — |
| | 50,296 |
| | 50,296 |
|
| Distributions declared on common equity | | (128,000 | ) | | — |
| | (128,000 | ) |
| Reclassification pursuant to ASU 2018-02 | | 6,262 |
| | (10,049 | ) | | (3,787 | ) |
| Other | | (9 | ) | | — |
| | (9 | ) |
| Balance at December 31, 2018 | |
| $5,909,071 |
| |
| ($6,153 | ) | |
| $5,902,918 |
|
| Net income | | 691,537 |
| | — |
| | 691,537 |
|
| Other comprehensive income | | — |
| | 10,715 |
| | 10,715 |
|
| Distributions declared on common equity | | (208,000 | ) | | — |
| | (208,000 | ) |
| Other | | (52 | ) | | — |
| | (52 | ) |
| Balance at December 31, 2019 | |
| $6,392,556 |
| |
| $4,562 |
| |
| $6,397,118 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| For the Years Ended December 31, 2022, 2021, and 2020 |
| | | | | |
| | Noncontrolling Interest | | Member’s Equity | | Accumulated Other Comprehensive Income | | Total |
| | (In Thousands) |
| | | | | | | |
| Balance at December 31, 2019 | $— | | | $6,392,556 | | | $4,562 | | | $6,397,118 | |
| Net income | — | | | 1,082,352 | | | — | | | 1,082,352 | |
| | | | | | | |
| Other comprehensive loss | — | | | — | | | (235) | | | (235) | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Common equity distributions | — | | | (21,500) | | | — | | | (21,500) | |
| | | | | | | |
| | | | | | | |
| Other | — | | | (47) | | | — | | | (47) | |
| Balance at December 31, 2020 | $— | | | $7,453,361 | | | $4,327 | | | $7,457,688 | |
| Net income | — | | | 653,984 | | | — | | | 653,984 | |
| | | | | | | |
| Other comprehensive income | — | | | — | | | 3,951 | | | 3,951 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Common equity distributions | — | | | (60,000) | | | — | | | (60,000) | |
| | | | | | | |
| | | | | | | |
| Other | — | | | (51) | | | — | | | (51) | |
| Balance at December 31, 2021 | $— | | | $8,172,294 | | | $8,278 | | | $8,180,572 | |
| Net income | 1,366 | | | 854,504 | | | — | | | 855,870 | |
| Other comprehensive income | — | | | — | | | 47,092 | | | 47,092 | |
| Beneficial interest in storm trust | 31,636 | | | — | | | — | | | 31,636 | |
| Non-cash contribution from parent | — | | | 3,597 | | | — | | | 3,597 | |
| Capital contribution from parent | — | | | 1,000,000 | | | — | | | 1,000,000 | |
| Common equity distributions | — | | | (624,000) | | | — | | | (624,000) | |
| Distribution to LURC | (1,267) | | | — | | | — | | | (1,267) | |
| | | | | | | |
| | | | | | | |
| Other | — | | | (52) | | | — | | | (52) | |
| Balance at December 31, 2022 | $31,735 | | | $9,406,343 | | | $55,370 | | | $9,493,448 | |
| | | | | | | |
| See Notes to Financial Statements. | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | |
| | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| | (In Thousands) |
| | | | | | | | | | |
| Operating revenues |
| $4,285,175 |
| |
| $4,296,320 |
| |
| $4,300,550 |
| |
| $4,177,048 |
| |
| $4,417,146 |
|
| Net income |
| $691,537 |
| |
| $675,614 |
| |
| $316,347 |
| |
| $622,047 |
| |
| $446,639 |
|
| Total assets |
| $21,464,108 |
| |
| $19,651,815 |
| |
| $18,448,864 |
| |
| $17,701,271 |
| |
| $16,387,447 |
|
| Long-term obligations (a) |
| $6,983,667 |
| |
| $6,805,766 |
| |
| $5,469,069 |
| |
| $5,612,593 |
| |
| $4,806,790 |
|
| | | | | | | | | | |
| (a) Includes long-term debt (excluding currently maturing debt). | | | | |
| | | | | | | | | | |
| | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| | (Dollars In Millions) |
| | | | | | | | | | |
| Electric Operating Revenues: | |
| | |
| | |
| | |
| | |
|
| Residential |
| $1,271 |
| |
| $1,244 |
| |
| $1,198 |
| |
| $1,196 |
| |
| $1,292 |
|
| Commercial | 947 |
| | 941 |
| | 956 |
| | 930 |
| | 989 |
|
| Industrial | 1,451 |
| | 1,462 |
| | 1,534 |
| | 1,350 |
| | 1,420 |
|
| Governmental | 71 |
| | 69 |
| | 69 |
| | 67 |
| | 67 |
|
| Total billed retail | 3,740 |
| | 3,716 |
| | 3,757 |
| | 3,543 |
| | 3,768 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | 273 |
| | 295 |
| | 278 |
| | 368 |
| | 406 |
|
| Non-associated companies | 60 |
| | 62 |
| | 64 |
| | 50 |
| | 36 |
|
| Other | 150 |
| | 160 |
| | 147 |
| | 165 |
| | 152 |
|
| Total |
| $4,223 |
| |
| $4,233 |
| |
| $4,246 |
| |
| $4,126 |
| |
| $4,362 |
|
| | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | |
| | |
| | |
| | |
| | |
|
| Residential | 14,046 |
| | 14,494 |
| | 13,357 |
| | 13,810 |
| | 14,399 |
|
| Commercial | 11,353 |
| | 11,578 |
| | 11,342 |
| | 11,478 |
| | 11,700 |
|
| Industrial | 29,801 |
| | 29,255 |
| | 29,754 |
| | 28,517 |
| | 27,713 |
|
| Governmental | 827 |
| | 823 |
| | 790 |
| | 794 |
| | 756 |
|
| Total retail | 56,027 |
| | 56,150 |
| | 55,243 |
| | 54,599 |
| | 54,568 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | 4,813 |
| | 5,498 |
| | 4,793 |
| | 7,345 |
| | 7,500 |
|
| Non-associated companies | 1,924 |
| | 1,762 |
| | 1,711 |
| | 1,690 |
| | 770 |
|
| Total | 62,764 |
| | 63,410 |
| | 61,747 |
| | 63,634 |
| | 62,838 |
|
| | | | | | | | | | |
ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
20192022 Compared to 20182021
Net IncomeEarnings Applicable to Member’s Equity
Net income decreased $6.2Earnings increased $30.8 million primarily due to higher retail electric price and higher volume/weather, partially offset by higher depreciation and amortization expenses, lower volume/weather,higher other operation and amaintenance expenses, and higher effective income tax rate, partially offset by higher retail electric price.interest expense.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 20192022 to 2018.
|
| | | | |
| Amount |
| (In Millions) |
20182021 operating revenues |
| $1,335.1 |
|
| Fuel, rider, and other revenues that do not significantly affect net income | (51.6172.2 | ) |
Volume/weather | (15.9 | ) |
Return of unprotected excess accumulated deferred income taxes to customers | 25.8 |
|
| Retail electric price | 29.656.8 |
|
2019Volume/weather | 25.6 | |
| Retail one-time bill credit | (36.7) | |
| 2022 operating revenues |
| $1,323.0 |
|
Entergy Mississippi’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.
The retail electric price variance is primarily due to increases in formula rate plan rates effective April 2021, July 2021, April 2022, and August 2022. See Note 2 to the financial statements for further discussion of the formula rate plan filings.
The volume/weather variance is primarily due to a decrease of 455 GWh, or 3%, in billed electricity usage, including the effect of lessmore favorable weather on residential sales and a decreasean increase in industrialcommercial usage. The decreaseincrease in industrialcommercial usage iswas primarily due to decreased small industrial sales.the effect of the COVID-19 pandemic on businesses in 2021.
The returnretail one-time bill credit represents the disbursement of unprotected excess accumulated deferred income taxessettlement proceeds in the form of a one-time bill credit provided to retail customers is due toduring the return of unprotected excess accumulated deferred income taxes through customer bill credits overSeptember 2022 billing cycle as a three-month period from July 2018 through September 2018 per an agreement approved by the MPSC in June 2018 resulting from the stipulation related to the effectsresult of the Tax Cuts and Jobs Act.System Energy settlement agreement with the MPSC. There wasis no effect on net income as the reduction in operating revenues was offset by a reduction in income tax expense.credit to fuel and purchased power expenses. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act.
The retail electric price variance is primarily due to an increase in formula rate plan rates 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 associated with the acquisition of the Choctaw Generating Station, each as approved by the MPSC. Entergy Mississippi began billing the interim capacity rate adjustment in January 2020. See Note 2 to the financial statements for further discussion of the formula rate plan filingsettlement agreement and the interim capacity rate adjustment.MPSC directive related to the disbursement of settlement proceeds.
Entergy Mississippi, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Total electric energy sales for Entergy Mississippi for the years ended December 31, 2022 and 2021 are as follows:
| | | | | | | | | | | | | | | | | |
| 2022 | | 2021 | | % Change |
| (GWh) | | |
| Residential | 5,679 | | | 5,494 | | | 3 | |
| Commercial | 4,586 | | | 4,455 | | | 3 | |
| Industrial | 2,359 | | | 2,287 | | | 3 | |
| Governmental | 414 | | | 409 | | | 1 | |
| Total retail | 13,038 | | | 12,645 | | | 3 | |
| Sales for resale: | | | | | |
| Non-associated companies | 2,914 | | | 4,364 | | | (33) | |
| Total | 15,952 | | | 17,009 | | | (6) | |
See Note 19 to the financial statements for additional discussion of Entergy Mississippi’s operating revenues.
Other Income Statement Variances
Other operation and maintenance expenses increased primarily due to:
| |
• | an increase of $4.7 million in spending on initiatives to explore new customer products and services; and
|
an increase of $4.6$4.7 million in information technology costspower delivery expenses primarily due to higher vegetation maintenance costs, related to applicationshigher safety and infrastructure support, enhanced cyber security,training costs, and upgrades and maintenance.
The increase washigher reliability costs, partially offset by a $5.8 million lossdecrease in 2018 on the sale of fuel oil inventory per an agreement approved by the MPSC in June 2018 resulting from the stipulation related to the effects of the Tax Act. There is no effect on net income as the loss on the sale of fuel oil inventory is offset by a reduction in income tax expense.
Depreciation and amortizationmeter reading expenses increased primarily as a result of higher depreciation rates, as approved by the MPSC, and additions to plantdeployment of advanced metering systems;
•$3.3 million in service.
Other regulatory charges include a regulatory charge recorded in second quarter 2018 to reflectamortization of the return of unprotected excess accumulated deferred income taxes per an agreement approved bybad debt expense deferral resulting from the MPSC in June 2018 that resulted in a reduction in net utility plant of $127.2 million. There was no effect on net income as the regulatory charge was offset by a reduction in income tax expense.COVID-19 pandemic. See Note 2 to the financial statements for further discussion of regulatory activity relatedassociated with the COVID-19 pandemic;
•an increase of $2.7 million in energy efficiency expenses primarily due to higher energy efficiency costs;
•an increase of $2.3 million in customer service center support costs primarily due to higher contract costs; and
•several individually insignificant items.
The increase was partially offset by a decrease of $2.2 million as a result of the amount of transmission costs allocated by MISO.
Taxes other than income taxes increased primarily due to increases in ad valorem taxes resulting from higher assessments and millage rate increases.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Other regulatory charges (credits) - net includes:
•regulatory credits of $22.6 million, recorded in third quarter 2022, to reflect the effects of the joint stipulation reached in the 2022 formula rate plan filing proceeding and regulatory credits of $18.2 million, recorded in the fourth quarter 2022, to reflect that the 2022 estimated earned return was below the formula bandwidth. See Note 2 to the Tax Cutsfinancial statements for discussion of the formula rate plan filings; and Jobs Act.
•regulatory credits of $19.9 million, recorded in the second quarter 2021, to reflect the effects of the joint stipulation reached in the 2021 formula rate plan filing proceeding and regulatory credits of $19 million, recorded in the fourth quarter 2021, to reflect that the 2021 earned return was below the formula bandwidth. See Note 2 to the financial statements for discussion of the formula rate plan filings.
Entergy Mississippi, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Interest expense increased primarily due to issuances of $300 million in June 2019 and $135 million in November 2019, of 3.85% Series mortgage bonds and to:
•the issuance of $55$200 million of 4.52%2.55% Series mortgage bonds in December 2018, partially offset by November 2021;
•the repayment, at maturity, of $150 million unsecured term loan drawn in June 2022;
•borrowings of 6.64%$100 million in 2022 on Entergy Mississippi’s credit facility, which were repaid in 2022; and
•the issuance of $200 million of 3.50% Series mortgage bonds in July 2019.March 2021.
Net loss attributable to noncontrolling interest reflects the earnings or losses attributable to the noncontrolling interest partner of the tax equity partnership for the Sunflower Solar facility under HLBV accounting. Entergy Mississippi recorded regulatory charges of $21.4 million in 2022 to defer the difference between the losses allocated to the tax equity partner under the HLBV method of accounting and the earnings/loss that would have been allocated to the tax equity partner under its respective ownership percentage in the partnership. See Note 51 to the financial statements for details on long-term debt.discussion of the HLBV method of accounting.
The effective income tax rates were 20.5%23.7% for 20192022 and (41,237%)21.4% for 2018. The difference in the effective income tax rate of (41,237%) versus the federal statutory rate of 21% for 2018 was primarily due to the flow through of excess accumulated deferred income taxes.2021. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates.rates, and for additional discussion regarding income taxes.
20182021 Compared to 20172020
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy Mississippi’s Annual Report on Form 10-K for the year ended December 31, 20182021, filed with the SEC on February 25, 2022, for discussion of results of operations for 20182021 compared to 2017.2020.
Income Tax Legislation
See the “Income Tax Legislation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the Tax Cuts and JobsInflation Reduction Act the federal income tax legislation enacted in December 2017. Note 3 to the financial statements contains additional discussion of the effect of the Act on 2017, 2018, and 2019 results of operations and financial position, the provisions of the Act, and the uncertainties associated with accounting for the Act, and Note 2 to the financial statements discusses the regulatory proceedings that have considered the effects of the Act.2022.
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2019, 2018,2022, 2021, and 20172020 were as follows:
| | | | | | | | | | | | | | | | | |
| | 2022 | | 2021 | | 2020 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period | $47,627 | | | $18 | | | $51,601 | |
| | | | | |
| Net cash provided by (used in): | | | | | |
| Operating activities | 405,649 | | | 350,960 | | | 300,314 | |
| Investing activities | (620,740) | | | (686,654) | | | (530,762) | |
| Financing activities | 184,443 | | | 383,303 | | | 178,865 | |
| Net increase (decrease) in cash and cash equivalents | (30,648) | | | 47,609 | | | (51,583) | |
| | | | | |
| Cash and cash equivalents at end of period | $16,979 | | | $47,627 | | | $18 | |
Entergy Mississippi, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
|
| | | | | | | | | | | |
| | 2019 | | 2018 | | 2017 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $36,954 |
| |
| $6,096 |
| |
| $76,834 |
|
| | | | | | |
| Net cash provided by (used in): | |
| | |
| | |
|
| Operating activities | 339,952 |
| | 418,382 |
| | 226,585 |
|
| Investing activities | (733,684 | ) | | (419,453 | ) | | (417,226 | ) |
| Financing activities | 408,379 |
| | 31,929 |
| | 119,903 |
|
| Net increase (decrease) in cash and cash equivalents | 14,647 |
| | 30,858 |
| | (70,738 | ) |
| | | | | | |
| Cash and cash equivalents at end of period |
| $51,601 |
| |
| $36,954 |
| |
| $6,096 |
|
20192022 Compared to 20182021
Operating Activities
Net cash flow provided by operating activities decreased $78.4increased $54.7 million in 20192022 primarily due to:
the timing of collection of receivables from customers;
•the receipt of $36.2$235 million from Entergy Arkansas as a resultin settlement proceeds, of a compliance filing made in responsewhich $198.3 million was applied to the FERC’s October 2018 order in the Entergy Arkansas opportunity sales proceeding.under-recovered deferred fuel balance. See Note 2 to the financial statements for furthera discussion of fuel and purchased power cost recovery and the opportunity sales proceeding;System Energy settlement agreement with the MPSC;
•higher collections from customers; and
$26.2•a decrease of $23.6 million in proceeds fromstorm spending in 2022, primarily due to Winter Storm Uri restoration efforts in 2021.
The increase was partially offset by:
•increased fuel costs. See Note 2 to the salefinancial statements for a discussion of fuel oil inventoryand purchased power cost recovery;
•payments to vendors, including timing and an increase in 2018.cost of operations;
•an increase of $19.6 million in pension contributions in 2022. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding; and
•a decrease of $14.3 million in income tax refunds in 2022. Entergy Mississippi received income tax refunds in 2022 and 2021, each in accordance with an intercompany income tax allocation agreement.
Investing Activities
Net cash flow used in investing activities decreased $65.9 million in 2022 primarily due to:
•a decrease of $94.7 million in distribution construction expenditures primarily due to lower capital expenditures for storm restoration in 2022 and lower spending in 2022 on advanced metering infrastructure;
•money pool activity; and
•a decrease of $26.9 million in transmission construction expenditures primarily due to a lower scope of work performed in 2022 as compared to 2021.
The decrease was partially offset by the timinginitial payment of recovery of fuel and purchased power costs and the return of unprotected excess accumulated deferred income taxes to customers in 2018. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act.
Investing Activities
Net cash flow used in investing activities increased $314.2approximately $105.1 million in 2019 primarily due to:
May 2022 for the purchase of the Choctaw Generating Station in October 2019 for approximately $305 million.Sunflower Solar facility by a consolidated tax equity partnership. See Note 14 to the financial statements for further discussion of the Choctaw Generating Station purchase;Sunflower Solar facility 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.
The increase was partially offset by money pool activity.
IncreasesDecreases in Entergy Mississippi’s receivable from the money pool are a usesource of cash flow, and Entergy Mississippi’s receivable from the money pool increased by $3.3decreased $13.6 million in 20192022 compared to increasing by $39.7$40.5 million in 2018.2021. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
Financing Activities
Net cash flow provided by financing activities increased $376.5decreased $198.9 million in 20192022 primarily due to:
to the issuance of $435$200 million of 3.85%3.50% Series mortgage bonds in 2019 compared toMarch 2021 and the issuance of $55$200 million of 4.52%2.55% Series first mortgage bonds 2018;in November 2021.
The decrease was partially offset by:
•proceeds received in June 2022 from a $150 million unsecured term loan due December 2023;
Entergy Mississippi, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
•a capital contribution of $130$9.6 million received in October 2019May 2022 from the noncontrolling tax equity investor in anticipationMS Sunflower Partnership, LLC and used by the partnership for initial payment in the acquisition 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.Sunflower Solar facility. See Note 214 to the financial statements for further discussion of the internal restructuring andSunflower Solar facility purchase;
•a capital contribution of $15.1 million received in December 2022 from the noncontrolling tax equity investor in MS Sunflower Partnership, LLC which will be used by the partnership for final payment in the acquisition of the Sunflower Solar facility in 2023. See Note 614 to the financial statements for detailsdiscussion of preferred stockthe Sunflower Solar facility purchase; and
•money pool activity.
The increase was partially offset byDecreases in Entergy Mississippi’s payable to the repayment, at maturity,money pool are a use of $150cash flow, and Entergy Mississippi’s payable to the money pool decreased $16.5 million of 6.64% Series mortgage bonds in July 2019.2021.
See Note 5 to the financial statements for details on long-term debt.
20182021 Compared to 2017
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Mississippi’s Annual Report on Form 10-K for the year ended December 31, 20182021, filed with the SEC on February 25, 2022, for discussion of operating, investing, and financing cash flow activities for 20182021 compared to 2017.2020.
Capital Structure
Entergy Mississippi’s debt to capital ratio is shown in the following table.
| | | | | | | | | | | |
| | December 31,
2022 | | December 31,
2021 |
| Debt to capital | 53.4 | % | | 54.3 | % |
| Effect of subtracting cash | (0.2 | %) | | (0.5 | %) |
| Net debt to net capital (non-GAAP) | 53.2 | % | | 53.8 | % |
|
| | | | | |
| | December 31,
2019 | | December 31,
2018 |
| Debt to capital | 51.2 | % | | 50.6 | % |
| Effect of subtracting cash | (0.8 | %) | | (0.7 | %) |
| Net debt to net capital | 50.4 | % | | 49.9 | % |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. Entergy Mississippi uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Mississippi’s financial condition. The net debt to net capital ratio is a non-GAAP measure. Entergy Mississippi uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Mississippi’s financial condition because net debt indicates Entergy Mississippi’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Mississippi seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a distribution, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Mississippi may issue incremental debt or reduce distributions, to the extent funds are legally available to do so, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reducing distributions, Entergy Mississippi may receive equity contributions to maintain its capital structure.
Entergy Mississippi, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Uses of Capital
Entergy Mississippi requires capital resources for:
•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.
Following are the amounts of Entergy Mississippi’s planned construction and other capital investments.
| | | | | | | | | | | | | | | | | |
| | 2023 | | 2024 | | 2025 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation | $85 | | | $75 | | | $370 | |
| Transmission | 60 | | | 80 | | | 90 | |
| Distribution | 255 | | | 280 | | | 215 | |
| Utility Support | 65 | | | 30 | | | 40 | |
| Total | $465 | | | $465 | | | $715 | |
|
| | | | | | | | | | | |
| | 2020 | | 2021 | | 2022 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation |
| $110 |
| |
| $285 |
| |
| $85 |
|
| Transmission | 130 |
| | 125 |
| | 90 |
|
| Distribution | 150 |
| | 115 |
| | 95 |
|
| Utility Support | 145 |
| | 130 |
| | 135 |
|
| Total |
| $535 |
| |
| $655 |
| |
| $405 |
|
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Mississippi includes investments in generation projects to modernize, decarbonize, and diversify Entergy Mississippi’s portfolio; distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to drive reliability and resilience while also supporting renewables expansion; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, government actions, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.
Following are the amounts of Entergy Mississippi’s existing debt obligations and lease obligations (includes estimated interest payments) and other purchase obligations..
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2023 | | 2024 | | 2025 | | 2026-2027 | | After 2027 |
| | (In Millions) |
| Long-term debt (a) | $480 | | | $167 | | | $66 | | | $281 | | | $2,912 | |
| Operating leases (b) | $7 | | | $6 | | | $5 | | | $5 | | | $2 | |
| Finance leases (b) | $2 | | | $2 | | | $2 | | | $2 | | | $1 | |
|
| | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2021-2022 | | 2023-2024 | | After 2024 | | Total |
| | (In Millions) |
| Long-term debt (a) |
| $59 |
| |
| $118 |
| |
| $455 |
| |
| $2,301 |
| |
| $2,933 |
|
| Operating leases (b) |
| $6 |
| |
| $9 |
| |
| $2 |
| |
| $2 |
| |
| $19 |
|
| Finance leases (b) |
| $2 |
| |
| $3 |
| |
| $2 |
| |
| $1 |
| |
| $8 |
|
| Purchase obligations (c) |
| $266 |
| |
| $502 |
| |
| $477 |
| |
| $4,444 |
| |
| $5,689 |
|
| |
(a) | Includes estimated interest payments. (a)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. |
In addition to the contractualfinancial statements.
(b)Lease obligations given above, are discussed in Note 10 to the financial statements.
Other Obligations
Entergy Mississippi currently expects to contribute approximately $7.8$21.1 million to its qualified pension plans and approximately $130$136 thousand to other postretirement health care and life insurance plans in 2020,2023, although the 20202023 required pension contributions will be known with more certainty when the January 1, 20202023 valuations are completed, which is expected by April 1, 2020.2023. See “Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Also, in addition to the contractual obligations,
Entergy Mississippi, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Mississippi has $59.3$42.6 million of unrecognized tax benefits and interest net of unused tax attributes plus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition, to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Mississippi includes amounts associated with specific investments such as the Sunflower Solar Facility;
enters into fuel and purchased power agreements that contain minimum purchase obligations. Entergy Mississippi LLChas rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations. See Note 8 to the financial statements for discussion of Entergy Mississippi’s obligations under the Unit Power Sales Agreement.
Management’s Financial Discussion and Analysis
transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including advanced meters and related investments; resource planning, including potential generation projects; system improvements; software and security; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Mississippi pays distributions from its earnings at a percentage determined monthly.
Sunflower Solar Facility
In November 2018, Entergy Mississippi announced that it signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic facility that willto be sited on approximately 1,000 acres in Sunflower County, Mississippi. The estimated base purchase price is approximately $138.4 million. The estimated total investment, including the base purchase price and other related costs, for Entergy Mississippi to acquire the Sunflower Solar Facilityfacility is approximately $153.2 million. The purchase is contingent upon, among other things, obtaining necessary approvals, including full cost recovery, from applicable federal and state regulatory and permitting agencies. The project will bewas being built by Sunflower County Solar Project, LLC, a sub-subsidiaryan indirect subsidiary of Recurrent Energy, LLC. Entergy Mississippi will purchase the facility upon mechanical completion and after the other purchase contingencies have been met. In December 2018, Entergy Mississippi filed a joint petition with Sunflower County Solar Project atwith the MPSC for Sunflower County Solar Project to construct and for Entergy Mississippi to acquire and thereafter own, operate, improve, and maintain the solar facility. Entergy Mississippi proposed revisions to its formula rate plan that would provide for a mechanism, the interim capacity rate adjustment mechanism, in the formula rate plan to recover the non-fuel related costs of additional owned capacity acquired by Entergy Mississippi, including the annual ownership costs of the Sunflower Solar Facility.facility. 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. The MPSC must approve recoveryRecovery through the interim capacity rate adjustment requires MPSC approval for each new resource. In March 2020, Entergy Mississippi filed supplemental testimony addressing questions and observations raised in August 2019 by consultants retained by the Mississippi Public Utilities Staff filed a report expressing concerns regardingand proposing an alternative structure for the project economics and recommendedtransaction that shouldwould reduce its cost. In April 2020 the MPSC wishissued an order approving certification of the Sunflower Solar facility and its recovery through the interim capacity rate adjustment mechanism, subject to approve the project,certain conditions, including: (i) that Entergy Mississippi should be required to guaranteepursue a tax equity partnership structure through which the energy outputpartnership would acquire and own the facility under the build-own-transfer agreement and (ii) that if Entergy Mississippi does not consummate the partnership structure under the terms of the unit.order, there will be a cap of $136 million on the level of recoverable costs. In April 2022, Entergy Mississippi confirmed mechanical completion of the Sunflower Solar facility. Pursuant to the MPSC’s April 2020 order, MS Sunflower Partnership, LLC was formed for the tax equity partnership with Entergy Mississippi as its managing member. In May 2022 both Entergy Mississippi and the Staff are engaged in settlement discussionstax equity investor made capital contributions to address these concerns. A hearing beforethe tax equity partnership that were then used to make an initial payment of $105 million for acquisition of the facility. In July 2022, pursuant to the MPSC’s April 2020 order, Entergy Mississippi submitted a compliance filing to the MPSC is targeted to occurwith updated calculations of the impact of the Sunflower Solar facility on rate base and revenue requirement for the Sunflower Solar facility and benefits of the tax equity partnership. In November 2022 the MPSC approved Entergy Mississippi’s July 2022 compliance filing and authorized the recovery of the costs of the Sunflower Solar facility through the interim capacity rate adjustment mechanism in the formula rate plan with rates effective in December 2022. Substantial completion of the Sunflower Solar facility was accepted by Entergy Mississippi in September 2022. Also, commercial operation at the second quarterSunflower Solar facility commenced in September 2022. Pending the remediation of 2020. Closingcertain operational issues, final payment is expected in first quarter 2023. See Note 14 to occur by the endfinancial statements for discussion of 2021.Entergy Mississippi’s purchase of the Sunflower Solar facility.
Entergy Mississippi, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Sources of Capital
Entergy Mississippi’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•the Entergy System money pool;
•storm reserve escrow accounts;
•debt or preferred membership interest issuances;issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations, Entergy Mississippi may refinance, redeem, or otherwiseexpects to continue, when economically feasible, to retire higher-cost debt prior to maturity, to the extentand replace it with lower-cost debt if market conditions and interest rates are favorable.permit.
All debt and preferred membership interest issuances by Entergy Mississippi require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in its bond indenture and other agreements. Entergy Mississippi has sufficient capacity under these tests to meet its foreseeable capital needs.needs for the next twelve months and beyond.
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
Entergy Mississippi’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
| | | | | | | | | | | | | | | | | | | | |
| 2022 | | 2021 | | 2020 | | 2019 |
| (In Thousands) |
| $26,879 | | $40,456 | | ($16,516) | | $44,693 |
|
| | | | | | |
| 2019 | | 2018 | | 2017 | | 2016 |
| (In Thousands) |
| $44,693 | | $41,380 | | $1,633 | | $10,595 |
See Note 4 to the financial statements for a description of the money pool.
Entergy Mississippi has three separate credit facilities in the aggregate amount of $82.5$95 million scheduled to expire in May 2020. NoApril 2023. As of December 31, 2022, there were no cash borrowings outstanding under these credit facilities. Also, Entergy Mississippi has a credit facility in the amount of $150 million scheduled to expire in July 2024. As of December 31, 2022, there were no cash borrowings outstanding under the credit facilities as of December 31, 2019.facility. In addition, Entergy Mississippi is a party to an uncommitted letter of credit facility primarily as a means to post collateral to support its obligations to MISO. As of December 31, 2019, $1.82022, $6.7 million in MISO letters of credit and $1 million in non-MISO letters of credit were outstanding under Entergy Mississippi’s uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.
Entergy Mississippi obtained authorization from the FERC through November 2020October 2023 for short-term borrowings not to exceed an aggregate amount of $175$200 million at any time outstanding and long-term borrowings and security issuances. See Note 4 to the financial statements for further discussion of Entergy Mississippi’s short-term borrowing limits.
Entergy Mississippi had $33.5 million in its storm reserve escrow account at December 31, 2022.
Entergy Mississippi, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy Mississippi charges for electricityits services significantly influence its financial position, results of operations, and liquidity. Entergy Mississippi is regulated, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the MPSC, is primarily responsible for approval of the rates charged to customers.
Filings with the MPSC
Retail Rates
2020 Formula Rate Plan Filings
In March 2017,2020, Entergy Mississippi submitted its formula rate plan 20172020 test year filing and 20162019 look-back filing showing Entergy Mississippi’s earned return for the historical 2016 calendar year and projected earned return for the 20172019 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.
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
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
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.
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 abovebelow the formula rate plan bandwidth and projected earned return for the 20192020 calendar year to be below the formula rate plan bandwidth. The 20192020 test year filing shows a $36.8$24.6 million rate increase is necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.94%6.51% return on rate base, within the formula rate plan bandwidth. The 20182019 look-back filing compares actual 20182019 results to the approved benchmark return on rate base and showsreflects the need for a $10.1$7.3 million interim decreaseincrease in formula rate plan revenues is necessary.revenues. In accordance with 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 underMPSC-approved revisions to the formula rate plan, performance-adjusted bandwidth mechanism. In the first quarter 2019, Entergy Mississippi recordedimplemented a $0.8$24.3 million interim rate increase, inreflecting a cap equal to 2% of 2019 retail revenues, effective with the provisionApril 2020 billing cycle, subject to reflect the amount shown in the look-back filing.refund. In June 2019,2020, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed that the 20192020 test year filing showed that a $32.8$23.8 million rate increase is necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.93%6.51% return on rate base, within the formula rate plan bandwidth. Additionally, pursuantPursuant to the joint stipulation, Entergy Mississippi’s 20182019 look-back filing reflected an earned return on rate base of 7.81%6.75% in calendar year 20182019, which is abovewithin the look-back benchmark return on rate base of 7.13%, resulting in an $11 million decreasebandwidth. As a result, there is no change 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 the2019 look-back filing. In June 20192020 the MPSC approved the joint stipulation with rates effective for the first billing cycle of July 2019.2020. In the June 2020 order the MPSC directed Entergy Mississippi to submit revisions to its formula rate plan to realign recovery of costs from its energy efficiency cost recovery rider to its formula rate plan. In November 2020 the MPSC approved Entergy Mississippi’s revisions to its formula rate plan providing for the realignment of energy efficiency costs to its formula rate plan, the deferral of energy efficiency expenditures into a regulatory asset, and the elimination of its energy efficiency cost recovery rider effective with the January 2022 billing cycle.
Internal Restructuring2021 Formula Rate Plan Filing
In March 2018,2021, Entergy Mississippi filedsubmitted its formula rate plan 2021 test year filing and 2020 look-back filing showing Entergy Mississippi’s earned return for the historical 2020 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2021 calendar year to be below the formula rate plan bandwidth. The 2021 test year filing shows a $95.4 million rate increase is necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.69% return on rate base, within the formula rate plan bandwidth. The change in formula rate plan revenues, however, is capped at 4% of retail revenues, which equates to a revenue change of $44.3 million. The 2021 evaluation report also includes $3.9 million in demand side management costs for which the MPSC approved realignment of recovery from the energy efficiency rider to the formula rate plan. These costs are not subject to the 4% cap and result in a total change in formula rate plan revenues of $48.2 million. The 2020 look-back filing compares actual 2020 results to the approved benchmark return on rate base and reflects the need for a $16.8 million interim increase in formula rate plan revenues. In addition, the 2020 look-back filing includes an applicationinterim capacity adjustment true-up for the Choctaw Generating Station, which increases the look-back interim rate adjustment by $1.7 million. These interim rate adjustments total $18.5 million. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $22.1 million interim rate increase, reflecting a cap equal to 2% of 2020 retail revenues, effective
Entergy Mississippi, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
with the April 2021 billing cycle, subject to refund, pending a final MPSC seeking authorizationorder. The $3.9 million of demand side management costs and the Choctaw Generating Station true-up of $1.7 million, which are not subject to undertake a restructuring that would resultthe 2% cap of 2020 retail revenues, were included 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. April 2021 rate adjustments.
In September 2018,June 2021, Entergy Mississippi and the Mississippi Public Utilities Staff entered into and filed a joint stipulation regardingthat confirmed the restructuring filing.2021 test year filing that resulted in a total rate increase of $48.2 million. Pursuant to the joint stipulation, Entergy Mississippi’s 2020 look-back filing reflected an earned return on rate base of 6.12% in calendar year 2020, which is below the look-back bandwidth, resulting in a $17.5 million increase in formula rate plan revenues on an interim basis through June 2022. This includes $1.7 million related to the Choctaw Generating Station and $3.7 million of COVID-19 non-bad debt expenses. See “COVID-19 Orders” below for additional discussion of provisions of the joint stipulation related to COVID-19 expenses. In September 2018June 2021 the MPSC issuedapproved the joint stipulation with rates effective for the first billing cycle of July 2021. In June 2021, Entergy Mississippi recorded regulatory credits of $19.9 million to reflect the effects of the joint stipulation.
2022 Formula Rate Plan Filing
In March 2022, Entergy Mississippi submitted its formula rate plan 2022 test year filing and 2021 look-back filing showing Entergy Mississippi’s earned return for the historical 2021 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2022 calendar year to be below the formula rate plan bandwidth. The 2022 test year filing shows a $69 million rate increase is necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.70% return on rate base, within the formula rate plan bandwidth. The change in formula rate plan revenues, however, is capped at 4% of retail revenues, which equates to a revenue change of $48.6 million. The 2021 look-back filing compares actual 2021 results to the approved benchmark return on rate base and reflects the need for a $34.5 million interim increase in formula rate plan revenues. In fourth quarter 2021, Entergy Mississippi recorded a regulatory asset of $19 million to reflect the then-current estimate in connection with the look-back feature of the formula rate plan. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $24.3 million interim rate increase, reflecting a cap equal to 2% of 2021 retail revenues, effective in April 2022.
In June 2022, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed the 2022 test year filing that resulted in a total rate increase of $48.6 million. Pursuant to the joint stipulation, Entergy Mississippi’s 2021 look-back filing reflected an order acceptingearned return on rate base of 5.99% in calendar year 2021, which is below the look-back bandwidth, resulting in a $34.3 million increase in the formula rate plan revenues on an interim basis through June 2023. In July 2022 the MPSC approved the joint stipulation with rates effective in its entirety andAugust 2022. In July 2022, Entergy Mississippi recorded regulatory credits of $22.6 million to reflect the effects of the joint stipulation. In August 2022 an intervenor filed a statutorily-authorized direct appeal to the Mississippi Supreme Court seeking review of the MPSC’s July 2022 order approving the restructuring and credits of $27 million to retail customers over six years, consisting of annual payments of $4.5 million forjoint stipulation confirming Entergy Mississippi’s 2022 formula rate plan filing. The rates that went into effect in August 2022 are not stayed or otherwise impacted while the years 2019-2024.appeal is pending.
In July 2022 the MPSC directed Entergy Mississippi also receivedto flow $14.1 million of the required FERC approval.power management rider over-recovery balance to customers beginning in August 2022 through December 2022 to mitigate the bill impact of the increase in formula rate plan revenues.
In November 2018, Entergy Mississippi undertook a multi-step restructuring, including the following:2023 Formula Rate Plan Filing
Entergy Mississippi Inc. redeemedplans to file its outstanding preferred stock, atlook-back evaluation report in March 2023 that will compare actual 2022 results to the aggregate redemption price of approximately $21.2 million.
performance-adjusted allowed return on rate base. In fourth quarter 2022, Entergy Mississippi Inc. converted fromrecorded a Mississippi corporation to a Texas corporation.
Underregulatory asset of $18.2 million in connection with 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 alllook-back feature of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger underformula rate plan to reflect that the TXBOC. Entergy Mississippi, Inc. remained in existence and held2022 estimated earned return was below the membership interests in Entergy Mississippi Power and Light.formula bandwidth.
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.
Entergy Mississippi, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
In December 2018, Entergy Mississippi, Inc. changedPursuant to a mandatory reopener provision in its name to Entergy Utility Enterprises, Inc., and Entergy Mississippi Power and Light then changed its name to Entergy Mississippi, LLC. Entergy Mississippi, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Mississippi, Inc. The restructuring was accounted for as a transaction between entities under common control.
In December 2018, Entergy Mississippi filed its notice of intent to implement the restructuring credit rider to allow Entergy Mississippi to return credits of $27 million to retail customers over six years. In January 2019net metering rule, the MPSC approvedopened a docket to review the proposed restructuring credit adjustment factor, which is effective for bills rendered beginning February 2019.
Advanced Metering Infrastructure (AMI)
efficacy and fairness of its existing net metering rule. 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, andJuly 2022 the MPSC issued an order approvingadopting revisions to its net metering rule. Among other things, the filing without material changes, findingamended rule requires utilities to calculate avoided cost using daytime energy production, grandfathers a 2.5 cents per kWh distributed generation benefits adder for 25 years, and expands eligibility for the 2 cents per kWh low-income benefits adder to households up to 250% of the federal poverty level and grandfathers that adder for 25 years. The amended rule expands meter aggregation to include systems up to 3 MW alternating current and to any additional meters within the same electric utility service territory. The amended rule also increases the 3% net metering participation cap to 4% and requires that utilities seek MPSC approval prior to refusing additional net generation requests. The MPSC also directs utilities to make rate filings implementing rebates for distributed generation facilities. Because of the size and number of customers eligible under this new rule, there is a risk of loss of load and the shifting of costs to customers. In August 2022, Entergy Mississippi filed a motion for rehearing on the proposed net metering rule, which the MPSC granted. A hearing on the proposed rule was held in September 2022. In October 2022 the MPSC adopted an amended rule, which will now be known as the Distributed Generation Rule. In the Distributed Generation Rule, all provisions permitting meter aggregation were struck. The Distributed Generation Rule maintains the 3% net metering participation cap. The Distributed Generation Rule grandfathers a 2.5 cents per kWh distributed generation benefits adder for 25 years and expands eligibility for the 2 cents per kWh low-income benefits adder to households up to 225% of the federal poverty level and grandfathers that adder for 25 years. The Distributed Generation Rule also directs utilities to make rate filings implementing up-front incentives for distributed generating systems and demand response battery systems, and to establish a public K-12 solar for schools program.
COVID-19 Orders
In March 2020 the MPSC issued an order suspending disconnections for a period of sixty days. The MPSC extended the order on disconnections through May 26, 2020. In April 2020 the MPSC issued an order authorizing utilities to defer incremental costs and expenses associated with COVID-19 compliance and to seek future recovery through rates of the prudently incurred incremental costs and expenses. In December 2020, Entergy Mississippi resumed disconnections for commercial, industrial, and governmental customers with past-due balances that have not made payment arrangements. In January 2021, Entergy Mississippi resumed disconnecting service for residential customers with past-due balances that had not made payment arrangements. Pursuant to the June 2021 MPSC order approving 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 20182021 formula rate plan evaluation reportfiling, Entergy Mississippi stopped deferring COVID-19 non-bad debt expenses effective December 31, 2020 and included those expenses in the ratemaking effectslook-back filing for the 2021 formula rate plan test year. In the order, the MPSC also adopted Entergy Mississippi’s quantification and methodology for calculating COVID-19 incremental bad debt expenses and authorized Entergy Mississippi to continue deferring these bad debt expenses through December 2021. Entergy Mississippi began recovery of the Tax Act,bad debt expense deferral resulting from the MPSC approved the accelerationCOVID-19 pandemic over a three-year period with implementation of the recoveryinterim formula rate plan rates in April 2022. As of substantially allDecember 31, 2022, Entergy Mississippi had a remaining regulatory asset of Entergy Mississippi’s existing customer meters in anticipation of AMI deployment.$9.8 million for costs associated with the COVID-19 pandemic.
Fuel and Purchased Power Cost Recoverypurchased power cost recovery
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 2017,2019, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation included $39.6 million of prior over-recovery flowing back to customers beginning February 2020. Entergy Mississippi’s balance in its deferred fuel account did not decrease as expected after implementation of the new factor. In an effort to assist customers during the COVID-19 pandemic, in May 2020, Entergy Mississippi requested an interim adjustment to the energy cost recovery rider to credit
Entergy Mississippi, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
approximately $50 million from the over-recovered balance in the deferred fuel account to customers over four consecutive billing months. The MPSC approved this interim adjustment in May 2020 effective for June through September 2020 bills.
In November 2020, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an over-recovery of approximately $24.4 million as of September 30, 2020. In January 2021 the MPSC approved the proposed energy cost factor effective for February 2021 bills.
In November 2021, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an under-recovery of approximately $61.5$80.6 million as of September 30, 2017.2021. In December 2021, at the request of the MPSC, Entergy Mississippi submitted a proposal to mitigate the impact of rising fuel costs on customer bills during 2022. Entergy Mississippi proposed that the deferred fuel balance as of December 31, 2021, which was $121.9 million, be amortized over three years, and that the MPSC authorize Entergy Mississippi to apply its weighted-average cost of capital as the carrying cost for the unamortized fuel balance. In January 20182022 the MPSC approved the proposed energy cost factors effective for February 2018 bills.
$100 million of the deferred fuel balance over two years and authorized Entergy Mississippi LLC
Management’s Financial Discussion and Analysis
In November 2018, Entergy Mississippi filedto apply its annual redeterminationweighted-average cost of capital as the annual factor to be applied undercarrying cost for the energy cost recovery rider.unamortized fuel balance. 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 20192022 bills.
See “Complaints Against System Energy - System Energy Settlement with the MPSC” in Note 2 to the financial statements for discussion of the settlement agreement filed with the FERC in June 2022. The settlement, which was contingent upon FERC approval, provides for a refund of $235 million from System Energy to Entergy Mississippi. In July 2022 the MPSC directed the disbursement of settlement proceeds, ordering Entergy Mississippi to provide a one-time $80 bill credit to each of its approximately 460,000 retail customers to be effective during the September 2022 billing cycle, and to apply the remaining proceeds to Entergy Mississippi’s under-recovered deferred fuel balance. In accordance with the MPSC’s directive, Entergy Mississippi provided approximately $36.7 million in customer bill credits as a result of the settlement. In November 2019,2022, Entergy Mississippi filed its annual redeterminationapplied the remaining settlement proceeds in the amount of approximately $198.3 million to Entergy Mississippi’s under-recovered deferred fuel balance. In November 2022 the annual factor to be appliedFERC issued an order approving the System Energy settlement with the MPSC.
Entergy Mississippi had a deferred fuel balance of approximately $291.7 million under the energy cost recovery rider as of July 31, 2022, along with an over-recovery balance of $51.1 million under the power management rider. Without further action, Entergy Mississippi anticipated a year-end deferred fuel balance of approximately $200 million after application of a portion of the System Energy settlement proceeds, as discussed above. In September 2022, Entergy Mississippi filed for interim adjustments under both the energy cost recovery rider and the power management rider. Entergy Mississippi proposed five monthly incremental adjustments to the net energy cost factor designed to collect the under-recovered fuel balance as of July 31, 2022 and to reflect the recovery of a higher natural gas price. Entergy Mississippi also proposed five monthly incremental adjustments to the power management adjustment factor designed to flow through to customers the over-recovered power management rider balance as of July 31, 2022. In October 2022 the MPSC approved modified interim adjustments to Entergy Mississippi’s energy cost recovery rider and power management rider. The calculation ofMPSC approved dividing the annual factor included an over-recovery of approximately $39.6 millionenergy cost recovery rider interim adjustment into two components that would allow Entergy Mississippi to 1) recover a natural gas fuel rate that is better aligned with current prices and 2) recover the estimated under-recovered deferred fuel balance as of September 30, 2019. In January 2020 the2022 over a period of 20 months. The MPSC approved six monthly incremental adjustments to the proposednet energy cost factor effective for February 2020 bills.
Mississippi Attorney General Complaint
designed to reflect the recovery of a higher natural gas price. The Mississippi Attorney General filed a complaint in state court in December 2008 against Entergy Corporation,MPSC also approved six monthly incremental adjustments to the power management adjustment factor designed to flow through to customers the over-recovered power management rider balance. In accordance with the order of the MPSC, Entergy Mississippi did not file an annual redetermination of the energy cost recovery rider or the power management rider in November 2022. Entergy Services, and Entergy Power alleging, among other things, violationsMississippi’s November 2023 annual redetermination will not reflect any part of Mississippi statutes, fraud, and breachthe estimated under-recovered deferred fuel balance as 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 September 30, 2022; it will
Entergy Mississippi, purchases power not generated in Mississippi to meet electricity demand. Entergy believesLLC and Subsidiaries
Management’s Financial Discussion and Analysis
only reflect any over/under recovery that accumulates after September 2022. The November 2024 annual redetermination will include 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 thesetotal 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 purviewfuel balance, including any over- or under-recovery 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.deferred fuel balance as of September 30, 2022.
Storm Cost Recovery Filings with Retail Regulators
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 wasbalance has been less than $10 million thereforesince May 2019, and Entergy Mississippi resumedhas been 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 withsince July 2019 bills.2019.
Federal Regulation
See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.
Nuclear Matters
See the “Nuclear Matters” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of nuclear matters.
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
Environmental Risks
Entergy Mississippi’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Mississippi is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of Entergy Mississippi’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and there is the potential for future changes in the assumptions and measurements that could produce estimates that would have a material impact on the presentation of Entergy Mississippi’s financial position or results of operations.
Utility Regulatory Accounting
See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.
Entergy Mississippi, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Impairment of Long-lived Assets and Trust Fund Investments
See “Impairment of Long-lived Assets and Trust Fund Investments” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the impairment of long-lived assets.
Taxation and Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.
Qualified Pension and Other Postretirement Benefits
Entergy Mississippi’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2023 Qualified Pension Cost | | Impact on 2022 Projected Qualified Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $364 | | $7,086 |
| Rate of return on plan assets | | (0.25%) | | $719 | | $— |
| Rate of increase in compensation | | 0.25% | | $303 | | $1,533 |
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2020 Qualified Pension Cost | | Impact on 2019 Projected Qualified Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $719 | | $11,678 |
| Rate of return on plan assets | | (0.25%) | | $823 | | $— |
| Rate of increase in compensation | | 0.25% | | $483 | | $2,529 |
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2023 Postretirement Benefit Cost | | Impact on 2022 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $27 | | $1,138 |
| Health care cost trend | | 0.25% | | $84 | | $982 |
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2020 Postretirement Benefit Cost | | Impact on 2019 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $29 | | $1,939 |
| Health care cost trend | | 0.25% | | $81 | | $1,456 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Employer Contributions
Total qualified pension cost for Entergy Mississippi in 20192022 was $11.3 million.$29.2 million, including $15.8 million in settlement costs. Entergy Mississippi anticipates 20202023 qualified pension cost to be $17.4$9 million. Entergy Mississippi contributed $20.8$33.3 million to its qualified pension plans in 20192022 and estimates 20202023 pension contributions will be
Entergy Mississippi, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
approximately $7.8$21.1 million, although the 20202023 required pension contributions will be known with more certainty when the January 1, 20202023 valuations are completed, which is expected by April 1, 2020.2023.
Total postretirement health care and life insurance benefit income for Entergy Mississippi in 20192022 was $2.1$4.4 million. Entergy Mississippi expects 20202023 postretirement health care and life insurance benefit income of approximately $3.1 thousand.$2.5 million. Entergy Mississippi contributed $228$759 thousand to its other postretirement plansplan in 20192022 and estimates that 20202023 contributions will be approximately $130$136 thousand.
Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the member and Board of Directors of
Entergy Mississippi, LLC and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy Mississippi, LLC and Subsidiaries (the “Company”) as of December 31, 20192022 and 2018,2021, the related consolidated statements of income, cash flows and changes in member’s equity (pages 363394 through 368398 and applicable items in pages 4953 through 236)245), for each of the three years in the period ended December 31, 2019,2022, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20192022 and 2018,2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2022, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Rate and Regulatory Matters —Entergy Mississippi, LLC and Subsidiaries — Refer to Note 2 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Mississippi Public Service Commission (the “MPSC”), which has jurisdiction with respect to the rates of electric companies in Mississippi, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.
The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the MPSC and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the MPSC and the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs and refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the MPSC and the FERC, involved specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and significant auditor judgment to evaluate management estimates and the subjectivity of audit evidence.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the MPSC and the FERC included the following, among others:
•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 Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the MPSC and the FERC for the Company, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the MPSC’s and 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.
•For regulatory matters in process, we inspected the Company’s filings with the MPSC and the FERC, including the annual formula rate plan filing, and considered the filings with the MPSC and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.
•We obtained an analysis from management and support 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 not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 21, 202024, 2023
We have served as the Company’s auditor since 2001.
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | |
| | | For the Years Ended December 31, |
| | | 2022 | | 2021 | | 2020 |
| | | (In Thousands) |
| | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | | $1,624,234 | | | $1,406,346 | | | $1,247,854 | |
| | | | | | |
| OPERATING EXPENSES | | | | | | |
| Operation and Maintenance: | | | | | | |
| Fuel, fuel-related expenses, and gas purchased for resale | | 252,760 | | | 181,511 | | | 187,087 | |
| Purchased power | | 322,674 | | | 298,034 | | | 240,471 | |
| Other operation and maintenance | | 314,902 | | | 298,129 | | | 288,543 | |
| | | | | | |
| Taxes other than income taxes | | 137,541 | | | 111,712 | | | 101,525 | |
| Depreciation and amortization | | 246,063 | | | 226,545 | | | 209,252 | |
| Other regulatory charges (credits) - net | | 38,017 | | | 5,913 | | | (15,219) | |
| TOTAL | | 1,311,957 | | | 1,121,844 | | | 1,011,659 | |
| | | | | | |
| OPERATING INCOME | | 312,277 | | | 284,502 | | | 236,195 | |
| | | | | | |
| OTHER INCOME (DEDUCTIONS) | | | | | | |
| Allowance for equity funds used during construction | | 6,125 | | | 8,101 | | | 6,726 | |
| Interest and investment income | | 508 | | | 53 | | | 272 | |
| Miscellaneous - net | | (3,619) | | | (8,791) | | | (9,253) | |
| TOTAL | | 3,014 | | | (637) | | | (2,255) | |
| | | | | | |
| INTEREST EXPENSE | | | | | | |
| Interest expense | | 86,960 | | | 75,124 | | | 68,945 | |
| Allowance for borrowed funds used during construction | | (2,800) | | | (3,416) | | | (2,778) | |
| TOTAL | | 84,160 | | | 71,708 | | | 66,167 | |
| | | | | | |
| INCOME BEFORE INCOME TAXES | | 231,131 | | | 212,157 | | | 167,773 | |
| | | | | | |
| Income taxes | | 54,864 | | | 45,323 | | | 27,190 | |
| | | | | | |
| NET INCOME | | 176,267 | | | 166,834 | | | 140,583 | |
| | | | | | |
| Net loss attributable to noncontrolling interest | | (21,355) | | | — | | | — | |
| | | | | | |
| EARNINGS APPLICABLE TO MEMBER'S EQUITY | | $197,622 | | | $166,834 | | | $140,583 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, LLC |
| INCOME STATEMENTS |
| | | |
| | | For the Years Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | |
| $1,323,043 |
| |
| $1,335,112 |
| |
| $1,198,229 |
|
| | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 277,425 |
| | 260,198 |
| | 185,816 |
|
| Purchased power | | 284,492 |
| | 364,575 |
| | 328,463 |
|
| Other operation and maintenance | | 266,175 |
| | 261,613 |
| | 240,738 |
|
| Taxes other than income taxes | | 105,318 |
| | 101,999 |
| | 95,051 |
|
| Depreciation and amortization | | 170,886 |
| | 152,577 |
| | 143,479 |
|
| Other regulatory charges (credits) - net | | 14,993 |
| | 147,704 |
| | (19,134 | ) |
| TOTAL | | 1,119,289 |
| | 1,288,666 |
| | 974,413 |
|
| | | | | | | |
| OPERATING INCOME | | 203,754 |
| | 46,446 |
| | 223,816 |
|
| | | | | | | |
| OTHER INCOME | | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 8,356 |
| | 8,710 |
| | 9,667 |
|
| Interest and investment income | | 1,412 |
| | 135 |
| | 85 |
|
| Miscellaneous - net | | (4,478 | ) | | (2,732 | ) | | (2,232 | ) |
| TOTAL | | 5,290 |
| | 6,113 |
| | 7,520 |
|
| | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
|
| Interest expense | | 61,785 |
| | 55,905 |
| | 51,260 |
|
| Allowance for borrowed funds used during construction | | (3,532 | ) | | (3,651 | ) | | (3,875 | ) |
| TOTAL | | 58,253 |
| | 52,254 |
| | 47,385 |
|
| | | | | | | |
| INCOME BEFORE INCOME TAXES | | 150,791 |
| | 305 |
| | 183,951 |
|
| | | | | | | |
| Income taxes | | 30,866 |
| | (125,773 | ) | | 73,919 |
|
| | | | | | | |
| NET INCOME | | 119,925 |
| | 126,078 |
| | 110,032 |
|
| | | | |
|
| | |
| Preferred dividend requirements and other | | — |
| | 834 |
| | 953 |
|
| | | | | | | |
| EARNINGS APPLICABLE TO COMMON EQUITY | |
| $119,925 |
| |
| $125,244 |
| |
| $109,079 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | |
| | | For the Years Ended December 31, |
| | | 2022 | | 2021 | | 2020 |
| | | (In Thousands) |
| | | | | | |
| OPERATING ACTIVITIES | | | | | | |
| Net income | | $176,267 | | | $166,834 | | | $140,583 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation and amortization | | 246,063 | | | 226,545 | | | 209,252 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 54,850 | | | 64,868 | | | 36,827 | |
| Changes in assets and liabilities: | | | | | | |
| Receivables | | (65,843) | | | 10,260 | | | (1,889) | |
| Fuel inventory | | (5,237) | | | 6,806 | | | (1,978) | |
| Accounts payable | | 49,101 | | | 27,068 | | | 22,794 | |
| Taxes accrued | | 18,632 | | | (1,811) | | | 17,423 | |
| Interest accrued | | 925 | | | (3,606) | | | 1,989 | |
| Deferred fuel costs | | (21,333) | | | (136,569) | | | (55,711) | |
| Other working capital accounts | | 2,632 | | | (9,522) | | | 630 | |
| Provisions for estimated losses | | (519) | | | (8,476) | | | (3,517) | |
| Other regulatory assets | | (57,028) | | | 4,909 | | | (89,369) | |
| Other regulatory liabilities | | 20,165 | | | 21,930 | | | (18,672) | |
| | | | | | |
| Pension and other postretirement liabilities | | (35,299) | | | (51,828) | | | 11,319 | |
| Other assets and liabilities | | 22,273 | | | 33,552 | | | 30,633 | |
| Net cash flow provided by operating activities | | 405,649 | | | 350,960 | | | 300,314 | |
| INVESTING ACTIVITIES | | | | | | |
| Construction expenditures | | (534,020) | | | (654,352) | | | (555,287) | |
| Allowance for equity funds used during construction | | 6,125 | | | 8,101 | | | 6,726 | |
| | | | | | |
| | | | | | |
| Payment for purchase of assets | | (105,149) | | | — | | | (28,612) | |
| Changes in money pool receivable - net | | 13,577 | | | (40,456) | | | 44,692 | |
| | | | | | |
| | | | | | |
| | | | | | |
| Other | | (1,273) | | | 53 | | | 1,719 | |
| Net cash flow used in investing activities | | (620,740) | | | (686,654) | | | (530,762) | |
| FINANCING ACTIVITIES | | | | | | |
| Proceeds from the issuance of long-term debt | | 249,266 | | | 398,284 | | | 165,385 | |
| Retirement of long-term debt | | (100,000) | | | — | | | — | |
| Capital contributions from noncontrolling interest | | 24,702 | | | — | | | — | |
| Changes in money pool payable - net | | — | | | (16,516) | | | 16,516 | |
| | | | | | |
| | | | | | |
| | | | | | |
| Common equity distributions paid | | — | | | — | | | (10,000) | |
| | | | | | |
| Other | | 10,475 | | | 1,535 | | | 6,964 | |
| Net cash flow provided by financing activities | | 184,443 | | | 383,303 | | | 178,865 | |
| Net increase (decrease) in cash and cash equivalents | | (30,648) | | | 47,609 | | | (51,583) | |
| Cash and cash equivalents at beginning of period | | 47,627 | | | 18 | | | 51,601 | |
| Cash and cash equivalents at end of period | | $16,979 | | | $47,627 | | | $18 | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | |
| Cash paid (received) during the period for: | | | | | | |
| Interest - net of amount capitalized | | $83,291 | | | $76,245 | | | $64,536 | |
| Income taxes | | ($5,396) | | | ($19,672) | | | ($8,084) | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
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|
| | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, LLC |
| STATEMENTS OF CASH FLOWS |
| | | |
| | | For the Years Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING ACTIVITIES | | | | | | |
| Net income | |
| $119,925 |
| |
| $126,078 |
| |
| $110,032 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation and amortization | | 170,886 |
| | 152,577 |
| | 143,479 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 32,547 |
| | 56,502 |
| | 84,816 |
|
| Changes in assets and liabilities: | | |
| | |
| | |
|
| Receivables | | (17,245 | ) | | 37,762 |
| | (29,528 | ) |
| Fuel inventory | | (3,208 | ) | | 33,675 |
| | 5,266 |
|
| Accounts payable | | (226 | ) | | (7,472 | ) | | 3,595 |
|
| Taxes accrued | | 13,109 |
| | (5,291 | ) | | 18,803 |
|
| Interest accrued | | (1,331 | ) | | (2,670 | ) | | 1,248 |
|
| Deferred fuel costs | | 78,418 |
| | 24,428 |
| | (25,487 | ) |
| Other working capital accounts | | (5,557 | ) | | (9,902 | ) | | 5,115 |
|
| Provisions for estimated losses | | (1,121 | ) | | 6,378 |
| | (9,676 | ) |
| Other regulatory assets | | (34,923 | ) | | 54,860 |
| | (17,412 | ) |
| Other regulatory liabilities | | (21,524 | ) | | (131,856 | ) | | 405,395 |
|
| Deferred tax rate change recognized as regulatory liability/asset | | — |
| | — |
| | (452,429 | ) |
| Pension and other postretirement liabilities | | 6,534 |
| | (8,405 | ) | | (8,055 | ) |
| Other assets and liabilities | | 3,668 |
| | 91,718 |
| | (8,577 | ) |
| Net cash flow provided by operating activities | | 339,952 |
| | 418,382 |
| | 226,585 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
|
| Construction expenditures | | (432,600 | ) | | (387,293 | ) | | (427,616 | ) |
| Allowance for equity funds used during construction | | 8,356 |
| | 8,710 |
| | 9,667 |
|
| Changes in money pool receivable - net | | (3,313 | ) | | (39,747 | ) | | 8,962 |
|
| Payment for purchase of plant or assets | | (305,472 | ) | | — |
| | (6,958 | ) |
| Other | | (655 | ) | | (1,123 | ) | | (1,281 | ) |
| Net cash flow used in investing activities | | (733,684 | ) | | (419,453 | ) | | (417,226 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | 437,153 |
| | 54,449 |
| | 148,185 |
|
| Retirement of long-term debt | | (150,000 | ) | | — |
| | — |
|
| Redemption of preferred stock | | — |
| | (21,208 | ) | | — |
|
| Capital contributions from parent | | 130,000 |
| | — |
| | — |
|
| Distributions/dividends paid: | | |
| | |
| | |
|
| Common equity | | — |
| | (10,000 | ) | | (26,000 | ) |
| Preferred stock | | — |
| | (993 | ) | | (953 | ) |
| Other | | (8,774 | ) | | 9,681 |
| | (1,329 | ) |
| Net cash flow provided by financing activities | | 408,379 |
| | 31,929 |
| | 119,903 |
|
| Net increase (decrease) in cash and cash equivalents | | 14,647 |
| | 30,858 |
| | (70,738 | ) |
| Cash and cash equivalents at beginning of period | | 36,954 |
| | 6,096 |
| | 76,834 |
|
| Cash and cash equivalents at end of period | |
| $51,601 |
| |
| $36,954 |
| |
| $6,096 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $60,533 |
| |
| $56,037 |
| |
| $47,631 |
|
| Income taxes | |
| ($12,204 | ) | |
| ($19,118 | ) | |
| ($25,043 | ) |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | |
| | | December 31, |
| | | 2022 | | 2021 |
| | | (In Thousands) |
| | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | | $26 | | | $29 | |
| Temporary cash investments | | 16,953 | | | 47,598 | |
| Total cash and cash equivalents | | 16,979 | | | 47,627 | |
| Accounts receivable: | | | | |
| Customer | | 99,504 | | | 84,048 | |
| Allowance for doubtful accounts | | (2,472) | | | (7,209) | |
| Associated companies | | 37,673 | | | 42,994 | |
| Other | | 34,564 | | | 14,609 | |
| Accrued unbilled revenues | | 73,473 | | | 56,034 | |
| Total accounts receivable | | 242,742 | | | 190,476 | |
| Deferred fuel costs | | 143,211 | | | 121,878 | |
| | | | |
| Fuel inventory - at average cost | | 15,548 | | | 10,311 | |
| Materials and supplies - at average cost | | 84,346 | | | 69,639 | |
| | | | |
| Prepayments and other | | 9,603 | | | 6,394 | |
| TOTAL | | 512,429 | | | 446,325 | |
| | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | |
| Non-utility property - at cost (less accumulated depreciation) | | 4,512 | | | 4,527 | |
| Escrow accounts | | 33,549 | | | 48,886 | |
| Other | | 910 | | | — | |
| TOTAL | | 38,971 | | | 53,413 | |
| | | | |
| UTILITY PLANT | | | | |
| Electric | | 7,079,849 | | | 6,613,109 | |
| | | | |
| Construction work in progress | | 170,191 | | | 95,452 | |
| TOTAL UTILITY PLANT | | 7,250,040 | | | 6,708,561 | |
| Less - accumulated depreciation and amortization | | 2,264,786 | | | 2,127,590 | |
| UTILITY PLANT - NET | | 4,985,254 | | | 4,580,971 | |
| | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | |
| Regulatory assets: | | | | |
| | | | |
| Other regulatory assets | | 519,460 | | | 462,432 | |
| Other | | 22,650 | | | 14,248 | |
| TOTAL | | 542,110 | | | 476,680 | |
| | | | |
| TOTAL ASSETS | | $6,078,764 | | | $5,557,389 | |
| | | | |
| See Notes to Financial Statements. | | | | |
|
| | | | | | | | |
| ENTERGY MISSISSIPPI, LLC |
| BALANCE SHEETS |
| ASSETS |
| | | |
| | | December 31, |
| | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | |
| $11 |
| |
| $11 |
|
| Temporary cash investments | | 51,590 |
| | 36,943 |
|
| Total cash and cash equivalents | | 51,601 |
| | 36,954 |
|
| Accounts receivable: | | |
| | |
|
| Customer | | 92,050 |
| | 73,205 |
|
| Allowance for doubtful accounts | | (636 | ) | | (563 | ) |
| Associated companies | | 49,257 |
| | 51,065 |
|
| Other | | 14,986 |
| | 8,647 |
|
| Accrued unbilled revenues | | 47,426 |
| | 50,171 |
|
| Total accounts receivable | | 203,083 |
| | 182,525 |
|
| Deferred fuel costs | | — |
| | 8,016 |
|
| Fuel inventory - at average cost | | 15,139 |
| | 11,931 |
|
| Materials and supplies - at average cost | | 57,972 |
| | 47,255 |
|
| Prepayments and other | | 7,149 |
| | 9,365 |
|
| TOTAL | | 334,944 |
| | 296,046 |
|
| | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
|
| Non-utility property - at cost (less accumulated depreciation) | | 4,560 |
| | 4,576 |
|
| Escrow accounts | | 80,201 |
| | 32,447 |
|
| TOTAL | | 84,761 |
| | 37,023 |
|
| | | | | |
| UTILITY PLANT | | |
| | |
|
| Electric | | 5,672,589 |
| | 4,780,720 |
|
| Construction work in progress | | 88,373 |
| | 128,149 |
|
| TOTAL UTILITY PLANT | | 5,760,962 |
| | 4,908,869 |
|
| Less - accumulated depreciation and amortization | | 1,894,000 |
| | 1,641,821 |
|
| UTILITY PLANT - NET | | 3,866,962 |
| | 3,267,048 |
|
| | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
|
| Regulatory assets: | | |
| | |
|
| Other regulatory assets | | 377,972 |
| | 343,049 |
|
| Other | | 10,105 |
| | 3,638 |
|
| TOTAL | | 388,077 |
| | 346,687 |
|
| | | | | |
| TOTAL ASSETS | |
| $4,674,744 |
| |
| $3,946,804 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
| | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | |
| | | December 31, |
| | | 2022 | | 2021 |
| | | (In Thousands) |
| | | | |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | | $400,000 | | | $— | |
| | | | |
| Accounts payable: | | | | |
| Associated companies | | 60,532 | | | 42,929 | |
| Other | | 176,162 | | | 113,000 | |
| Customer deposits | | 89,668 | | | 86,167 | |
| Taxes accrued | | 124,905 | | | 106,273 | |
| | | | |
| Interest accrued | | 18,208 | | | 17,283 | |
| | | | |
| | | | |
| Other | | 38,908 | | | 36,731 | |
| TOTAL | | 908,383 | | | 402,383 | |
| | | | |
| NON-CURRENT LIABILITIES | | | | |
| Accumulated deferred income taxes and taxes accrued | | 780,030 | | | 720,097 | |
| Accumulated deferred investment tax credits | | 14,591 | | | 10,913 | |
| Regulatory liability for income taxes - net | | 202,058 | | | 212,445 | |
| | | | |
| Other regulatory liabilities | | 79,865 | | | 49,313 | |
| Asset retirement cost liabilities | | 7,797 | | | 10,315 | |
| Accumulated provisions | | 37,509 | | | 38,028 | |
| Pension and other postretirement liabilities | | 23,742 | | | 59,065 | |
| Long-term debt | | 1,931,096 | | | 2,179,989 | |
| Other | | 53,156 | | | 35,273 | |
| TOTAL | | 3,129,844 | | | 3,315,438 | |
| | | | |
| Commitments and Contingencies | | | | |
| | | | |
| | | | |
| | | | |
| EQUITY | | | | |
| Member's equity | | 2,037,190 | | | 1,839,568 | |
| Noncontrolling interest | | 3,347 | | | — | |
| TOTAL | | 2,040,537 | | | 1,839,568 | |
| | | | |
| TOTAL LIABILITIES AND EQUITY | | $6,078,764 | | | $5,557,389 | |
| | | | |
| See Notes to Financial Statements. | | | | |
|
| | | | | | | | |
| ENTERGY MISSISSIPPI, LLC |
| BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | | |
| | | December 31, |
| | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | |
| $— |
| |
| $150,000 |
|
| Accounts payable: | | |
| | |
|
| Associated companies | | 48,090 |
| | 42,928 |
|
| Other | | 94,729 |
| | 79,117 |
|
| Customer deposits | | 85,938 |
| | 85,085 |
|
| Taxes accrued | | 90,661 |
| | 77,552 |
|
| Interest accrued | | 18,900 |
| | 20,231 |
|
| Deferred fuel costs | | 70,402 |
| | — |
|
| Other | | 32,667 |
| | 7,526 |
|
| TOTAL | | 441,387 |
| | 462,439 |
|
| | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 594,832 |
| | 551,869 |
|
| Accumulated deferred investment tax credits | | 9,602 |
| | 10,186 |
|
| Regulatory liability for income taxes - net | | 236,988 |
| | 246,402 |
|
| Other regulatory liabilities | | 21,512 |
| | 33,622 |
|
| Asset retirement cost liabilities | | 9,727 |
| | 9,206 |
|
| Accumulated provisions | | 50,021 |
| | 51,142 |
|
| Pension and other postretirement liabilities | | 99,406 |
| | 93,100 |
|
| Long-term debt | | 1,614,129 |
| | 1,175,750 |
|
| Other | | 54,989 |
| | 20,862 |
|
| TOTAL | | 2,691,206 |
| | 2,192,139 |
|
| | | | | |
| Commitments and Contingencies | |
|
| |
|
|
| | | | | |
| EQUITY | | |
| | |
|
| Member's equity | | 1,542,151 |
| | 1,292,226 |
|
| TOTAL | | 1,542,151 |
| | 1,292,226 |
|
| | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $4,674,744 |
| |
| $3,946,804 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
| | | | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| For the Years Ended December 31, 2022, 2021, and 2020 |
| | | | | |
| | Noncontrolling Interest | | Member's Equity | | Total |
| | (In Thousands) |
| | | | | |
| Balance at December 31, 2019 | $— | | | $1,542,151 | | | $1,542,151 | |
| Net income | — | | | 140,583 | | | 140,583 | |
| | | | | |
| Common equity distributions | — | | | (10,000) | | | (10,000) | |
| | | | | |
| | | | | |
| Balance at December 31, 2020 | $— | | | $1,672,734 | | | $1,672,734 | |
| Net income | — | | | 166,834 | | | 166,834 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Balance at December 31, 2021 | $— | | | $1,839,568 | | | $1,839,568 | |
| Net income (loss) | (21,355) | | | 197,622 | | | 176,267 | |
| Capital contributions from noncontrolling interest | 24,702 | | | — | | | 24,702 | |
| | | | | |
| | | | | |
| | | | | |
| Balance at December 31, 2022 | $3,347 | | | $2,037,190 | | | $2,040,537 | |
| | | | | |
| See Notes to Financial Statements. | | | | | |
|
| | | |
ENTERGY MISSISSIPPI, LLC |
STATEMENTS OF CHANGES IN MEMBER'S EQUITY |
For the Years Ended December 31, 2019, 2018, and 2017 |
| |
| |
| Member's Equity |
| (In Thousands) |
| |
Balance at December 31, 2016 |
| $1,094,791 |
|
Net income | 110,032 |
|
Common equity distributions | (26,000 | ) |
Preferred stock dividends | (953 | ) |
Balance at December 31, 2017 |
| $1,177,870 |
|
Net income | 126,078 |
|
Common equity distributions | (10,000 | ) |
Preferred stock dividends | (834 | ) |
Other | (888 | ) |
Balance at December 31, 2018 |
| $1,292,226 |
|
Net income | 119,925 |
|
Capital contribution from parent | 130,000 |
|
Balance at December 31, 2019 |
| $1,542,151 |
|
| |
See Notes to Financial Statements. | |
|
|
| | | | | | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, LLC |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | |
| | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| | (In Thousands) |
| | | | | | | | | | |
| Operating revenues |
| $1,323,043 |
| |
| $1,335,112 |
| |
| $1,198,229 |
| |
| $1,094,649 |
| |
| $1,396,985 |
|
| Net income |
| $119,925 |
| |
| $126,078 |
| |
| $110,032 |
| |
| $109,184 |
| |
| $92,708 |
|
| Total assets |
| $4,674,744 |
| |
| $3,946,804 |
| |
| $3,879,375 |
| |
| $3,602,140 |
| |
| $3,477,407 |
|
| Long-term obligations (a) |
| $1,614,129 |
| |
| $1,175,750 |
| |
| $1,290,503 |
| |
| $1,141,924 |
| |
| $972,058 |
|
| | | | | | | | | | |
| (a) Includes long-term debt (excluding currently maturing debt), non-current capital lease obligations, and preferred stock without sinking fund. |
| | | | | | | | | | |
| | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| | (Dollars In Millions) |
| | | | | | | | | | |
| Electric Operating Revenues: | |
| | |
| | |
| | |
| | |
|
| Residential |
| $562 |
| |
| $579 |
| |
| $502 |
| |
| $459 |
| |
| $565 |
|
| Commercial | 444 |
| | 462 |
| | 423 |
| | 374 |
| | 465 |
|
| Industrial | 165 |
| | 175 |
| | 159 |
| | 134 |
| | 164 |
|
| Governmental | 44 |
| | 44 |
| | 41 |
| | 38 |
| | 47 |
|
| Total billed retail | 1,215 |
| | 1,260 |
| | 1,125 |
| | 1,005 |
| | 1,241 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | — |
| | 1 |
| | — |
| | 1 |
| | 75 |
|
| Non-associated companies | 39 |
| | 25 |
| | 18 |
| | 30 |
| | 10 |
|
| Other | 69 |
| | 49 |
| | 55 |
| | 59 |
| | 71 |
|
| Total |
| $1,323 |
| |
| $1,335 |
| |
| $1,198 |
| |
| $1,095 |
| |
| $1,397 |
|
| | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | |
| | |
| | |
| | |
|
| Residential | 5,659 |
| | 5,829 |
| | 5,308 |
| | 5,617 |
| | 5,661 |
|
| Commercial | 4,698 |
| | 4,865 |
| | 4,783 |
| | 4,894 |
| | 4,913 |
|
| Industrial | 2,443 |
| | 2,559 |
| | 2,536 |
| | 2,493 |
| | 2,283 |
|
| Governmental | 436 |
| | 438 |
| | 421 |
| | 439 |
| | 433 |
|
| Total retail | 13,236 |
| | 13,691 |
| | 13,048 |
| | 13,443 |
| | 13,290 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | — |
| | — |
| | — |
| | — |
| | 1,419 |
|
| Non-associated companies | 1,776 |
| | 1,060 |
| | 857 |
| | 1,021 |
| | 261 |
|
| Total | 15,012 |
| | 14,751 |
| | 13,905 |
| | 14,464 |
| | 14,970 |
|
ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
20192022 Compared to 20182021
Net Income
Net income decreased $0.5increased $32.3 million primarily due to lowerhigher retail electric price and higher volume/weather, partially offset by higher other operation and maintenance expenses, a higher effective income tax rate, substantially offset by higher taxes other than income taxes, and lower other operation and maintenance expenses.higher interest expense.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 20192022 to 2018.
|
| | | | |
| Amount |
| (In Millions) |
| 2021 operating revenues | $768.9 | |
2018 operating revenues |
| $717.4 |
|
| Fuel, rider, and other revenues that do not significantly affect net income | (37.4147.7 | ) |
| Retail electric price | (5.542.2 | ) |
| Volume/weather | 1.825.8 |
|
Return of unprotected excess accumulated deferred income taxes to customersRetail gas price | 9.912.7 |
|
20192022 operating revenues |
| $686.2 |
|
Entergy New Orleans’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.
The retail electric price variance is primarily due to a provision for rate refund recordedincreases effective November 2021 and September 2022, each in fourth quarter 2019 as a resultaccordance with the terms of the 2018 combined2021 and 2022 formula rate case resolution approved by the City Council.plan filings. See Note 2 to the financial statements for further discussion of the formula rate case resolution.plan filings.
The volume/weather variance is primarily due to an increase in weather-adjusted residential usage, duringan increase in commercial usage, and the unbilled sales period.effect of more favorable weather on residential sales. The increase in weather-adjusted residential usage was primarily due to the effect of Hurricane Ida in 2021. The increase in commercial usage was primarily due to the effect of the COVID-19 pandemic on businesses in 2021.
The return of unprotected excess accumulated deferred income taxes to customersretail gas price variance is primarily due to a decreaserate increase effective November 2021 in accordance with the returnterms of unprotected excess accumulated deferred income taxes through the fuel adjustment clause. In 2019, $2.1 million was returned to customers as compared to $12 million in 2018. There is no effect on net income as the reduction in operating revenues in each period is offset by a reduction in income tax expense.2021 formula rate plan filing. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act.
Other Income Statement Variances
Other operation and maintenance expenses decreased primarily due to:
a decrease of $9.2 million as a result of the deferral in 2019 of 2018 costs related to theformula rate case and a system conversion for Algiers customers as a result of the 2018 combined rate case resolution approved by the City
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Council. | | | | | | | | | | | | | | | | | |
| 2022 | | 2021 | | % Change |
| (GWh) | |
| Residential | 2,410 | | | 2,221 | | | 9 | |
| Commercial | 2,096 | | | 1,963 | | | 7 | |
| Industrial | 411 | | | 413 | | | — | |
| Governmental | 789 | | | 750 | | | 5 | |
| Total retail | 5,706 | | | 5,347 | | | 7 | |
| Sales for resale: | | | | | |
| Non-associated companies | 2,298 | | | 2,369 | | | (3) | |
| Total | 8,004 | | | 7,716 | | | 4 | |
See Note 19 to the financial statements for additional discussion of Entergy New Orleans’s operating revenues.
Other Income Statement Variances
Other operation and maintenance expenses increased primarily due to:
•an increase of $10.4 million in power delivery expenses primarily due to higher reliability costs, partially offset by a decrease in meter reading expenses as a result of the deployment of advanced metering systems;
•an increase of $3.3 million in bad debt expense resulting from the COVID-19 pandemic, including the deferral in 2021 of bad debt expense. See Note 2 to the financial statements for further discussion of regulatory activity associated with the rate case resolution;COVID-19 pandemic; and
•an increase of $2.1 million in loss provisions.
The increase was partially offset by a decrease of $2.9$5.9 million in distributionnon-nuclear generation expenses primarily due to a lower contract labor costs.scope of work performed in 2022, including during plant outages, as compared to 2021.
The decrease was partially offset by:
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 costsTaxes other than income taxes increased primarily due to increases in local franchise taxes and increases in ad valorem taxes resulting from higher software maintenance costsassessments.
Depreciation and higher contract costs;
an increase of $2 million in customer service costsamortization expenses increased primarily due to higher labor costs, including contract labor; andadditions to plant in service.
an increase of $1.8 million in energy efficiency costs.
Other incomeInterest expense increased primarily due to:to the issuance of $90 million of 4.19% Series mortgage bonds and the issuance of $70 million of 4.51% Series mortgage bonds, each in November 2021.
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.
|
The effective income tax rates were 0.4%27.5% for 20192022 and (4.8%) for 2018. The differences in the effective income tax rates versus the federal statutory rate of 21% for 2019 and 2018 were primarily due to the amortization of excess accumulated deferred income taxes.15.7% for 2021. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates.rates, and for additional discussion regarding income taxes.
20182021 Compared to 2017
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy New Orleans’s Annual Report on Form 10-K for the year ended December 31, 20182021, filed with the SEC on February 25, 2022, for discussion of results of operations for 20182021 compared to 2017.2020.
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Income Tax Legislation
See the “Income Tax Legislation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the Tax CutsInflation Reduction Act of 2022.
Liquidity and Jobs Act,Capital Resources
Cash Flow
Cash flows for the federal income tax legislation enactedyears ended December 31, 2022, 2021, and 2020 were as follows:
| | | | | | | | | | | | | | | | | |
| | 2022 | | 2021 | | 2020 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period | $42,862 | | | $26 | | | $6,017 | |
| | | | | |
| Net cash provided by (used in): | | | | | |
| Operating activities | 363,763 | | | 78,808 | | | 64,024 | |
| Investing activities | (403,790) | | | (169,920) | | | (220,845) | |
| Financing activities | 1,629 | | | 133,948 | | | 150,830 | |
| Net increase (decrease) in cash and cash equivalents | (38,398) | | | 42,836 | | | (5,991) | |
| | | | | |
| Cash and cash equivalents at end of period | $4,464 | | | $42,862 | | | $26 | |
2022 Compared to 2021
Operating Activities
Net cash flow provided by operating activities increased $285 million in 2022 primarily due to:
•net proceeds of $201.8 million received from the LURC in December 2017. Note 3 to the financial statements contains additional discussion of the effect of the Act on 2017, 2018, and 2019 results of operations and financial position, the provisions of the Act, and the uncertainties associated with accounting for the Act, and2022 from securitization. See Note 2 to the financial statements discusses the regulatory proceedings that have considered the effectsfor discussion of the Act.storm securitization;
•the timing of payments to vendors.
The increase was partially offset by increased fuel costs, including the timing of recovery of fuel and purchased power costs. See Note 2 to the financial statements for discussion of fuel and purchased power cost recovery.
Investing Activities
Net cash flow used in investing activities increased $233.9 million in 2022 primarily due to:
•a net payment to the storm reserve escrow account of $75 million in 2022 compared to net receipts of $83 million from the storm reserve escrow account in 2021;
•an increase of $16.3 million in transmission construction expenditures primarily due to a higher scope of work on projects performed in 2022 as compared to 2021; and
•money pool activity.
The increase was partially offset by:
•a decrease of $8.5 million in non-nuclear generation construction expenditures primarily due to a lower scope of work on projects performed, including during plant outages, in 2022 as compared to 2021; and
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2019, 2018, and 2017 were as follows:
|
| | | | | | | | | | | |
| | 2019 | | 2018 | | 2017 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $19,677 |
| |
| $32,741 |
| |
| $103,068 |
|
| | | | | | |
| Net cash provided by (used in): | |
| | |
| | |
|
| Operating activities | 115,604 |
| | 171,778 |
| | 127,797 |
|
| Investing activities | (204,310 | ) | | (207,616 | ) | | (109,500 | ) |
| Financing activities | 75,046 |
| | 22,774 |
| | (88,624 | ) |
| Net decrease in cash and cash equivalents | (13,660 | ) |
| (13,064 | ) |
| (70,327 | ) |
| | | | | | |
| Cash and cash equivalents at end of period |
| $6,017 |
|
|
| $19,677 |
|
|
| $32,741 |
|
2019 Compared to 2018
Operating Activities
Net cash flow provided by operating activities decreased $56.2 million in 2019 primarily due to •a decrease of $34.5 million in 2019 of income tax refunds and the timing of collection of receivables from customers. Entergy New Orleans had income tax refunds in 2019 and 2018 in accordance with an intercompany income tax allocation agreement. The income tax refunds resulted from the utilization of Entergy New Orleans’s net operating loss.
Investing Activities
Net cash flow used in investing activities decreased $3.3 million in 2019 primarily due to money pool activity. The decrease was substantially offset by:
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$6.4 million in distribution construction expenditures primarily due to lower capital expenditures for storm restoration in 2022 and lower spending on advanced metering infrastructure, partially offset by increased investment in the reliability and infrastructure of Entergy New Orleans’s distribution system, including increasedsystem. The decrease in storm restoration spending on advanced metering infrastructure.is primarily due to Hurricane Zeta and Hurricane Ida restoration efforts. See “Hurricane Zeta” and “Hurricane Ida” below for discussion of storm restoration efforts.
DecreasesIncreases in Entergy New Orleans’s receivable from the money pool are a sourceuse of cash flow, and Entergy New Orleans’s receivable from the money pool decreased by $16.8increased $110.8 million in 20192022 compared to increasing by $9.3$36.4 million in 2018.2021. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Financing Activities
Net cash flow provided by financing activities increased $52.3decreased $132.3 million in 2022 primarily due to:
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
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
net borrowings of $20 million in 2019 on Entergy New Orleans’s credit facility.
The increase was partially offset byto the issuance of $60$90 million of 4.19% Series mortgage bonds and the issuance of $70 million of 4.51% Series mortgage bonds, each in September 2018.November 2021. The decrease was partially offset by a $15 million advance received in 2022 in anticipation of Entergy New Orleans’s construction of a New Orleans Sewerage and Water Board substation and money pool activity.
Decreases in Entergy New Orleans’s payable to the money pool are a use of cash flow, and Entergy New Orleans’s payable to the money pool decreased $10.2 million in 2021.
See Note 5 to the financial statements for details on long-term debt.
20182021 Compared to 2017
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy New Orleans’s Annual Report on Form 10-K for the year ended December 31, 20182021 filed with the SEC on February 25, 2022 for discussion of operating, investing, and financing cash flow activities for 20182021 compared to 2017.2020.
Capital Structure
Entergy New Orleans’s debt to capital ratio is shown in the following table. The increasedecrease in the debt to capital ratio is primarily due to the issuance of long-term debtan increase in 2019. equity resulting from retained earnings in 2022.
| | | | | | | | | | | |
| December 31,
2022 | | December 31,
2021 |
| Debt to capital | 52.6 | % | | 55.4 | % |
| Effect of excluding securitization bonds | (0.6 | %) | | (1.0 | %) |
| Debt to capital, excluding securitization bonds (non-GAAP) (a) | 52.0 | % | | 54.4 | % |
| Effect of subtracting cash | (0.1 | %) | | (1.4 | %) |
| Net debt to net capital, excluding securitization bonds (non-GAAP) (a) | 51.9 | % | | 53.0 | % |
|
| | | | | |
| | December 31,
2019 | | December 31,
2018 |
| Debt to capital | 53.1 | % | | 52.1 | % |
| Effect of excluding securitization bonds | (2.4 | %) | | (3.5 | %) |
| Debt to capital, excluding securitization bonds (a) | 50.7 | % | | 48.6 | % |
| Effect of subtracting cash | (0.3 | %) | | (1.2 | %) |
| Net debt to net capital, excluding securitization bonds (a) | 50.4 | % | | 47.4 | % |
(a)Calculation excludes the securitization bonds, which are non-recourse to Entergy New Orleans.
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, long-term debt, including the currently maturing portion, and the long-term payable due to an associated company. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. The debt to capital ratio excluding securitization bonds and net debt to net capital ratio excluding securitization bonds are non-GAAP measures. Entergy New Orleans uses the debt to capital ratios excluding
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy New Orleans’s financial condition because the securitization bonds are non-recourse to Entergy New Orleans, as more fully described in Note 5 to the financial statements. Entergy New Orleans also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy New Orleans’s financial condition because net debt indicates Entergy New Orleans’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy New Orleans seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a distribution, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy New Orleans may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reducing distributions, Entergy New Orleans may receive equity contributions to maintain its capital structure.
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Uses of Capital
Entergy New Orleans requires capital resources for:
•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.
Following are the amounts of Entergy New Orleans’s planned construction and other capital investments.
| | | | | | | | | | | | | | | | | |
| | 2023 | | 2024 | | 2025 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation | $— | | | $20 | | | $25 | |
| Transmission | 15 | | | 15 | | | 15 | |
| Distribution | 110 | | | 160 | | | 145 | |
| Utility Support | 15 | | | 15 | | | 20 | |
| Total | $140 | | | $210 | | | $205 | |
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy New Orleans includes investments in generation projects to modernize, decarbonize, and diversify Entergy New Orleans’s portfolio; distribution and Utility support spending to deliver reliability, resilience, and customer experience; transmission spending to drive reliability and resilience while also supporting renewables expansion; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, government actions, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.
|
| | | | | | | | | | | |
| | 2020 | | 2021 | | 2022 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation |
| $70 |
| |
| $15 |
| |
| $15 |
|
| Transmission | 10 |
| | 20 |
| | 25 |
|
| Distribution | 90 |
| | 80 |
| | 40 |
|
| Utility Support | 65 |
| | 40 |
| | 70 |
|
| Total |
| $235 |
| |
| $155 |
| |
| $150 |
|
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy New Orleans’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations..
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2023 | | 2024 | | 2025 | | 2026-2027 | | After 2027 |
| | (In Millions) |
| Long-term debt (a) | $211 | | | $32 | | | $101 | | | $125 | | | $767 | |
| Operating leases (b) | $2 | | | $2 | | | $1 | | | $1 | | | $1 | |
| Finance leases (b) | $1 | | | $1 | | | $1 | | | $1 | | | $1 | |
|
| | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2021-2022 | | 2023-2024 | | After 2024 | | Total |
| | (In Millions) |
| Long-term debt (a) |
| $62 |
| |
| $159 |
| |
| $153 |
| |
| $612 |
| |
| $986 |
|
| Operating leases (b) |
| $1 |
| |
| $2 |
| |
| $1 |
| |
| $— |
| |
| $4 |
|
| Finance leases (b) |
| $1 |
| |
| $1 |
| |
| $1 |
| |
| $1 |
| |
| $4 |
|
| Purchase obligations (c) |
| $224 |
| |
| $459 |
| |
| $448 |
| |
| $3,602 |
| |
| $4,733 |
|
| |
(a) | Includes estimated interest payments. (a)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. |
In addition to the contractualfinancial statements.
(b)Lease obligations given above, are discussed in Note 10 to the financial statements.
Other Obligations
Entergy New Orleans currently expects to contribute approximately $3.2$1.4 million to its qualified pension plan and approximately $162$193 thousand to other postretirement health care and life insurance plans in 2020,2023, although the 20202023 required pension contributions will be known with more certainty when the January 1, 20202023 valuations are completed, which is expected by April 1, 2020.2023. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Also in addition to the contractual obligations, Entergy New Orleans has $271.3$182.8 million of unrecognized tax benefits and interest net of unused tax attributes and paymentsplus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition, to routine capital spending to maintain operations, the planned capital investment estimate for Entergy New Orleans includes specific investments such as the New Orleans Power Stationenters into fuel and New Orleans Solar
purchased power agreements that contain minimum purchase obligations. Entergy New Orleans LLChas rate mechanisms in place to recover fuel, purchased power, and Subsidiaries
Management’s Financial Discussion and Analysis
Station; transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including advanced meters and related investments; system improvements; software and security; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital. Management provides more information on long-term debt and preferred stock maturities in Notes 5 and 6associated costs incurred under these purchase obligations. See Note 8 to the financial statements.statements for discussion of Entergy New Orleans’s obligations under the Unit Power Sales Agreement.
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy New Orleans pays distributions from its earnings at a percentage determined monthly.
New Orleans Power Station
In March 2018 the City Council adopted a resolution approving construction of the New Orleans Power Station, a 128 MW unit composed of natural gas-fired reciprocating engines, and a related cost recovery plan. The cost estimate for the plant, which will be located at the site of the Michoud generating facility that was retired in May 2016, is $210 million. Entergy New Orleans had previously filed an application with the City Council seeking a public interest determination and authorization to construct a 226 MW advanced combustion turbine power station. In January 2017 several intervenors filed testimony opposing the construction of the New Orleans Power Station on various grounds. In July 2017, Entergy New Orleans submitted a supplemental and amending application to the City Council seeking approval to construct either the originally proposed 226 MW advanced combustion turbine power station, or alternatively, the 128 MW power station. In addition, the application renewed the commitment to pursue up to 100 MW of renewable resources to serve New Orleans.
In April 2018 intervenors opposing the construction of the New Orleans Power Station filed with the City Council a request for rehearing, which was subsequently denied, and a petition for judicial review of the City Council’s decision, and also filed a lawsuit challenging the City Council’s approval based on Louisiana’s open meeting law. In May 2018 the City Council announced that it would initiate an investigation into allegations that Entergy New Orleans, Entergy, or some other entity paid or participated in paying certain attendees and speakers in support of the New Orleans Power Station to attend or speak at certain meetings organized by the City Council. In October 2018 investigators for the City Council released their report, concluding that individuals were paid to attend or speak in support of the New Orleans Power Station and that Entergy New Orleans “knew or should have known that such conduct occurred or reasonably might occur.” The City Council issued a resolution requiring Entergy New Orleans to show cause why it should not be fined $5 million as a result of the findings in the report. In November 2018, Entergy New Orleans submitted its response to the show cause resolution, disagreeing with certain characterizations and omissions of fact in the report and asserting that the City Council could not legally impose the proposed fine. Simultaneous with the filing of its response to the show cause resolution, Entergy New Orleans sent a letter to the City Council re-asserting that the City Council’s imposition of the proposed fine would be unlawful, but acknowledging that the actions of a subcontractor, which was retained by an Entergy New Orleans contractor without the knowledge or contractually-required consent of Entergy New Orleans, were contrary to Entergy’s values. In that letter, Entergy New Orleans offered to donate $5 million to the City Council to resolve the show cause proceeding. In January 2019, Entergy New Orleans submitted a new settlement proposal to the City Council. The proposal retains the components of the first offer but adds to it a commitment to make reasonable efforts to limit the costs of the project to the $210 million cost estimate with advanced notification of anticipated cost overruns, additional reporting requirements for cost and environmental items, and a commitment regarding reliability investment and to work with the New Orleans Sewerage and Water Board to provide a reliable source of power. In February 2019 the City Council approved a resolution approving the settlement proposal and allowing the construction of the New Orleans Power Station to commence.
Also in February 2019 certain intervenors in the City Council proceeding on the New Orleans Power Station filed suit in Louisiana state court challenging the Louisiana Department of Environmental Quality’s issuance of the New Orleans Power Station’s air permit. Entergy New Orleans intervened in that lawsuit and, along with the Louisiana
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Department of Environmental Quality, filed exceptions seeking dismissal of the lawsuit. In June 2019 the state court judge sustained the exceptions and dismissed the plaintiffs’ petition with prejudice.
Also in June 2019, a state court judge in New Orleans affirmed the City Council’s approval of the New Orleans Power Station and dismissed the petition for judicial review that had been filed in April 2018. The petitioners have filed an appeal of that ruling. Also in June 2019, with regard to the lawsuit challenging the City Council’s decision on the basis of a violation of the open meetings law, the same state court judge in New Orleans ruled that there was a violation of the open meetings law at the February 2018 meeting of the City Council’s Utility Committee at which that Committee considered the New Orleans Power Station approval, and further ruled that, although there was no violation of the open meetings law at the March 2018 full City Council meeting at which the New Orleans Power Station was approved, both the approval of the Utility Committee and the approval of the full City Council were void. The City Council and Entergy New Orleans each filed a suspensive appeal of the open meetings law ruling. A suspensive appeal suspends the effect of the judgment in the open meetings law proceeding while the appeal is being taken. The petitioners sought in the state appellate court, and then at the Louisiana Supreme Court, to terminate the suspension of the effect of the judgment, but both courts declined to do so. Appellate briefing on the merits both in the open meetings law appeal and in the judicial review appeal occurred in November and December 2019 and oral argument in both cases was heard in January 2020. In February 2020 the state appellate court reversed the lower court’s ruling that the City Council’s approval of the New Orleans Power Station was void due to a violation of the open meetings law at the City Council’s Utility Committee meeting in February 2018. The state appellate court ruled that there was no violation of the open meetings law at the full City Council meeting in March 2018 and that the lower court erred in voiding the City Council resolution approving the New Orleans Power Station. The appellate court’s decision on the appeal of the judicial review decision that affirmed the City Council’s approval of the New Orleans Power Station as in the public interest is still pending. Construction of the plant is on schedule, with commercial operation expected in mid-2020.
Gas Infrastructure Rebuild Plan
In September 2016, Entergy New Orleans submitted to the City Council a request for authorization for Entergy New Orleans to proceed with annual incremental capital funding of $12.5 million for its gas infrastructure rebuild plan, which would replace all of Entergy New Orleans’s low pressure cast iron, steel, and vintage plastic pipe over a ten-year period commencing in 2017. Entergy New Orleans also proposed that recovery of the investment to fund its gas infrastructure replacement plan be determined in connection with its next base rate case. The City Council authorized Entergy New Orleans to proceed with its replacement plans and established a schedule for proceedings in advance of the rate case intended to provide an opportunity for evaluation of the gas infrastructure plan that would best serve the public interest and the effect on customers of the approval of any such plan. In the course of that proceeding, the City Council’s advisors submitted pre-filed testimony recommending that Entergy New Orleans be allowed to continue with its condition-based approach to gas pipeline replacement to replace approximately 238 miles of low pressure pipe at a rate of approximately 25 miles per year. The City Council’s advisors also recommended that Entergy New Orleans be required to adhere to certain reporting requirements and recognized the need to address the sustained level of investment in gas infrastructure on customer bills. In September 2017, Entergy New Orleans filed rebuttal testimony suggesting that its recovery of future investment and customer effects would be addressed in the rate case that Entergy New Orleans was required to file in July 2018. The procedural schedule was suspended in order to allow for resolution in the rate case proceeding. As a result of the rate case, the City Council approved the planned gas rebuild expenditures through 2019, but rejected Entergy New Orleans’s proposed gas infrastructure rider. Entergy New Orleans is required to submit a gas infrastructure rebuild plan to the City Council in March 2020 and to convene a working group to explore appropriate cost mitigation measures.
Renewables
In July 2018, Entergy New Orleans filed an application with the City Council requesting approval of three utility-scale solar projects totaling 90 MW. If approved, theThe resource additions will allow Entergy New Orleans to make significant progress towards meeting its voluntary commitment to the City Council to add up to 100 MW of renewable energy resources. The three projects include constructing a self-build solar plant in Orleans Parish with an
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
output of 20 MW, acquiring a 50 MW solar facility in Washington Parish through a build-own-transfer acquisition, and procuring 20 MW of solar power from a project to be built in St. James Parish through a power purchase agreement. In December 2018 the City Council advisors requested that Entergy New Orleans pursue alternative deal structures for the Washington Parish project and attempt to reduce costs for the 20 MW New Orleans Solar Station. As a result of settlement discussions, in March 2019, Entergy New Orleans revised its application to convert the build-own transfer acquisition of the 50 MW facility in Washington Parish to a power purchase agreement. In June 2019 the parties to the proceeding executed a stipulated settlement term sheet, which recommends that the City Council approve Entergy New Orleans’s revised application as to all three projects. In July 2019 the City Council approved the stipulated settlement. Commercial operation of the 20 MW New Orleans Solar Station commenced in December 2020. In November 2022 Entergy New Orleans began receiving power under the 50 MW Iris Solar power purchase agreement. Due to a delay resulting from Hurricane Ida, Entergy New
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Orleans now expects to begin receiving power under the 20 MW St. James Solar power purchase agreement in the first half of 2023.
System Resilience and Storm Hardening
In October 2021 the City Council passed a resolution and order establishing a docket and procedural schedule with respect to system resiliency and storm hardening. The docket will identify a plan for storm hardening and resiliency projects with other stakeholders. In July 2022, Entergy New Orleans filed with the City Council a response identifying a preliminary plan for storm hardening and resiliency projects, including microgrids, to be implemented over 10 years at an approximate cost of $1.5 billion. In February 2023 the City Council approved a revised procedural schedule requiring Entergy New Orleans to make a filing in April 2023 containing a narrowed list of proposed hardening projects, with final comments on that filing due July 2023.
Sources of Capital
Entergy New Orleans’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•the Entergy System money pool;
•storm reserve escrow accounts;
•debt and preferred membership interest issuances;issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations, Entergy New Orleans may refinance, redeem, or otherwiseexpects to continue, when economically feasible, to retire higher-cost debt prior to maturity, to the extentand replace it with lower-cost debt if market conditions and interest rates are favorable.permit.
All debt and common and preferred membership interest issuances by Entergy New Orleans require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in its bond indenturesindenture and other agreements. Entergy New Orleans has sufficient capacity under these tests to meet its foreseeable capital needs.needs for the next twelve months and beyond.
Entergy New Orleans’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
| | | | | | | | | | | | | | | | | | | | |
| 2022 | | 2021 | | 2020 | | 2019 |
| (In Thousands) |
| $147,254 | | $36,410 | | ($10,190) | | $5,191 |
|
| | | | | | |
| 2019 | | 2018 | | 2017 | | 2016 |
| (In Thousands) |
| $5,191 | | $22,016 | | $12,723 | | $14,215 |
See Note 4 to the financial statements for a description of the money pool.
Entergy New Orleans has a credit facility in the amount of $25 million scheduled to expire in November 2021.June 2024. The credit facility includes fronting commitments for the issuance of letters of credit against $10 million of the borrowing capacity of the facility. As of December 31, 2019,2022, there were $20 million ofno cash borrowings and a $0.8 million letterno letters of credit outstanding under the credit facility. In addition, Entergy New Orleans is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2019,2022, a $5.6$1 million
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
letter of credit was outstanding under Entergy New Orleans’s uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.
Entergy New Orleans obtained authorization from the FERC through October 20212023 for short-term borrowings not to exceed an aggregate amount of $150 million at any time outstanding and long-term borrowings and securities issuances. See Note 4 to the financial statements for further discussion of Entergy New Orleans’s short-term borrowing limits. The long-term securities issuances of Entergy New Orleans are limited to amounts authorized not only by the FERC, but also by the City Council, and the current City Council authorization extends through December 2023.
Entergy New Orleans had $75 million in its storm reserve escrow account at December 31, 2022.
Hurricane Zeta
In October 2021.2020, Hurricane Zeta caused significant damage to Entergy New Orleans’s service area. The storm resulted in widespread power outages, significant damage to distribution and transmission infrastructure, and the loss of sales during the power outages. In March 2021, Entergy New Orleans withdrew $44 million from its funded storm reserves. In May 2021, Entergy New Orleans filed an application with the City Council requesting approval and certification that its system restoration costs associated with Hurricane Zeta of approximately $36 million, which included $7 million in estimated costs, were reasonable and necessary to enable Entergy New Orleans to restore electric service to its customers and Entergy New Orleans’s electric utility infrastructure. In May 2022 the City Council advisors issued a report recommending that the City Council find that Entergy New Orleans acted prudently in restoring service following Hurricane Zeta and approximately $33 million in storm restoration costs were prudently incurred and recoverable. Additionally, the advisors concluded that approximately $7 million of the $44 million withdrawn from its funded storm reserve was in excess of Entergy New Orleans’s costs and should be considered in Entergy New Orleans’s application for certification of costs related to Hurricane Ida. In September 2022 the City Council issued a resolution finding that Entergy New Orleans’s system restoration costs were reasonable and necessary, and that Entergy New Orleans acted prudently in restoring electricity following Hurricane Zeta. The City Council also found that approximately $33 million in storm costs were recoverable.
Hurricane Ida
In August 2021, Hurricane Ida caused significant damage to Entergy New Orleans’s service area, including Entergy’s electrical grid. The storm resulted in widespread power outages, including the loss of 100% of Entergy New Orleans’s load and damage to distribution and transmission infrastructure, including the loss of connectivity to the eastern interconnection. In September 2021, Entergy New Orleans withdrew $39 million from its funded storm reserves. In June 2022, Entergy New Orleans filed an application with the City Council requesting approval and certification that storm restoration costs associated with Hurricane Ida of approximately $170 million, which included $11 million in estimated costs, were reasonable, necessary, and prudently incurred to enable Entergy New Orleans to restore electric service to its customers and to repair Entergy New Orleans’s electric utility infrastructure. In addition, estimated carrying costs through December 2022 related to Hurricane Ida restoration costs were $9 million. Also, Entergy New Orleans is requesting approval that the $39 million withdrawal from its funded storm reserve in September 2021 and $7 million in excess storm reserve escrow withdrawals related to Hurricane Zeta and prior miscellaneous storms are properly applied to Hurricane Ida storm restoration costs, the application of which reduces the amount to be recovered from Entergy New Orleans customers by $46 million. In November 2022 the City Council adopted a procedural schedule regarding the certification of the Hurricane Ida storm restoration costs in which the hearing officer shall certify the record for City Council consideration no later than August 2023.
Additionally, in February 2022, Entergy New Orleans and the LURC filed with the City Council a securitization application requesting that the City Council review Entergy New Orleans’s storm reserve and increase the storm reserve funding level to $150 million, to be funded through securitization. In August 2022 the City
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Council’s advisors recommended that the City Council authorize a single securitization bond issuance to fund Entergy New Orleans’s storm recovery reserves to an amount sufficient to: (1) allow recovery of all of Entergy New Orleans’s unrecovered storm recovery costs following Hurricane Ida, subject to City Council review and certification; (2) provide initial funding of storm recovery reserves for future storms to a level of $75 million; and (3) fund the storm recovery bonds’ upfront financing costs. In September 2022, Entergy New Orleans and the City Council’s advisors entered into an agreement in principle, which was approved by the City Council along with a financing order in October 2022, authorizing Entergy New Orleans and the LURC to proceed with a single securitization bond issuance of approximately $206 million (subject to further adjustment and review pursuant to the Final Issuance Advice Letter process set forth in the financing order), with $125 million of that total to be used for interim recovery, subject to City Council review and certification, to be allocated to unrecovered Hurricane Ida storm recovery costs; $75 million of that total to provide for a storm recovery reserve for future storms; and the remainder to fund the recovery of the storm recovery bonds’ upfront financing costs.
In December 2022, Entergy New Orleans and the LURC filed with the City Council the Final Issuance Advice Letter for a securitization bond issuance in the amount of $209.3 million, the final structuring, terms, and pricing of which were approved by the City Council in accordance with the financing order. Also in December 2022, the LCDA issued $209.3 million in bonds pursuant to the Louisiana Electric Utility Storm Recovery Securitization Act, Part V-B of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana Regular Session of 2021. The LCDA loaned $201.8 million of bond proceeds, net of certain debt service and issuance costs, to the LURC. The LURC used the proceeds to purchase from Entergy New Orleans the storm recovery property, which is the right to collect storm recovery charges sufficient to pay the storm recovery bonds and associated financing costs, and Entergy New Orleans deposited $200 million in a restricted storm reserve escrow account as a storm damage reserve for Entergy New Orleans and received directly $1.8 million in estimated upfront financing costs. Subsequently, Entergy New Orleans withdrew $125 million from the newly securitized storm reserve to cover Hurricane Ida storm recovery costs, subject to a final determination from the City Council regarding the prudency of the storm recovery costs.
Entergy and Entergy New Orleans do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA, and there is no recourse against Entergy or Entergy New Orleans in the event of a bond default. To service the bonds, Entergy New Orleans collects a storm recovery charge on behalf of the LURC and remits the collections to the bond indenture trustee. Entergy and Entergy New Orleans do not report the collections as revenue because Entergy New Orleans is merely acting as the billing and collection agent for the LURC.
State and Local Rate Regulation
The rates that Entergy New Orleans charges for electricity and natural gasits services significantly influence its financial position, results of operations, and liquidity. Entergy New Orleans is regulated, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the City Council, is primarily responsible for approval of the rates charged to customers.
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.2018 Base Rate Case
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.
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
customers residing in the remainder of Orleans Parish through a three-year phase-in; (2) contemporaneous cost recovery riders for investments in energy efficiency/demand response, incremental changes in capacity/long-term service agreement costs, grid modernization investment, and gas infrastructure replacement investment; and (3) formula rate plans for both electric and gas operations. In February 2019 the City Council’s advisors and several intervenors filed testimony in response to Entergy New Orleans’s application. The City Council’s advisors recommended, among other things, overall rate reductions of approximately $33 million in electric rates and $3.8 million in gas rates. Certain intervenors recommended overall rate reductions of up to approximately $49 million in electric rates and $5 million in gas rates. An evidentiary hearing was held in June 2019, and the record and post-hearing briefs were submitted in July 2019.
In October 2019 the City Council’s Utility Committee approved a resolution for a change in electric and gas rates for consideration by the full City Council that included a 9.35% return on common equity, an equity ratio of the lesser of 50% or Entergy New Orleans’s actual equity ratio, and a total reduction in revenues that Entergy New Orleans initially estimated to be approximately $39 million ($36 million electric; $3 million gas). At its November 7, 2019 meeting, the full City Council approved the resolution that had previously been approved by the City Council’s Utility Committee. Based on the approved resolution, in the fourth quarter 2019 Entergy New Orleans recorded an accrual of $10 million that reflects the estimate of the revenue billed in 2019 to be refunded to customers in 2020 based on an August 2019 effective date for the rate decrease. Entergy New Orleans also recorded a total of $12 million in regulatory assets for rate case costs and information technology costs associated with integrating Algiers customers with Entergy New Orleans’s legacy system and records. Entergy New Orleans will also transferredbe allowed to recover $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)(1) a provision for forward-looking adjustments to include known and measurable changes realized up to 12 months after the evaluation period; 2)(2) a decoupling mechanism; and 3)(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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Management’s Financial Discussion and Analysis
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 implementimplemented the new rates byin April 2020. The merits
Commercial operation of the appeal will be subject to a separate procedural scheduleNew Orleans Power Station commenced in May 2020. In accordance with the City Council resolution issued byin the Civil District Court.
Advanced Metering Infrastructure (AMI)
In October 2016,2018 base rate case proceeding, Entergy New Orleans filed an application seeking a finding fromhad been deferring the City Council that Entergy New Orleans’s deployment of advanced electric and gas metering infrastructure is in the public interest. Entergy New Orleans proposedPower Station non-fuel costs pending the conclusion of the appellate proceedings. In October 2020 the Louisiana Supreme Court denied all writ applications relating 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 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.Power Station. With those denials, Entergy New Orleans began deployment of AMI during the first quarter of 2019 and expects to complete deployment by the end ofrecovering New Orleans Power Station costs in rates in November 2020. Entergy New Orleans will recoveris recovering the undepreciated balancecosts over a five-year period that began in November 2020. As of its existing meters through aDecember 31, 2022, the regulatory asset to be amortized on a straight-line basis over 12 years, asfor the deferral of New Orleans Power Station non-fuel costs was $2.9 million.
2020 Formula Rate Plan Filing
Entergy New Orleans’s first annual filing under the three-year formula rate plan approved by the City Council.
Internal Restructuring
In July 2016, Entergy New OrleansCouncil in November 2019 was originally due to be filed an application within April 2020. The authorized return on equity under the approved three-year formula rate plan is 9.35% for both electric and gas operations. The City Council 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. Entergy New Orleans began crediting retail customers
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several extensions of the deadline to allow additional time to assess the effects of the COVID-19 pandemic on the New Orleans community, Entergy New Orleans customers, and Entergy New Orleans itself. In October 2020 the City Council approved an agreement in June 2017. In June 2017principle filed by Entergy New Orleans that results in Entergy New Orleans foregoing its 2020 formula rate plan filing and shifting the FERC approved the transactionthree-year formula rate plan to filings in 2021, 2022, and pursuant to2023. Key provisions of the agreement in principle include: changing the lower of actual equity ratio or 50% equity ratio approved in the rate case to a hypothetical capital structure of 51% equity and 49% debt for the duration of the three-year formula rate plan; changing the 2% depreciation rate for the New Orleans Power Station approved in the rate case to 3%; retention of over-recovery of $2.2 million in rider revenues; recovery of $1.4 million of certain rate case expenses outside of the earnings band; recovery of the New Orleans Solar Station costs upon commercial operation; and Entergy New Orleans’s dismissal of its 2018 rate case appeal.
2021 Formula Rate Plan Filing
In July 2021, Entergy New Orleans submitted to the City Council its formula rate plan 2020 test year filing. The 2020 test year evaluation report produced an earned return on equity of 6.26% compared to the authorized return on equity of 9.35%. Entergy New Orleans sought approval of a $64 million rate increase based on the formula set by the City Council in the 2018 rate case. The formula resulted in an increase in authorized electric revenues of $40 million and an increase in authorized gas revenues of $18.8 million. Entergy New Orleans also sought to commence collecting $5.2 million in electric revenues and $0.3 million in gas revenues that were previously approved by the City Council for collection through the formula rate plan. The filing was subject to review by the City Council and other parties over a 75-day review period, followed by a 25-day period to resolve any disputes among the parties. In October 2021 the City Council’s advisors filed a 75-day report recommending a reduction of $10 million for electric revenues and a reduction of $4.5 million for gas revenues, along with one-time credits funded by certain electric regulatory liabilities currently held by Entergy New Orleans for customers. On October 26, 2021, Entergy New Orleans provided notice to the City Council that it intends to implement rates effective with the first billing cycle of November 2021, with such rates reflecting an amount agreed-upon by Entergy New Orleans including adjustments filed in the City Council’s 75-day report, per the approved process for formula rate plan implementation. The total formula rate plan increase implemented was $49.5 million, with an increase of $34.9 million in electric revenues and $14.6 million in gas revenues. Also, credits of $17.4 million funded by certain regulatory liabilities currently held by Entergy New Orleans for customers will be issued over a five-month period from November 2021 through March 2022. Resulting rates went into effect with the first billing cycle of November 2021 pursuant to the formula rate plan tariff.
2022 Formula Rate Plan Filing
In April 2022, Entergy New Orleans submitted to the City Council its formula rate plan 2021 test year filing. The 2021 test year evaluation report, subsequently updated in a July 2022 filing, produced an earned return on equity of 6.88% compared to the authorized return on equity of 9.35%. Entergy New Orleans sought approval of a $42.1 million rate increase based on the formula set by the City Council in the 2018 rate case. The formula results in an increase in authorized electric revenues of $34.1 million and an increase in authorized gas revenues of $3.3 million. Entergy New Orleans also sought to commence collecting $4.7 million in electric revenues that were previously approved by the City Council for collection through the formula rate plan. In July 2022 the City Council’s advisors issued a report seeking a reduction to Entergy New Orleans’s proposed increase of approximately $17.1 million in total for electric and gas revenues. Effective with the first billing cycle of September 2022, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council including adjustments filed in the City Council’s advisors’ report, per the approved process for formula rate plan implementation. The total formula rate plan increase implemented was $24.7 million, which includes an increase of $18.2 million in electric revenues, $4.7 million in previously approved electric revenues, and an increase of $1.8 million in gas revenues. Additionally, credits of $13.9 million funded by certain regulatory liabilities currently held by Entergy New Orleans for customers will be issued over an eight-month period beginning September 2022.
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
COVID-19 Orders
In March 2020, Entergy New Orleans voluntarily suspended customer disconnections for non-payment of utility bills through May 2020. Subsequently, the City Council ordered that the moratorium be extended to August 1, 2020. In May 2020 the City Council issued an accounting order authorizing Entergy New Orleans to establish a regulatory asset for incremental COVID-19-related expenses. In January 2021, Entergy New Orleans resumed disconnecting service to commercial and small business customers with past-due balances that had not made payment arrangements. In February 2021 the City Council adopted a resolution suspending residential customer disconnections for non-payment of utility bills and suspending the assessment and accumulation of late fees on residential customers with past-due balances through May 15, 2021, which was not extended by the City Council. As of December 31, 2021, Entergy New Orleans had a regulatory asset of $13.9 million for costs associated with the COVID-19 pandemic. As part of the 2022 formula rate plan filing, Entergy New Orleans will provide additional credits to retail customers of $5 million in each of the years 2018, 2019, and 2020.recover this regulatory asset over a five-year period beginning September 2023.
In November 2017,June 2020 the City Council established the City Council Cares Program and directed Entergy New Orleans undertookto use the approximately $7 million refund received from the Entergy Arkansas opportunity sales FERC proceeding and approximately $15 million of non-securitized storm reserves to fund this program, which was intended to provide temporary bill relief to customers who become unemployed during the COVID-19 pandemic. The program was effective July 1, 2020 and offered qualifying residential customers bill credits of $100 per month for up to four months, for a multi-step restructuring, including the following:
Entergy New Orleans, Inc. redeemed its outstanding preferred stock at a pricemaximum of approximately $21$400 in residential customer bill credits. Credits of $4.3 million which included a call premium of approximately $819,000, plus any accumulated and unpaid dividends.
Entergy New Orleans, Inc. converted from a Louisiana corporationwere applied 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 mergercustomer bills under the TXBOC. Entergy New Orleans, Inc. remained in existence and held the membership interests in Entergy New Orleans Power.City Council Cares Program.
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.
Fuel and Purchased Power Cost Recovery
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.
Show Cause Order
In July 2016 the City Council approved the issuance of a show cause order, which directed Entergy New Orleans to make a filing on or before September 29, 2016 to demonstrate the reasonableness of its actions or positions with regard to certain issues in four existing dockets that relate to Entergy New Orleans’s: (i) storm hardening proposal; (ii) 2015 integrated resource plan; (iii) gas infrastructure rebuild proposal; and (iv) proposed sizing of the New Orleans Power Station and its community outreach prior to the filing. In September 2016, Entergy New Orleans filed its response to the City Council’s show cause order. The City Council has not established any further procedural schedule with regard to this proceeding.
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Reliability Investigation
In August 2017 the City Council established a docket to investigate the reliability of the Entergy New Orleans distribution system and to consider implementing certain reliability standards and possible financial penalties for not meeting any such standards. In April 2018 the City Council adopted a resolution directing Entergy New Orleans to demonstrate that it has been prudent in the management and maintenance of the reliability of its distribution system. The resolution also called for Entergy New Orleans to file a revised reliability plan addressing the current state of its distribution system and proposing remedial measures for increasing reliability. In June 2018, Entergy New Orleans filed its response to the City Council’s resolution regarding the prudence of its management and maintenance of the reliability of its distribution system. In July 2018, Entergy New Orleans filed its revised reliability plan discussing the various reliability programs that it uses to improve distribution system reliability and discussing generally the positive effect that advanced meter deployment and grid modernization can have on future reliability. Entergy New Orleans has retained a national consulting firm with expertise in distribution system reliability to conduct a review of Entergy New Orleans’s distribution system reliability-related practices and procedures and to provide recommendations for improving distribution system reliability. The report was filed with the City Council in October 2018. The City Council also approved a resolution that opensopened a prudence investigation into whether Entergy New Orleans was imprudent for not acting sooner to address outages in New Orleans and whether fines should be imposed. In January 2019, Entergy New Orleans filed testimony in response to the prudence investigation and asserting that it had been prudent in managing system reliability. In April 2019 the City Council
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Management’s Financial Discussion and Analysis
advisors filed comments and testimony asserting that Entergy New Orleans did not act prudently in maintaining and improving its distribution system reliability in recent years and recommending that a financial penalty in the range of $1.5 million to $2 million should be assessed. Entergy New Orleans disagreesdisagreed with the recommendation and submitted rebuttal testimony and rebuttal comments in June 2019. In November 2019 the City Council passed a resolution that penalized Entergy New Orleans $1 million for alleged imprudence in the maintenance of its distribution system. In December 2019, Entergy New Orleans filed suit in Louisiana state court seeking judicial review of the City Council’s resolution. In June 2022 the Orleans Civil District Court issued a written judgment that the penalty be set aside, reversed, and vacated. In August 2022 the Orleans Civil District Court issued written reasons for its judgment and also granted a post-judgment motion to remand for the City Council to take actions consistent with its judgment.
Also in August 2022 the City Council approved a resolution establishing a 30-day comment period on proposed minimum reliability standards and an associated penalty mechanism. In September 2022, Entergy New Orleans filed comments to the proposed plan including a request for an additional round of comments.
Renewable Portfolio Standard Rulemaking
In March 2019 the City Council initiated a rulemaking proceeding to consider whether to establish a renewable portfolio standard. The rulemaking will consider, among other issues, whether to adopt a renewable portfolio standard, whether such standard should be voluntary or mandatory, what kinds of technologies should qualify for inclusion in the rules, what level, if any, of renewable generation should be required, and whether penalties are an appropriate componentfour components of the proposed rules. Parties to the proceeding submitted initial comments in June 2019Renewable and reply comments in July 2019. Entergy New Orleans recommendsClean Portfolio Standard that the City Council adoptexpressed a voluntary cleandesire to implement were: (1) a mandatory requirement that Entergy New Orleans achieve 100% net zero carbon emissions by 2040; (2) reliance on renewable energy credits purchased without the associated energy for compliance with the standard being phased out over the ten-year period from 2040 to 2050; (3) no carbon-emitting resources in the portfolio of 70%resources Entergy New Orleans uses to serve New Orleans by 2050; and (4) a mechanism to limit costs in any one plan year to no more than one percent of generation being clean energy by 2030, as so defined, which,plan year total utility retail sales revenues. The City Council adopted the Utility Committee resolution in addition to renewable generation, would include nuclear, beneficial electrification, and demand-side management as compliant technologies. Several other industry leaders, academic researchers, and environmental advocates filed comments also supporting a clean energy standard. Other parties, including many representativesApril 2020. The first technical meeting of the solar and wind industry, are recommending mandatory, renewables-only requirements of up to 100% renewable resources by 2040.parties occurred in June 2020; a second technical meeting occurred in July 2020. In September 2019August 2020 the City Council advisors issued a report and recommendations, which also put forth three alternativefinal draft of the rules for review and comment from the parties. Comments wereparties before final rules would be proposed for consideration by the City Council. Entergy New Orleans filed comments in September and October 2020. The City Council approved the draft rule, as amended, in May 2021.
In March 2022 the City Council approved Entergy New Orleans’s initial compliance plan and established an alternative compliance payment value of $8.45 per MWh, which Entergy New Orleans will pay if it is unable to comply with the Renewable and Clean Portfolio Standard for the 2022 compliance year. Such compliance payments are paid into a clean energy fund established by the City Council. The City Council also approved the electric vehicle credit calculation methodology for use in the compliance demonstration report for 2022, to be filed prior to May 1, 2023. Entergy New Orleans’s proposal to create a 5% contingency reserve was considered reasonable for the initial compliance plan.
In August 2022, Entergy New Orleans submitted its compliance plan covering compliance years 2023-2025 requesting that the City Council (a) approve Entergy New Orleans’s proposal to purchase unbundled renewable energy credits as needed to achieve compliance with the Renewable and Clean Portfolio Standard; (b) approve treatment of the Sewerage and Water Board’s 230 kV Sullivan substation electrification project as a “qualified measure;” (c) establish the alternative compliance payment for years 2023-2025 at $8.45 per MWh; and (d) approve the Tier 3 credit calculations for electric vehicle charging infrastructure and for the Sewerage and Water Board Sullivan substation electrification. After receiving comments from intervenors and Entergy New Orleans, in October 2019December 2022 the City Council adopted a resolution that (a) approved Entergy New Orleans's proposal to purchase unbundled renewable energy credits, as needed; (b) denied Entergy New Orleans’s request to treat the Sewerage and replies wereWater Board’s 230 kV Sullivan substation electrification as a “qualified measure;” (c) approved the alternative compliance payment for years 2023-2025 at $8.45 per MWh; and (d) approved the Tier 3 credit calculations for electric vehicle charging infrastructure but denied the request to approve a Tier 3 credit for the Sewerage and Water Board substation electrification project at this time while the substation is not yet in service.
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Load Shed Investigation
On February 16, 2021, due to high customer demand and limited generation, MISO issued an order requiring load-serving entities throughout its southern region to shed load to protect the integrity of the bulk electric system. Entergy New Orleans was required to shed load of at least 26 MW, but due to certain complications with its automated load shed program and certain load measurement issues, it inadvertently shed approximately 105 MW of load in its service area. The maximum time any customer was without power due to the load shed event was one hour and forty minutes. In late February 2021 the City Council ordered its advisors to conduct an investigation into the load shed event and to issue a report, which was completed and filed in November 2019. FurtherApril 2021. The report recommended that the City Council action,open an additional docket to determine whether any of Entergy New Orleans’s actions were imprudent. In May 2021 the City Council opened a docket directing its advisors to conduct a prudence investigation and determine whether financial and/or other penalties should be imposed by the City Council. In June 2021, Entergy New Orleans filed a response to the show cause docket that outlined how its response to Winter Storm Uri was reasonable under the circumstances. In November 2021 the City Council’s Advisors issued a report that criticized Entergy’s response to the winter storm, including the establishmentinadvertent shedding of additional procedural steps105 MW of load and communications with customers. The advisors’ report, however, did not find that Entergy New Orleans was imprudent and did not recommend a fine under the circumstances. In February 2022 the City Council’s advisors presented to the City Council their report and investigative findings. While the presentation was critical, it recommended remedial actions to the load shedding process and did not recommend a finding of imprudence or a fine. Entergy New Orleans would oppose any attempt to levy a fine under the circumstances presented.
Management Audit
In September 2021 the City Council issued a resolution initiating a management audit of Entergy New Orleans that has been proposed by certain solar advocates. The advocates have proposed a broad scope audit including, but not limited to, ensuring the corporate culture embraces climate solutions, employee salaries, expenses, and capital spending, but the City Council has not yet determined the full scope of the proposed audit. In September 2021 the City Council passed a resolution directing its staff to issue a request for qualifications for firms interested in conducting the rulemaking, is expectedaudit.
Utility Alternative Investigation
In September 2021 the City Council issued a resolution directing its staff to initiate a request for qualifications for a third-party firm to study alternatives to Entergy New Orleans as the electric service provider for New Orleans. Entergy responded to the City Council and issued a press release stating that it stands ready to work with the City Council to quickly implement any action taken by the City Council in response to the first quarterstudy. In the press release, Entergy highlighted four preliminary options that the City Council would consider: merger of 2020.Entergy New Orleans with Entergy Louisiana, sale of Entergy New Orleans, spinoff of Entergy New Orleans to establish a standalone company, or municipalization of the assets of Entergy New Orleans by the City of New Orleans.
Federal Regulation
See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Nuclear Matters
See the “Nuclear Matters” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of nuclear matters.
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Environmental Risks
Entergy New Orleans’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy New Orleans is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of Entergy New Orleans’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and there is the potential for future changes in the assumptions and measurements that could produce estimates that would have a material impact on the presentation of Entergy New Orleans’s financial position or results of operations.
Utility Regulatory Accounting
See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.
Impairment of Long-lived Assets and Trust Fund Investments
See “Impairment of Long-lived Assets and Trust Fund Investments” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the impairment of long-lived assets.
Taxation and Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.
Qualified Pension and Other Postretirement Benefits
Entergy New Orleans’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2023 Qualified Pension Cost | | Impact on 2022 Projected Qualified Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $135 | | $3,249 |
| Rate of return on plan assets | | (0.25%) | | $320 | | $— |
| Rate of increase in compensation | | 0.25% | | $128 | | $670 |
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2020 Qualified Pension Cost | | Impact on 2019 Projected Qualified Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $334 | | $5,567 |
| Rate of return on plan assets | | (0.25%) | | $376 | | $— |
| Rate of increase in compensation | | 0.25% | | $209 | | $1,118 |
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2023 Postretirement Benefit Cost | | Impact on 2022 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $6 | | $544 |
| Health care cost trend | | 0.25% | | $29 | | $387 |
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2020 Postretirement Benefit Cost | | Impact on 2019 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $61 | | $950 |
| Health care cost trend | | 0.25% | | $97 | | $665 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Employer Contributions
Total qualified pension cost for Entergy New Orleans in 20192022 was $5.1 million.$10 million, including $6.7 million in settlement costs. Entergy New Orleans anticipates 20202023 qualified pension cost to be $6$2 million. Entergy New Orleans contributed $4.6$1.1 million to its qualified pension plans in 20192022 and estimates 20202023 pension contributions will be approximately $3.2$1.4 million, although the 20202023 required pension contributions will be known with more certainty when the January 1, 20202023 valuations are completed, which is expected by April 1, 2020.2023.
Total postretirement health care and life insurance benefit income for Entergy New Orleans in 20192022 was $3.5$6.7 million. Entergy New Orleans expects 20202023 postretirement health care and life insurance benefit income of approximately $4.3 million. Entergy New Orleans contributed $1.7 million$333 thousand to its other postretirement plans in 20192022 and estimates 20202023 contributions will be approximately $162$193 thousand.
Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the member and Board of Directors of
Entergy New Orleans, LLC and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy New Orleans, LLC and Subsidiaries (the “Company”) as of December 31, 20192022 and 2018,2021, the related consolidated statements of income, cash flows, and changes in member’s equity (pages 386418 through 390422 and applicable items in pages 4953 through 236)245), for each of the three years in the period ended December 31, 2019,2022, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20192022 and 2018,2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2022, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Rate and Regulatory Matters— Entergy New Orleans, LLC and Subsidiaries — Refer to Note 2 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Council of the City of New Orleans, Louisiana (the “City Council”), which has jurisdiction with respect to the rates of electric companies in the City of New Orleans, Louisiana, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based
rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.
The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the City Council and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the City Council and the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs and refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the City Council and the FERC involved specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and significant auditor judgment to evaluate management estimates and the subjectivity of audit evidence.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the City Council and the FERC included the following, among others:
•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 Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the City Council and the FERC for the Company, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the City Council’s 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.
•For regulatory matters in process, we inspected the Company’s filings with the City Council and the FERC, including the base rate case filing, and considered the filings with the City Council and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.
•We obtained an analysis from management and support 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 not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
Securitization Financing—Storm Cost Recovery Filings with Retail Regulators—Entergy New Orleans, LLC and Subsidiaries — Refer to Note 2 to the financial statements
Critical Audit Matter Description
In August 2021, Hurricane Ida caused significant damage to the Company’s service area. In October 2022, the City Council issued a Financing Order authorizing the Company and the Louisiana Utilities Restoration Corporation (“LURC”) to proceed with a single securitization bond issuance of approximately $206 million. In December 2022, the Louisiana Local Government Environmental Facilities and Community Development Authority (“LCDA”), a political subdivision of the State of Louisiana, issued $209.3 million in bonds pursuant to the Louisiana Electric
Utility Storm Recovery Securitization Act. From the $201.8 million of net bond proceeds loaned by the LCDA to the LURC, the LURC purchased the storm recovery property from the Company.
The Company does not report the bonds issued by the LCDA on its balance sheet because the bonds are the obligation of the LCDA, and there is no recourse against the Company in the event of a default. To service the bonds, the Company collects a storm recovery charge on behalf of the LURC and remits the collections to the bond indenture trustee. The Company does not report the collections as revenue because the Company is merely acting as the billing and collection agent for the LURC.
We identified management’s conclusion that the bonds issued by the LCDA are the obligation of the LCDA as a critical audit matter due to the significant judgments made by management to support its conclusion. Auditing management’s judgments involved especially subjective judgment and specialized knowledge of accounting for securitization financing transactions.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the securitization financing included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the accounting impact of this securitization financing transaction, including the conclusion that the bonds issued by the LCDA are the obligation of the LCDA.
•We evaluated the Company’s disclosures related to the impacts of the securitization financing, including the balances recorded.
•We read relevant securitization regulatory and financing orders issued by the City Council for the Company, the LURC, and the LCDA, and by the Louisiana Public Service Commission for other public utilities with similar transactions, and evaluated the external information to compare to management’s conclusions.
•We obtained an analysis from management regarding the legal status of the bonds issued by the LCDA and the storm recovery property to assess management’s assertion that the bonds issued by the LCDA are the obligation of the LCDA.
•With the assistance of professionals in our firm having expertise and experience in addressing the accounting for securitization financing transactions by regulated utilities, we evaluated the Company’s conclusion, including the conclusion that the bonds issued by the LCDA are the obligation of the LCDA.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 21, 202024, 2023
We have served as the Company’s auditor since 2001.
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | |
| | | For the Years Ended December 31, |
| | | 2022 | | 2021 | | 2020 |
| | | (In Thousands) |
| | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | | $855,248 | | | $672,231 | | | $560,632 | |
| Natural gas | | 142,085 | | | 96,621 | | | 73,209 | |
| TOTAL | | 997,333 | | | 768,852 | | | 633,841 | |
| | | | | | |
| OPERATING EXPENSES | | | | | | |
| Operation and Maintenance: | | | | | | |
| Fuel, fuel-related expenses, and gas purchased for resale | | 244,994 | | | 150,018 | | | 76,781 | |
| Purchased power | | 314,283 | | | 268,568 | | | 243,572 | |
| Other operation and maintenance | | 156,653 | | | 145,377 | | | 125,756 | |
| Taxes other than income taxes | | 63,743 | | | 53,569 | | | 57,454 | |
| Depreciation and amortization | | 76,938 | | | 73,480 | | | 64,012 | |
| Other regulatory charges (credits) - net | | 19,596 | | | 13,177 | | | 1,854 | |
| TOTAL | | 876,207 | | | 704,189 | | | 569,429 | |
| | | | | | |
| OPERATING INCOME | | 121,126 | | | 64,663 | | | 64,412 | |
| | | | | | |
| OTHER INCOME | | | | | | |
| Allowance for equity funds used during construction | | 829 | | | 2,371 | | | 6,339 | |
| Interest and investment income | | 742 | | | 48 | | | 120 | |
| Miscellaneous - net | | (21) | | | (1,240) | | | 316 | |
| TOTAL | | 1,550 | | | 1,179 | | | 6,775 | |
| | | | | | |
| INTEREST EXPENSE | | | | | | |
| Interest expense | | 34,829 | | | 29,164 | | | 29,105 | |
| Allowance for borrowed funds used during construction | | (531) | | | (1,056) | | | (3,049) | |
| TOTAL | | 34,298 | | | 28,108 | | | 26,056 | |
| | | | | | |
| INCOME BEFORE INCOME TAXES | | 88,378 | | | 37,734 | | | 45,131 | |
| | | | | | |
| Income taxes | | 24,277 | | | 5,936 | | | (4,207) | |
| | | | | | |
| NET INCOME | | $64,101 | | | $31,798 | | | $49,338 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | | |
| | | For the Years Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | |
| $594,417 |
| |
| $624,733 |
| |
| $631,744 |
|
| Natural gas | | 91,806 |
| | 92,657 |
| | 84,326 |
|
| TOTAL | | 686,223 |
| | 717,390 |
| | 716,070 |
|
| | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 105,217 |
| | 114,787 |
| | 111,082 |
|
| Purchased power | | 258,306 |
| | 270,634 |
| | 282,178 |
|
| Other operation and maintenance | | 121,057 |
| | 124,293 |
| | 107,977 |
|
| Taxes other than income taxes | | 55,270 |
| | 56,141 |
| | 54,590 |
|
| Depreciation and amortization | | 56,072 |
| | 55,930 |
| | 52,945 |
|
| Other regulatory charges - net | | 21,616 |
| | 21,413 |
| | 10,889 |
|
| TOTAL | | 617,538 |
| | 643,198 |
| | 619,661 |
|
| | | | | | | |
| OPERATING INCOME | | 68,685 |
| | 74,192 |
| | 96,409 |
|
| | | | | | | |
| OTHER INCOME | | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 9,941 |
| | 5,941 |
| | 2,418 |
|
| Interest and investment income | | 428 |
| | 604 |
| | 707 |
|
| Miscellaneous - net | | (6,038 | ) | | (10,444 | ) | | (1,269 | ) |
| TOTAL | | 4,331 |
| | (3,899 | ) | | 1,856 |
|
| | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
|
| Interest expense | | 24,463 |
| | 21,772 |
| | 21,281 |
|
| Allowance for borrowed funds used during construction | | (4,262 | ) | | (2,195 | ) | | (847 | ) |
| TOTAL | | 20,201 |
| | 19,577 |
| | 20,434 |
|
| | | | | | | |
| INCOME BEFORE INCOME TAXES | | 52,815 |
| | 50,716 |
| | 77,831 |
|
| | | | | | | |
| Income taxes | | 186 |
| | (2,436 | ) | | 33,278 |
|
| | | | | | | |
| NET INCOME | | 52,629 |
| | 53,152 |
| | 44,553 |
|
| | | | | | | |
| Preferred dividend requirements and other | | — |
| | — |
| | 841 |
|
| | | | | | | |
| EARNINGS APPLICABLE TO COMMON EQUITY | |
| $52,629 |
| |
| $53,152 |
| |
| $43,712 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | |
| | | For the Years Ended December 31, |
| | | 2022 | | 2021 | | 2020 |
| | | (In Thousands) |
| | | | | | |
| OPERATING ACTIVITIES | | | | | | |
| Net income | | $64,101 | | | $31,798 | | | $49,338 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation and amortization | | 76,938 | | | 73,480 | | | 64,012 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 18,685 | | | 12,573 | | | 3,938 | |
| Changes in assets and liabilities: | | | | | | |
| Receivables | | 6,128 | | | (42,612) | | | (12,003) | |
| Fuel inventory | | (2,927) | | | (967) | | | (58) | |
| Accounts payable | | 21 | | | 22,457 | | | 5,582 | |
| Taxes accrued | | 5,923 | | | (315) | | | 398 | |
| Interest accrued | | 89 | | | (104) | | | 1,179 | |
| Deferred fuel costs | | (17,760) | | | 9,737 | | | (7,048) | |
| Other working capital accounts | | (790) | | | (3,233) | | | (13,156) | |
| Provisions for estimated losses | | 80,719 | | | (83,569) | | | 1,356 | |
| Other regulatory assets | | 46,505 | | | 18,173 | | | (7,427) | |
| Other regulatory liabilities | | (8,639) | | | 4,985 | | | (4,728) | |
| Effect of securitization on regulatory asset | | 95,920 | | | — | | | — | |
| Pension and other postretirement liabilities | | 9,769 | | | (32,144) | | | (14,063) | |
| Other assets and liabilities | | (10,919) | | | 68,549 | | | (3,296) | |
| Net cash flow provided by operating activities | | 363,763 | | | 78,808 | | | 64,024 | |
| INVESTING ACTIVITIES | | | | | | |
| Construction expenditures | | (217,864) | | | (220,284) | | | (228,983) | |
| Allowance for equity funds used during construction | | 829 | | | 2,371 | | | 6,339 | |
| Payment for purchase of assets | | — | | | — | | | (1,584) | |
| | | | | | |
| | | | | | |
| Changes in money pool receivable - net | | (110,844) | | | (36,410) | | | 5,191 | |
| Payments to storm reserve escrow account | | (200,000) | | | (7) | | | (433) | |
| Receipts from storm reserve escrow account | | 125,000 | | | 83,045 | | | — | |
| Changes in securitization account | | (236) | | | 1,365 | | | (1,375) | |
| Increase in other investments | | (675) | | | — | | | — | |
| Net cash flow used in investing activities | | (403,790) | | | (169,920) | | | (220,845) | |
| FINANCING ACTIVITIES | | | | | | |
| Proceeds from the issuance of long-term debt | | — | | | 183,403 | | | 138,925 | |
| Retirement of long-term debt | | (12,207) | | | (36,873) | | | (56,593) | |
| Repayment of long-term payable due to associated company | | (1,326) | | | (1,618) | | | (1,838) | |
| | | | | | |
| Capital contributions from parent | | — | | | — | | | 60,000 | |
| | | | | | |
| Changes in money pool payable - net | | — | | | (10,190) | | | 10,190 | |
| | | | | | |
| | | | | | |
| | | | | | |
| Other | | 15,162 | | | (774) | | | 146 | |
| Net cash flow provided by financing activities | | 1,629 | | | 133,948 | | | 150,830 | |
| Net increase (decrease) in cash and cash equivalents | | (38,398) | | | 42,836 | | | (5,991) | |
| Cash and cash equivalents at beginning of period | | 42,862 | | | 26 | | | 6,017 | |
| Cash and cash equivalents at end of period | | $4,464 | | | $42,862 | | | $26 | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | |
| Cash paid (received) during the period for: | | | | | | |
| Interest - net of amount capitalized | | $33,343 | | | $28,009 | | | $26,673 | |
| Income taxes | | $499 | | | ($3,839) | | | $3,392 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | | |
| | | For the Years Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | |
| Net income | |
| $52,629 |
| |
| $53,152 |
| |
| $44,553 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation and amortization | | 56,072 |
| | 55,930 |
| | 52,945 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 21,350 |
| | 24,548 |
| | 64,036 |
|
| Changes in assets and liabilities: | | |
| | |
| | |
|
| Receivables | | (9,372 | ) | | 15,724 |
| | (18,058 | ) |
| Fuel inventory | | (387 | ) | | 357 |
| | (49 | ) |
| Accounts payable | | (5,571 | ) | | (385 | ) | | 1,874 |
|
| Prepaid taxes and taxes accrued | | 234 |
| | 30,547 |
| | (22,100 | ) |
| Interest accrued | | 550 |
| | 879 |
| | 44 |
|
| Deferred fuel costs | | 3,630 |
| | (6,486 | ) | | 12,592 |
|
| Other working capital accounts | | 5,021 |
| | 4,146 |
| | (2,711 | ) |
| Provisions for estimated losses | | 1,948 |
| | 1,511 |
| | (3,430 | ) |
| Other regulatory assets | | (29,567 | ) | | 21,637 |
| | 16,673 |
|
| Other regulatory liabilities | | (22,105 | ) | | (28,459 | ) | | 110,147 |
|
Deferred tax rate change recognized as regulatory liability/asset
| | — |
| | — |
| | (111,170 | ) |
| Pension and other postretirement liabilities | | (14,624 | ) | | (15,134 | ) | | (15,994 | ) |
| Other assets and liabilities | | 55,796 |
| | 13,811 |
| | (1,555 | ) |
| Net cash flow provided by operating activities | | 115,604 |
| | 171,778 |
| | 127,797 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
|
| Construction expenditures | | (229,560 | ) | | (202,186 | ) | | (115,584 | ) |
| Allowance for equity funds used during construction | | 9,941 |
| | 5,941 |
| | 2,418 |
|
| Changes in money pool receivable - net | | 16,825 |
| | (9,293 | ) | | 1,492 |
|
| Payments to storm reserve escrow account | | (1,752 | ) | | (1,311 | ) | | (597 | ) |
| Receipts from storm reserve escrow account | | — |
| | 3 |
| | 2,488 |
|
| Changes in securitization account | | 236 |
| | (770 | ) | | 283 |
|
| Net cash flow used in investing activities | | (204,310 | ) | | (207,616 | ) | | (109,500 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | 113,876 |
| | 59,234 |
| | — |
|
| Retirement of long-term debt | | (35,376 | ) | | (11,042 | ) | | (10,600 | ) |
| Repayment of long-term payable due to associated company | | (1,979 | ) | | (2,077 | ) | | (2,104 | ) |
Redemption of preferred stock
| | — |
| | — |
| | (20,599 | ) |
| Capital contributions from parent | | — |
| | — |
| | 20,000 |
|
| Distributions/dividends paid: | | |
| | |
| | |
|
| Common equity | | — |
| | (23,750 | ) | | (74,250 | ) |
| Preferred stock | | — |
| | — |
| | (1,083 | ) |
| Other | | (1,475 | ) | | 409 |
| | 12 |
|
| Net cash flow provided by (used in) financing activities | | 75,046 |
| | 22,774 |
| | (88,624 | ) |
| Net decrease in cash and cash equivalents | | (13,660 | ) | | (13,064 | ) | | (70,327 | ) |
| Cash and cash equivalents at beginning of period | | 19,677 |
| | 32,741 |
| | 103,068 |
|
| Cash and cash equivalents at end of period | |
| $6,017 |
| |
| $19,677 |
| |
| $32,741 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | |
| | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $22,873 |
| |
| $19,840 |
| |
| $20,180 |
|
| Income taxes | |
| ($5,310 | ) | |
| ($39,781 | ) | |
| ($8,660 | ) |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | |
| | | December 31, |
| | | 2022 | | 2021 |
| | | (In Thousands) |
| | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | | $27 | | | $26 | |
| Temporary cash investments | | 4,437 | | | 42,836 | |
| Total cash and cash equivalents | | 4,464 | | | 42,862 | |
| Securitization recovery trust account | | 2,235 | | | 1,999 | |
| Accounts receivable: | | | | |
| Customer | | 93,288 | | | 69,902 | |
| Allowance for doubtful accounts | | (11,909) | | | (13,282) | |
| Associated companies | | 149,927 | | | 74,146 | |
| Other | | 6,110 | | | 13,668 | |
| Accrued unbilled revenues | | 37,284 | | | 25,550 | |
| Total accounts receivable | | 274,700 | | | 169,984 | |
| | | | |
| Deferred fuel costs | | 10,153 | | | — | |
| Fuel inventory - at average cost | | 5,872 | | | 2,945 | |
| Materials and supplies - at average cost | | 22,498 | | | 19,216 | |
| | | | |
| Prepayments and other | | 6,312 | | | 5,428 | |
| TOTAL | | 326,234 | | | 242,434 | |
| | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | |
| Non-utility property - at cost (less accumulated depreciation) | | 1,050 | | | 1,016 | |
| Storm reserve escrow account | | 75,000 | | | — | |
| Other | | 675 | | | — | |
| TOTAL | | 76,725 | | | 1,016 | |
| | | | |
| UTILITY PLANT | | | | |
| Electric | | 1,934,837 | | | 1,976,202 | |
| Natural gas | | 390,252 | | | 373,983 | |
| Construction work in progress | | 39,607 | | | 22,199 | |
| TOTAL UTILITY PLANT | | 2,364,696 | | | 2,372,384 | |
| Less - accumulated depreciation and amortization | | 808,224 | | | 774,309 | |
| UTILITY PLANT - NET | | 1,556,472 | | | 1,598,075 | |
| | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | |
| Regulatory assets: | | | | |
| | | | |
| Deferred fuel costs | | 4,080 | | | 4,080 | |
| Other regulatory assets (includes securitization property of $13,363 as of December 31, 2022 and $25,761 as of December 31, 2021) | | 202,112 | | | 248,617 | |
| Other | | 46,778 | | | 56,101 | |
| TOTAL | | 252,970 | | | 308,798 | |
| | | | |
| TOTAL ASSETS | | $2,212,401 | | | $2,150,323 | |
| | | | |
| See Notes to Financial Statements. | | | | |
|
| | | | | | | | |
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | | |
| | | December 31, |
| | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents | | | | |
| Cash | |
| $26 |
| |
| $26 |
|
| Temporary cash investments | | 5,991 |
| | 19,651 |
|
| Total cash and cash equivalents | | 6,017 |
| | 19,677 |
|
| Securitization recovery trust account | | 1,989 |
| | 2,224 |
|
| Accounts receivable: | | |
| | |
|
| Customer | | 48,265 |
| | 43,890 |
|
| Allowance for doubtful accounts | | (3,226 | ) | | (3,222 | ) |
| Associated companies | | 6,280 |
| | 27,938 |
|
| Other | | 7,378 |
| | 4,090 |
|
| Accrued unbilled revenues | | 25,453 |
| | 18,907 |
|
| Total accounts receivable | | 84,150 |
| | 91,603 |
|
| Fuel inventory - at average cost | | 1,920 |
| | 1,533 |
|
| Materials and supplies - at average cost | | 13,522 |
| | 12,133 |
|
| Prepayments and other | | 4,846 |
| | 6,905 |
|
| TOTAL | | 112,444 |
|
| 134,075 |
|
| | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
|
| Non-utility property at cost (less accumulated depreciation) | | 1,016 |
| | 1,016 |
|
| Storm reserve escrow account | | 82,605 |
| | 80,853 |
|
| TOTAL | | 83,621 |
| | 81,869 |
|
| | | | | |
| UTILITY PLANT | | |
| | |
|
| Electric | | 1,467,215 |
| | 1,364,091 |
|
| Natural gas | | 311,432 |
| | 284,728 |
|
| Construction work in progress | | 201,829 |
| | 146,668 |
|
| TOTAL UTILITY PLANT | | 1,980,476 |
| | 1,795,487 |
|
| Less - accumulated depreciation and amortization | | 715,406 |
| | 670,135 |
|
| UTILITY PLANT - NET | | 1,265,070 |
| | 1,125,352 |
|
| | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
|
| Regulatory assets: | | |
| | |
|
| Deferred fuel costs | | 4,080 |
| | 4,080 |
|
| Other regulatory assets (includes securitization property of $49,542 as of December 31, 2019 and $60,453 as of December 31, 2018) | | 259,363 |
| | 229,796 |
|
| Other | | 10,720 |
| | 1,416 |
|
| TOTAL | | 274,163 |
| | 235,292 |
|
| | | | | |
| TOTAL ASSETS | |
| $1,735,298 |
| |
| $1,576,588 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
| | | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | | | |
| | | December 31, |
| | | 2022 | | 2021 |
| | | (In Thousands) |
| | | | |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | | $170,000 | | | $— | |
| Payable due to associated company | | 1,306 | | | 1,326 | |
| Accounts payable: | | | | |
| Associated companies | | 53,258 | | | 45,057 | |
| Other | | 57,291 | | | 146,921 | |
| Customer deposits | | 31,826 | | | 28,539 | |
| Taxes accrued | | 10,308 | | | 4,385 | |
| Interest accrued | | 8,080 | | | 7,991 | |
| Deferred fuel costs | | — | | | 7,607 | |
| Current portion of unprotected excess accumulated deferred income taxes | | — | | | 1,906 | |
| | | | |
| Other | | 6,560 | | | 6,204 | |
| TOTAL | | 338,629 | | | 249,936 | |
| | | | |
| NON-CURRENT LIABILITIES | | | | |
| Accumulated deferred income taxes and taxes accrued | | 385,259 | | | 365,384 | |
| Accumulated deferred investment tax credits | | 16,481 | | | 16,306 | |
| Regulatory liability for income taxes - net | | 39,738 | | | 40,589 | |
| Asset retirement cost liabilities | | — | | | 4,032 | |
| Accumulated provisions | | 87,048 | | | 6,329 | |
| | | | |
| Long-term debt (includes securitization bonds of $17,697 as of December 31, 2022 and $29,661 as of December 31, 2021) | | 596,047 | | | 777,254 | |
| Long-term payable due to associated company | | 8,279 | | | 9,585 | |
| Other | | 38,104 | | | 42,193 | |
| TOTAL | | 1,170,956 | | | 1,261,672 | |
| | | | |
| Commitments and Contingencies | | | | |
| | | | |
| EQUITY | | | | |
| Member's equity | | 702,816 | | | 638,715 | |
| TOTAL | | 702,816 | | | 638,715 | |
| | | | |
| TOTAL LIABILITIES AND EQUITY | | $2,212,401 | | | $2,150,323 | |
| | | | |
| See Notes to Financial Statements. | | | | |
|
| | | | | | | | |
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | | December 31, |
| | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | |
| $25,000 |
| |
| $— |
|
| Payable due to associated company | | 1,838 |
| | 1,979 |
|
| Accounts payable: | | |
| | |
|
| Associated companies | | 43,222 |
| | 43,416 |
|
| Other | | 43,963 |
| | 36,686 |
|
| Customer deposits | | 28,493 |
| | 28,667 |
|
| Taxes accrued | | 4,302 |
| | 4,068 |
|
| Interest accrued | | 6,916 |
| | 6,366 |
|
| Deferred fuel costs | | 4,918 |
| | 1,288 |
|
| Current portion of unprotected excess accumulated deferred income taxes | | 9,470 |
| | 25,301 |
|
| Other | | 15,827 |
| | 9,521 |
|
| TOTAL CURRENT LIABILITIES | | 183,949 |
| | 157,292 |
|
| | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 354,536 |
| | 323,595 |
|
| Accumulated deferred investment tax credits | | 2,131 |
| | 2,219 |
|
| Regulatory liability for income taxes - net | | 49,090 |
| | 60,249 |
|
| Asset retirement cost liabilities | | 3,522 |
| | 3,291 |
|
| Accumulated provisions | | 88,542 |
| | 86,594 |
|
| Long-term debt (includes securitization bonds of $52,641 as of December 31, 2019 and $63,620 as of December 31, 2018) | | 521,539 |
| | 467,358 |
|
| Long-term payable due to associated company | | 12,529 |
| | 14,367 |
|
| Other | | 21,881 |
| | 16,673 |
|
| TOTAL NON-CURRENT LIABILITIES | | 1,053,770 |
| | 974,346 |
|
| | | | | |
| Commitments and Contingencies | |
|
| |
|
|
| | | | | |
| EQUITY | | |
| | |
|
| Member's equity | | 497,579 |
| | 444,950 |
|
| TOTAL | | 497,579 |
| | 444,950 |
|
| | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $1,735,298 |
| |
| $1,576,588 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
|
| | | | | | | |
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY |
For the Years Ended December 31, 2019, 2018,2022, 2021, and 20172020 |
| | |
| |
| Member’s Equity |
| | (In Thousands) |
| | |
Balance at December 31, 2016 |
| $426,946 |
|
Net income | 44,553 |
|
Capital contributions from parent | 20,000 |
|
Common equity distributions | (74,250 | ) |
Preferred stock dividends | (841 | ) |
Other | (860 | ) |
Balance at December 31, 2017 |
| $415,548 |
|
Net income | 53,152 |
|
Common equity distributions | (23,750 | ) |
Balance at December 31, 2018 |
| $444,950 |
|
Net income | 52,629 |
|
| Balance at December 31, 2019 |
| $497,579 |
|
| Net income | | 49,338 | |
| Capital contributions from parent | | 60,000 | |
| | |
| | |
| | |
| Balance at December 31, 2020 | | $606,917 | |
| Net income | | 31,798 | |
| | |
| | |
| | |
| | |
| Balance at December 31, 2021 | | $638,715 | |
| Net income | | 64,101 | |
| | |
| | |
| | |
| | |
| Balance at December 31, 2022 | | $702,816 | |
| | |
| See Notes to Financial Statements. | |
|
|
| | | | | | | | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | |
| | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| | (In Thousands) |
| | | | | | | | | | |
| Operating revenues |
| $686,223 |
| |
| $717,390 |
| |
| $716,070 |
| |
| $665,463 |
| |
| $671,446 |
|
| Net income |
| $52,629 |
| |
| $53,152 |
| |
| $44,553 |
| |
| $48,849 |
| |
| $44,925 |
|
| Total assets |
| $1,735,298 |
| |
| $1,576,588 |
| |
| $1,497,836 |
| |
| $1,494,569 |
| |
| $1,215,144 |
|
| Long-term obligations (a) |
| $534,068 |
| |
| $481,725 |
| |
| $434,793 |
| |
| $466,670 |
| |
| $357,687 |
|
| | | | | | | | | | |
| (a) Includes long-term debt (including the long-term payable to associated company and excluding currently maturing debt) and preferred stock without sinking fund. |
| | | | | | | | | | |
| | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| | (Dollars In Millions) |
| | | | | | | | | | |
| Electric Operating Revenues: | |
| | |
| | |
| | |
| | |
|
| Residential |
| $245 |
| |
| $262 |
| |
| $250 |
| |
| $231 |
| |
| $220 |
|
| Commercial | 202 |
| | 217 |
| | 228 |
| | 206 |
| | 186 |
|
| Industrial | 32 |
| | 33 |
| | 36 |
| | 33 |
| | 30 |
|
| Governmental | 71 |
| | 72 |
| | 77 |
| | 69 |
| | 64 |
|
| Total billed retail | 550 |
| | 584 |
| | 591 |
| | 539 |
| | 500 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | — |
| | — |
| | — |
| | 30 |
| | 66 |
|
| Non-associated companies | 38 |
| | 30 |
| | 29 |
| | 3 |
| | — |
|
| Other | 6 |
| | 11 |
| | 12 |
| | 15 |
| | 18 |
|
| Total |
| $594 |
| |
| $625 |
| |
| $632 |
| |
| $587 |
| |
| $584 |
|
| | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | |
| | |
| | |
| | |
|
| Residential | 2,353 |
| | 2,401 |
| | 2,155 |
| | 2,231 |
| | 2,301 |
|
| Commercial | 2,215 |
| | 2,270 |
| | 2,248 |
| | 2,268 |
| | 2,257 |
|
| Industrial | 438 |
| | 448 |
| | 429 |
| | 441 |
| | 463 |
|
| Governmental | 815 |
| | 795 |
| | 790 |
| | 794 |
| | 825 |
|
| Total retail | 5,821 |
| | 5,914 |
| | 5,622 |
| | 5,734 |
| | 5,846 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | — |
| | — |
| | — |
| | 1,071 |
| | 1,644 |
|
| Non-associated companies | 1,961 |
| | 1,484 |
| | 1,703 |
| | 141 |
| | 11 |
|
| Total | 7,782 |
| | 7,398 |
| | 7,325 |
| | 6,946 |
| | 7,501 |
|
| | | | | | | | | | |
| | | | | | | | | | |
ENTERGY TEXAS, INC. AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
20192022 Compared to 20182021
Net Income
Net income decreased $2.8increased $74.5 million primarily due to a higher effective income tax rate, after excludingvolume/weather, higher retail electric price, and the effectrecognition of the returnequity component of unprotected excess accumulated deferred income taxes which iscarrying costs as part of the securitization of the Hurricane Laura, Hurricane Delta, and Winter Storm Uri system restoration costs in April 2022. The increase was partially offset in operating revenues,by higher other operation and maintenance expenses, higher depreciation and amortization expenses, and a higher other operation and maintenance expenses, partially offset by higher retail electric price and higher other income.effective income tax rate.
Operating Revenues
Following is an analysis of the change in operating revenuerevenues comparing 20192022 to 2018.
|
| | | | |
| Amount |
| (In Millions) |
| 2021 operating revenues | $1,902.5 |
|
2018 operating revenues |
| $1,605.9 |
|
| Fuel, rider, and other revenues that do not significantly affect net income | (88.4244.8 | ) |
Return of unprotected excess accumulated deferred income taxes to customersVolume/weather | (72.869.4 | ) |
| Retail electric price | 41.050.5 |
|
Volume/weatherSystem restoration carrying costs | 3.321.7 |
|
20192022 operating revenues |
| $1,489.0 |
|
Entergy Texas’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.
The returnvolume/weather variance is primarily due to an increase of unprotected excess accumulated deferred income taxes1,744 GWh, or 9%, in electricity usage across all customer classes, including the effect of more favorable weather on residential sales. The increase in industrial usage was primarily due to an increase in demand from cogeneration and small industrial customers resultedand an increase in demand from expansion projects, primarily in the returntransportation, primary metals, and chemicals industries. The increase in weather-adjusted residential usage was primarily due to an increase in customers. The increase in commercial usage was primarily due to the effect of unprotected excess accumulated deferred income taxes throughthe COVID-19 pandemic on businesses in 2021. The increased usage from these industrial and commercial customers has a rider effective October 2018. In 2019, $87.4 million was returned to customers as compared to $14.6 million in 2018. There is norelatively smaller effect on net income as the reduction in operating revenues is offset bybecause a reduction in income tax expense. See Note 2 tolarger portion of the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act.revenues from those customers comes from fixed charges.
The retail electric price variance is primarily due to a base rateto:
•increases in the transmission cost recovery factor rider effective March 2021 and March 2022;
•an increase in the distribution cost recovery factor rider effective October 2018 as approvedJanuary 2022; and
by •the PUCT. implementation of the generation cost recovery rider, which includes the first-year revenue requirement for the Montgomery County Power Station, effective in late January 2021 and the implementation of the
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
generation cost recovery relate-back rider for the Montgomery County Power Station effective August 2022.
See Note 2 to the financial statements for further discussion of the rate case.transmission and distribution cost recovery factor rider and generation cost recovery rider filings.
The volume/weather variance is primarily dueSystem restoration carrying costs represent the equity component of system restoration carrying costs, recorded in second quarter 2022, recognized as part of the securitization of the Hurricane Laura, Hurricane Delta, and Winter Storm Uri system restoration costs in April 2022. See Note 2 to an increase in usage during the unbilledfinancial statements for a discussion of the securitization.
Total electric energy sales period.for Entergy Texas for the years ended December 31, 2022 and 2021 are as follows:
| | | | | | | | | | | | | | | | | |
| 2022 | | 2021 | | % Change |
| (GWh) | | |
| Residential | 6,779 | | | 6,156 | | | 10 | |
| Commercial | 4,758 | | | 4,503 | | | 6 | |
| Industrial | 9,572 | | | 8,722 | | | 10 | |
| Governmental | 271 | | | 255 | | | 6 | |
| Total retail | 21,380 | | | 19,636 | | | 9 | |
| Sales for resale: | | | | | |
| Associated companies | 279 | | | 1,364 | | | (80) | |
| Non-associated companies | 813 | | | 1,008 | | | (19) | |
| Total | 22,472 | | | 22,008 | | | 2 | |
See Note 19 to the financial statements for additional discussion of Entergy Texas’s operating revenues.
Other Income Statement Variances
Other operation and maintenance expenses increased primarily due to:
•an increase of $15.6 million in power delivery expenses primarily due to higher vegetation maintenance costs, higher reliability costs, and higher safety and training costs;
•an increase of $5.1 million in information technologynon-nuclear generation expenses primarily due to higher costs associated with materials and supplies in 2022 as compared to 2021 and higher expenses associated with the Hardin County Peaking Facility, which was purchased in June 2021;
•an increase of $3.2 million in customer service center support costs primarily due to higher costs relatedcontract costs; and
•several individually insignificant items.
Taxes other than income taxes increased primarily due to applicationsincreases in ad valorem taxes, increases in gross receipts taxes, and increases in local franchise taxes, partially offset by a sales tax audit assessment in 2021. Ad valorem taxes increased as a result of higher assessments.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Interest expense increased primarily due to the issuance of $290.85 million of senior secured system restoration bonds in April 2022 and the issuance of $325 million of 5.00% Series mortgage bonds in August 2022. The increase was partially offset by the repayment, prior to maturity, of $545.9 million of senior secured transition
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
and infrastructure support, enhanced cyber security, and upgrades and maintenance;
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.
Depreciation and amortization expenses increased primarilybonds as a result of new depreciation rates establishedpayments made on the remaining principal balance in 2022 and the settlementrepayment, at maturity, of the 2018 base rate case and additions to plant$75 million of 4.10% Series mortgage bonds in service.September 2021.
Other regulatory charges (credits) include regulatory charges of $25.4 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 customers. See Note 2 to the financial statements for discussion of the rate case proceeding.
Other income increased primarily due to an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2019, including the Montgomery County Power Station project.
Interest expense decreased primarily due to an increase in the allowance for borrowed funds used during construction due to higher construction work in progress in 2019, including the Montgomery County Power Station project.
The effective income tax rates were (51.1%)14.3% for 20192022 and (19.3%)10% for 2018. The difference in the effective income tax rate of (51.1%) versus the federal statutory rate of 21% for 2019 was primarily due to the amortization of excess accumulated deferred income taxes and book and tax differences related to the allowance for equity funds used during construction. The difference in the effective income tax rate of (19.3%) versus the federal statutory rate of 21% for 2018 was primarily due to the flow through and amortization of excess accumulated deferred income taxes, along with the effect on income tax expense of the resolution of Entergy Texas’s 2018 base rate proceeding.2021. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates.rates, and for additional discussion regarding income taxes.
20182021 Compared to 2017
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy Texas’s Annual Report on Form 10-K for the year ended December 31, 20182021, filed with the SEC on February 25, 2022, for discussion of results of operations for 20182021 compared to 2017.2020.
Income Tax Legislation
See the “Income Tax Legislation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the Tax CutsInflation Reduction Act of 2022.
Liquidity and Jobs Act,Capital Resources
Cash Flow
Cash flows for the federalyears ended December 31, 2022, 2021, and 2020 were as follows:
| | | | | | | | | | | | | | | | | |
| | 2022 | | 2021 | | 2020 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period | $28 | | | $248,596 | | | $12,929 | |
| | | | | |
| Net cash provided by (used in): | | | | | |
| Operating activities | 409,427 | | | 356,933 | | | 375,325 | |
| Investing activities | (764,069) | | | (647,271) | | | (848,648) | |
| Financing activities | 358,111 | | | 41,770 | | | 708,990 | |
| Net increase (decrease) in cash and cash equivalents | 3,469 | | | (248,568) | | | 235,667 | |
| | | | | |
| Cash and cash equivalents at end of period | $3,497 | | | $28 | | | $248,596 | |
2022 Compared to 2021
Operating Activities
Net cash flow provided by operating activities increased $52.5 million in 2022 primarily due to:
•higher collections from customers;
•a decrease of $27 million in storm spending in 2022, primarily due to Hurricane Laura, Hurricane Delta, and Winter Storm Uri restoration efforts in 2021; and
•a decrease of $15.7 million in income taxes paid in 2022 as a result of lower estimated income tax legislation enactedpayments in December 2017. Note 3comparison to the financial statements contains additional discussion of the effect of the Act on 2017, 2018, and 2019 results of operations and financial position, the provisions of the Act,2021.
The increase was partially offset by increased fuel costs and the uncertainties associated with accounting for the Act,timing of recovery of fuel and purchased power costs. See Note 2 to the financial statements discusses the regulatory proceedings that have considered the effectsfor a discussion of the Act.fuel and purchased power cost recovery.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2019, 2018, and 2017 were as follows:
|
| | | | | | | | | | | |
| | 2019 | | 2018 | | 2017 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $56 |
| |
| $115,513 |
| |
| $6,181 |
|
| | | | | | |
| Net cash provided by (used in): | |
| | |
| | |
|
| Operating activities | 286,739 |
| | 331,753 |
| | 301,396 |
|
| Investing activities | (878,280 | ) | | (395,973 | ) | | (383,176 | ) |
| Financing activities | 604,414 |
| | (51,237 | ) | | 191,112 |
|
| Net increase (decrease) in cash and cash equivalents | 12,873 |
| | (115,457 | ) | | 109,332 |
|
| | | | | | |
| Cash and cash equivalents at end of period |
| $12,929 |
| |
| $56 |
| |
| $115,513 |
|
2019 Compared to 2018
Operating Activities
Net cash flow provided by operatingused in investing activities decreased $45increased $116.8 million in 20192022 primarily due to to:
•money pool activity;
•the return of unprotected excess accumulated deferred income taxes to customers and the receipt of $33.2 million in 2018 from Entergy Arkansas as a resultsale of a compliance filing made in response to the FERC’s October 2018 order7.56% partial interest in the Entergy Arkansas opportunity sales proceeding. The decrease was partially offset by the timing of recovery of fuel and purchased power costs and the timing of collection of receivables from customers.Montgomery County Power Station in June 2021 for approximately $67.9 million. See Note 214 to the financial statements for further discussion of the opportunity sales proceeding and regulatory activity regarding the Tax Cuts and Jobs Act.transaction;
Investing Activities
Net cash flow used in investing activities increased $482.3 million in 2019 primarily due to:
•an increase of $243.3$18.8 million in fossil-fueledfacilities construction expenditures primarily due to the construction of a new service facility to improve storm response and resiliency; and
•an increase of $18.4 million in non-nuclear generation construction expenditures primarily due to increasedhigher spending on the MontgomeryOrange County Advanced Power Station;
an increase of $153.4 million in transmission construction expenditures primarily due toStation project, partially offset by a higherlower scope of work performed during outages in 20192022 as compared to 2018;2021.
an
The increase was partially offset by:
•a decrease of $47.1$39.7 million in distribution construction expenditures primarily due to investmentlower capital expenditures for storm restoration in the reliability and infrastructure2022, partially offset by higher capital expenditures as a result of increased development in Entergy Texas’s distribution system, including increasedservice area. The decrease in storm restoration spending on advanced metering infrastructure,is primarily due to Hurricane Laura and increased storm spending;Hurricane Delta restoration efforts in 2021; and
money pool activity.•the purchase of the Hardin County Peaking Facility in June 2021 for approximately $36.7 million. See Note 14 to the financial statements for further discussion of the Hardin County Peaking Facility purchase.
Increases in Entergy Texas’s receivable from the money pool are a use of cash flow, and Entergy Texas’s receivable from the money pool increased by $11.2$99.5 million in 20192022 compared to decreasing $44.9by $4.6 million in 2018.2021. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Financing Activities
Entergy Texas’sNet cash flow provided by financing activities provided $604.4increased $316.3 million of cash in 2019 compared to using $51.2 million of cash in 20182022 primarily due to:
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
the issuance of $300$325 million of 4.0% Series mortgage bonds and $400 million of 4.5%5.00% Series mortgage bonds in January 2019;August 2022;
•the issuance of $300$290.85 million of 3.55%senior secured system restoration bonds in April 2022; and
•the repayment, prior to maturity, of $125 million of 2.55% Series mortgage bonds in May 2021 and the repayment, at maturity, of $75 million of 4.10% Series mortgage bonds in September 2019;2021.
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.
The increase was partially offset by by:
•money pool activity;
•the repayment, at maturity,issuance of $500$130 million of 7.125%1.50% Series mortgage bonds in August 2021;
February 2019•the payment of $105 million of common stock dividends in 2022. No common stock dividends were paid in 2021 in order to maintain Entergy Texas’s capital structure; and money pool activity. See Note 5
•capital contributions of $95 million received from Entergy Corporation in 2021 in order to the financial statements for more details on long-term debt. See Note 6 to the financial statements for more details on the issuancemaintain Entergy Texas’s capital structure and in anticipation of preferred stock.various upcoming capital expenditures.
Decreases in Entergy Texas’s payable to the money pool are a use of cash flow, and Entergy Texas’s payable
to the money pool decreased by $22.4$79.6 million in 20192022 compared to increasing by $22.4$79.6 million in 2018.2021.
2018See Note 5 to the financial statements for further details of long-term debt.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
2021 Compared to 2017
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Texas’s Annual Report on Form 10-K for the year ended December 31, 20182021, filed with the SEC on February 25, 2022, for discussion of operating, investing, and financing cash flow activities for 20182021 compared to 2017.2020.
Capital Structure
Entergy Texas’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio
for Entergy Texas is primarily due to the net issuance of $500 million of mortgage bondslong-term debt in 2019,2022, partially offset by
an increase in equity.equity resulting from retained earnings.
| | | | | | | | | | | |
| | December 31,
2022 | | December 31,
2021 |
| Debt to capital | 52.0 | % | | 48.7 | % |
| Effect of excluding securitization bonds | (2.5 | %) | | (0.5 | %) |
| Debt to capital, excluding securitization bonds (non-GAAP) (a) | 49.5 | % | | 48.2 | % |
| Effect of subtracting cash | — | % | | — | % |
| Net debt to net capital, excluding securitization bonds (non-GAAP) (a) | 49.5 | % | | 48.2 | % |
|
| | | | | |
| | December 31,
2019 | | December 31,
2018 |
| Debt to capital | 51.7 | % | | 51.6 | % |
| Effect of excluding the securitization bonds | (2.8 | %) | | (5.2 | %) |
| Debt to capital, excluding securitization bonds (a) | 48.9 | % | | 46.4 | % |
| Effect of subtracting cash | (0.2 | %) | | — | % |
| Net debt to net capital, excluding securitization bonds (a) | 48.7 | % | | 46.4 | % |
(a)Calculation excludes the securitization bonds, which are non-recourse to Entergy Texas. |
| |
(a) | Calculation excludes the securitization bonds, which are non-recourse to Entergy Texas. |
Net debt consists of debt less cash and cash equivalents. Debt consists of finance lease obligations and long-term debt, including the currently maturing portion. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. The debt to capital ratio excluding securitization bonds and net debt to net capital ratio excluding securitization bonds are non-GAAP measures. Entergy Texas uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy Texas’s financial condition because the securitization bonds are non-recourse to Entergy Texas, as more fully described in Note 5 to the financial statements. Entergy Texas also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Texas’s financial condition because net debt indicates Entergy Texas’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Texas seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Texas may issue incremental debt or reduce dividends, or both, to maintain its capital structure. In addition, Entergy Texas may receive equity
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
contributions to maintain its capital structure for certain circumstances such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reduced dividends.
Uses of Capital
Entergy Texas requires capital resources for:
•construction and other capital investments;
•debt maturities or retirements;
•working capital purposes, including the financing of fuel and purchased power costs; and
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
•dividend and interest payments.
Following are the amounts of Entergy Texas’s planned construction and other capital investments.
| | | | | | | | | | | | | | | | | |
| | 2023 | | 2024 | | 2025 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation | $580 | | | $495 | | | $710 | |
| Transmission | 135 | | | 240 | | | 230 | |
| Distribution | 345 | | | 385 | | | 425 | |
| Utility Support | 70 | | | 30 | | | 30 | |
| Total | $1,130 | | | $1,150 | | | $1,395 | |
|
| | | | | | | | | | | |
| | 2020 | | 2021 | | 2022 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation |
| $235 |
| |
| $165 |
| |
| $195 |
|
| Transmission | 265 |
| | 180 |
| | 220 |
|
| Distribution | 150 |
| | 125 |
| | 170 |
|
| Utility Support | 115 |
| | 135 |
| | 130 |
|
| Total |
| $765 |
| |
| $605 |
| |
| $715 |
|
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Texas includes investments in generation projects to modernize, decarbonize, and diversify Entergy Texas’s portfolio, including Orange County Advanced Power Station; distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to drive reliability and resilience while also supporting renewables expansion; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, government actions, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.
Following are the amounts of Entergy Texas’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations..
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2023 | | 2024 | | 2025 | | 2026-2027 | | After 2027 |
| | (In Millions) |
| Long-term debt (a) | $120 | | | $120 | | | $120 | | | $517 | | | $3,801 | |
| Operating leases (b) | $6 | | | $5 | | | $4 | | | $3 | | | $1 | |
| Finance leases (b) | $2 | | | $2 | | | $2 | | | $2 | | | $1 | |
|
| | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2021-2022 | | 2023-2024 | | After 2024 | | Total |
| | (In Millions) |
| Long-term debt (a) |
| $164 |
| |
| $466 |
| |
| $133 |
| |
| $2,683 |
| |
| $3,446 |
|
| Operating leases (b) |
| $4 |
| |
| $7 |
| |
| $4 |
| |
| $1 |
| |
| $16 |
|
| Finance leases (b) |
| $1 |
| |
| $2 |
| |
| $2 |
| |
| $1 |
| |
| $6 |
|
| Purchase obligations (c) |
| $280 |
| |
| $434 |
| |
| $514 |
| |
| $1,039 |
| |
| $2,267 |
|
| |
(a) | Includes estimated interest payments. (a)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. |
In addition to the contractualfinancial statements.
(b)Lease obligations given above, are discussed in Note 10 to the financial statements.
Other Obligations
Entergy Texas expects to contribute approximately $3.5$5.3 million to its qualified pension plans and approximately $61$86 thousand to other postretirement health care and life insurance plans in 2020,2023, although the 20202023 required pension contributions will be known with more certainty when the January 1, 20202023 valuations are completed, which is expected by April 1, 2020.2023. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Also in addition to the contractual obligations, Entergy Texas has $17.5$12.3 million of unrecognized tax benefits and interest net of unused tax attributes plus interest and payments for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Texas includes specific investments such as the Montgomery County Power Station; transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including advanced meters and related investments; system improvements; software and security; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital. Management provides more information on long-term debt in Note 5 to the financial statements.
As a subsidiary, Entergy Texas dividends its earnings to Entergy Corporation at a percentage determined monthly.
MontgomeryOrange County Advanced Power Station
In October 2016,September 2021, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the Orange County Advanced Power Station, a new 1,215 MW combined-cycle combustion turbine facility to be located in Bridge City, Texas at an initially-estimated expected total cost of $1.2 billion inclusive of the estimated costs of the generation facilities, transmission upgrades, contingency, an allowance for funds used during construction, and necessary regulatory expenses, among others. The project includes combustion turbine technology with dual fuel capability, able to co-fire up to 30% hydrogen by volume upon commercial operation and upgradable to support 100% hydrogen operations in the future. In December 2021 the PUCT referred the proceeding to the State Office of Administrative Hearings. In March 2022 certain intervenors filed testimony opposing the hydrogen co-firing component of the proposed project and others filed testimony opposing the project outright. Also in March 2022 the PUCT staff filed testimony opposing the hydrogen co-firing component of the proposed project, but otherwise taking no specific position on the merits of the project. The PUCT staff also proposed that the PUCT establish a maximum amount that Entergy Texas may recover in rates attributable to the project. In April 2022, Entergy Texas filed rebuttal testimony addressing and rebutting these various arguments. The hearing on the merits was held in June 2022, and post-hearing briefs were submitted in July 2022. In September 2022 the ALJs with the State Office of Administrative Hearings issued a proposal for decision recommending the PUCT approve Entergy Texas’s application for certification of Orange County Advanced Power Station subject to certain conditions, including a cap on cost recovery at $1.37 billion, the exclusion of investment associated with co-firing hydrogen, weatherization requirements, and customer receipt of any contractual benefits associated with the facility’s guaranteed heat rate. In October 2022 the parties in the proceeding filed exceptions and replies to exceptions to the proposal for decision. Also in October 2022, Entergy Texas filed with the PUCT seeking certification thatinformation regarding a new fixed pricing option for an estimated project cost of approximately $1.55 billion associated with Entergy Texas’s issuance of limited notice to proceed by mid-November 2022. In November 2022 the publicPUCT issued a final order approving the requested amendment to Entergy Texas’s certificate of convenience and necessity would be served byto construct, own, and operate the constructionOrange County Advanced Power Station without the investment associated with hydrogen co-firing capability, without a cap on cost recovery, and subject to certain conditions, including weatherization requirements and customer receipt of any contractual benefits associated with the facility’s guaranteed heat rate.
In December 2022, Texas Industrial Energy Consumers and Sierra Club filed motions for rehearing of the MontgomeryPUCT’s final order alleging the PUCT erred in granting the certification of the Orange County Advanced Power Station, in not imposing a nominal 993 MW combined-cycle generating unitcost cap, in Willis, Texas, on land adjacentincluding certain findings related to the existing Lewis Creek plant. The current estimated costreasonableness of the Montgomery County Power Station is $937 million, including approximately $111 million of transmission interconnection and network upgrades and other related costs. The independent monitor, who oversaw theEntergy Texas’s request for proposal process, filed testimony and a report affirming thatproposals from which the MontgomeryOrange County Advanced Power Station was selected, throughand in other regards. Also in December 2022, Entergy Texas filed a response to the motions for rehearing refuting the points raised therein. In January 2023 the PUCT issued letters noting that it voted to consider Texas Industrial Energy Consumers’ motion for rehearing at its upcoming January 2023 open meeting and voted not to consider Sierra Club’s motion for rehearing at an objective and fairopen meeting. At the January 2023 open meeting, the PUCT voted to grant Texas Industrial Energy Consumers’ motion for rehearing for the limited purpose of issuing an order on rehearing that excludes three findings related to Entergy Texas’s request for proposal processproposals. The order on rehearing does not change the PUCT’s certification of the Orange County Advanced Power Station or the conditions placed thereon in the PUCT’s November 2022 final order. Entergy Texas also is pursuing environmental permitting that showed no undue preference to any proposal. In June 2017 partiesis required prior to the proceeding filed an unopposed stipulation and settlement agreement. The stipulation contemplates that Entergy Texas’s levelcommencement of cost-recovery for generation construction costs for Montgomery County Power Station is capped at $831 million, subjectconstruction. Subject to certain exclusions such as force majeure events. Transmission interconnection and network upgradesreceipt of required regulatory approvals, permits, and other related costs are not subjectconditions, the facility is expected to the $831 million cap. In July 2017 the PUCT approved the stipulation. Subject to the timely receiptbe in service by mid-2026.
Entergy Texas, Inc. and approvals, commercial operation is estimated to occur by mid-2021.Subsidiaries
Management’s Financial Discussion and Analysis
Sources of Capital
Entergy Texas’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•the Entergy System money pool;
•debt or preferred stock issuances;issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations, Entergy Texas may refinance, redeem, or otherwiseexpects to continue, when economically feasible, to retire higher-cost debt prior to maturity, to the extentand replace it with lower-cost debt if market conditions and interest and dividend rates are favorable.permit.
All debt and common and preferred stock issuances by Entergy Texas require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in its bond indenture and other agreements. Entergy Texas has sufficient capacity under these tests to meet its foreseeable capital needs.needs for the next twelve months and beyond.
Entergy Texas’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
| | | | | | | | | | | | | | | | | | | | |
| 2022 | | 2021 | | 2020 | | 2019 |
| (In Thousands) |
| $99,468 | | ($79,594) | | $4,601 | | $11,181 |
|
| | | | | | |
| 2019 | | 2018 | | 2017 | | 2016 |
| (In Thousands) |
| $11,181 | | ($22,389) | | $44,903 | | $681 |
See Note 4 to the financial statements for a description of the money pool.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Texas has a credit facility in the amount of $150 million scheduled to expire in September 2024.June 2027. The credit facility includes fronting commitments for the issuance of letters of credit against $30 million of the borrowing capacity of the facility. As of December 31, 2019,2022, there were no cash borrowings and $1.3$1.1 million of letters of credit outstanding under the credit facility. In addition, Entergy Texas is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2019, a $12.12022, $34.8 million letterin letters of credit waswere outstanding under Entergy Texas’s uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.
Entergy Texas obtained authorizations from the FERC through November 2020October 2023 for short-term borrowings, not to exceed an aggregate amount of $200 million at any time outstanding, and long-term borrowings and security issuances. See Note 4 to the financial statements for further discussion of Entergy Texas’s short-term borrowing limits.
Hurricane Laura, Hurricane Delta, and Winter Storm Uri
In August 2020 and October 2020, Hurricane Laura and Hurricane Delta caused extensive damage to Entergy Texas’s service area. In February 2021, Winter Storm Uri also caused damage to Entergy Texas’s service area. The storms resulted in widespread power outages, significant damage primarily to distribution and transmission infrastructure, and the loss of sales during the power outages. In April 2021, Entergy Texas filed an application with the PUCT requesting a determination that approximately $250 million of system restoration costs associated with Hurricane Laura, Hurricane Delta, and Winter Storm Uri, including approximately $200 million in
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
capital costs and approximately $50 million in non-capital costs, were reasonable and necessary to enable Entergy Texas to restore electric service to its customers and Entergy Texas’s electric utility infrastructure. The filing also included the projected balance of approximately $13 million of a regulatory asset containing previously approved system restoration costs related to Hurricane Harvey. In September 2021 the parties filed an unopposed settlement agreement, pursuant to which Entergy Texas removed from the amount to be securitized approximately $4.3 million that will instead be charged to its storm reserve, $5 million related to no particular issue, of which Entergy Texas would be permitted to seek recovery in a future proceeding, and approximately $300 thousand related to attestation costs. In December 2021 the PUCT issued an order approving the unopposed settlement and determining system restoration costs of $243 million related to Hurricane Laura, Hurricane Delta, and Winter Storm Uri and the $13 million projected remaining balance of the Hurricane Harvey system restoration costs were eligible for securitization. The order also determines that Entergy Texas can recover carrying costs on the system restoration costs related to Hurricane Laura, Hurricane Delta, and Winter Storm Uri.
In July 2021, Entergy Texas filed with the PUCT an application for a financing order to approve the securitization of the system restoration costs that are the subject of the April 2021 application. In November 2021 the parties filed an unopposed settlement agreement supporting the issuance of a financing order consistent with Entergy Texas’s application and with minor adjustments to certain upfront and ongoing costs to be incurred to facilitate the issuance and serving of system restoration bonds. In January 2022 the PUCT issued a financing order consistent with the unopposed settlement. As a result of the financing order, Entergy Texas reclassified $153 million from utility plant to other regulatory assets.
In April 2022, Entergy Texas Restoration Funding II, LLC, a company wholly-owned and consolidated by Entergy Texas, issued $290.85 million of senior secured system restoration bonds (securitization bonds). With the proceeds, Entergy Texas Restoration Funding II purchased from Entergy Texas the transition property, which is the right to recover from customers through a system restoration charge amounts sufficient to service the securitization bonds. Entergy Texas began cost recovery through the system restoration charge effective with the first billing cycle of May 2022 and the system restoration charge is expected to remain in place up to 15 years. See Note 5 to the financial statements for a discussion of the April 2022 issuance of the securitization bonds.
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy Texas charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Texas is regulated, and the rates charged to its customers are determined in regulatory proceedings. The PUCT, aA governmental agency, the PUCT, is primarily responsible for approval of the rates charged to customers.
Filings with the PUCT and Texas Cities
2018Retail Rates
2022 Base Rate Case
In May 2018,In July 2022, Entergy Texas filed a base rate case with the PUCT seeking ana net 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$131.4 million. The base rate case was based on a 12-month test year ending December 31, 2017.2021. Key drivers of the requested increase are changes in depreciation rates as the result of a depreciation study and an increase in the return on equity. In addition, Entergy Texas included capital additions placed into service for the period of AprilJanuary 1, 20132018 through December 31, 2017, as well2021, including those additions currently reflected in the distribution and transmission cost recovery factor riders and the generation cost recovery rider, all of which would be reset to zero as a post-test year adjustmentresult of this proceeding. In July 2022 the PUCT referred the proceeding to includethe State Office of Administrative Hearings. In October 2022 intervenors filed direct testimony challenging and supporting various aspects of Entergy Texas’s rate case application. The key issues addressed included the appropriate return on equity, generation plant deactivations, depreciation rates, and proposed tariffs related to electric vehicles. In
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
November 2022 the PUCT staff filed direct testimony addressing a similar set of issues and recommending a reduction of $50.7 million to Entergy Texas’s overall cost of service associated with the requested net increase in base rates of approximately $131.4 million. Entergy Texas filed rebuttal testimony in November 2022. In December 2022 the ALJs with the State Office of Administrative Hearings issued an order adopting the parties’ joint proposals that the issue of rate case expenses be addressed at a separate hearing and at a later date, if requested by the parties, from the hearing on the merits initially scheduled for December 2022 and that issues related to electric vehicle charging infrastructure be decided exclusively on written evidence and briefing. Also in December 2022, Entergy Texas filed on behalf of the parties a motion to abate the hearing on the merits to give parties additional time to finalize a settlement, which was approved by the ALJs with the State Office of Administrative Hearings along with an order for the parties to file monthly settlement status reports. Subsequently, the ALJs also issued an order adopting a joint proposed briefing outline and schedule with deadlines in January 2023 for the parties to submit briefing on issues related to electric vehicle charging infrastructure, admitting evidence related to electric vehicle charging infrastructure issues, and adopting a joint proposed procedural schedule regarding rate case expenses with a hearing in March 2023, if requested. In January 2023 the parties filed initial and reply briefs addressing issues related to electric vehicle charging infrastructure. A final decision by the PUCT is expected in second quarter 2023.
Distribution Cost Recovery Factor (DCRF) Rider
In March 2020, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $23.6 million annually, or $20.4 million in incremental annual DCRF revenue beyond Entergy Texas’s then-effective DCRF rider, based on its capital additions placedinvested in service bydistribution between January 1, 2019 and December 31, 2019. In May and June 30, 2018.2020 intervenors filed testimony recommending reductions in Entergy Texas’s annual revenue requirement of approximately $0.3 million and $4.1 million. The parties briefed the contested issues in this matter and a proposal for decision was issued in September 2020 recommending a $4.1 million revenue reduction related to non-advanced metering system meters included in the DCRF calculation. The parties filed exceptions to the proposal for decision and replies to those exceptions in September 2020. In October 2020 the PUCT issued a final order approving a $16.3 million incremental annual DCRF revenue increase, with rates effective in October 2020.
In October 20182020, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $26.3 million annually, or $6.8 million in incremental annual revenues beyond Entergy Texas’s then-effective DCRF rider based on its capital invested in distribution between January 1, 2020 and August 31, 2020. In February 2021 the ALJ with the State Office of Administrative Hearings approved Entergy Texas's agreed motion for interim rates, which went into effect in March 2021. In March 2021 the parties filed an unopposed settlement recommending that Entergy Texas be allowed to collect its full requested DCRF revenue requirement and 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.proceeding. 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 2018May 2021 the PUCT issued an order approving the unopposed settlement.
In January 2019,August 2021, Entergy Texas filed for recoverywith the PUCT a request to amend its DCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $40.2 million annually, or $13.9 million in incremental annual revenues beyond Entergy Texas’s then-effective DCRF rider based on its capital invested in distribution between September 1, 2020 and June 30, 2021. In September 2021 the PUCT referred the proceeding to the State Office of rate case expenses totaling $7.2 million. The amounts requested primarily include internal and external expenses related to litigatingAdministrative Hearings. A procedural schedule was established with a hearing scheduled in December 2021. In December 2021 the 2018 base rate case. Partiesparties filed testimony in April 2019an unopposed settlement recommending a disallowance ranging from $3.2 million to $4.2 million of the $7.2 million requested. In May 2019,that Entergy Texas filed rebuttal testimony respondingbe allowed to collect its full requested DCRF revenue requirement and resolving all issues in the proceeding, including a motion for interim rates to take effect for usage on and after January 24, 2022. Also, in December 2021, the ALJ with the State Office of Administrative Hearings issued an order granting the motion for interim rates, which went into effect in January 2022, admitting evidence, and remanding the proceeding to the parties’ positions.PUCT to consider the settlement. In September 2019March 2022 the PUCT issued an order was issued abatingapproving the procedural schedule and scheduled hearing to allow the finalization of a settlementsettlement.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
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 2018 base rate case discussion.
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 below, Entergy Texas and the PUCT staff reached a settlement agreeing to the amended TCRF annual revenue requirement of $29.5 million. As discussed below, 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 discussed 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 iswas 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,October 2020, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The proposed new TCRFamended rider iswas designed to collect approximately $19.4 million annually from Entergy Texas’s retail customers approximately $51 million annually, or $31.6 million in incremental annual revenues beyond Entergy Texas’s then-effective TCRF rider based on its capital invested in transmission between JanuaryJuly 1, 20182019 and June 30, 2019, which is $16.7 million in incremental annual revenue aboveAugust 31, 2020. In March 2021 the $2.7 million approved in the prior pending TCRF proceeding. In November 2019, Entergy Texasparties filed an unopposed stipulationsettlement recommending that Entergy Texas be allowed to collect its full requested TCRF revenue requirement with interim rates effective March 2021 and settlement agreement providingresolving all issues in the proceeding. In March 2021 the ALJ granted the motion for recoveryinterim rates, admitted evidence, and remanded the case to the PUCT for consideration of the requested revenue requirement.a final order at a future open meeting. In January 2020June 2021 the PUCT issued an order approving the unopposed settlement.
In October 2021, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $66.1 million annually, or $15.1 million in incremental annual revenues beyond Energy Texas’s then-effective TCRF rider based on its capital invested in transmission between September 1, 2020 and July 31, 2021 and changes in approved transmission charges. In January 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In February 2022 the parties filed an unopposed settlement recommending that Entergy Texas be allowed to collect its full requested TCRF revenue requirement with interim rates effective March 2022. In February 2022 the ALJ granted the motion for interim rates, admitted evidence, and remanded the case to the PUCT for consideration of a final order at a future open meeting. In June 2022 the PUCT issued an order approving the settlement.
Generation Cost Recovery Rider
In October 2020, Entergy Texas filed an application to establish a generation cost recovery rider with an initial annual revenue requirement of approximately $91 million to begin recovering a return of and on its generation capital investment in the Montgomery County Power Station through August 31, 2020. In December 2020, Entergy Texas filed an unopposed settlement supporting a generation cost recovery rider with an annual revenue requirement of approximately $86 million. The settlement revenue requirement was based on a depreciation rate intended to fully depreciate Montgomery County Power Station over 38 years and the removal of certain costs from Entergy Texas’s request. Under the settlement, Entergy Texas retained the right to propose a different depreciation rate and seek recovery of a majority of the costs removed from its request in its next base rate proceeding, which proceeding commenced in June 2022. On January 14, 2021, the PUCT approved the generation cost recovery rider settlement rates on an interim basis and abated the proceeding. In March 2021, Entergy Texas filed to update its generation cost recovery rider to include its generation capital investment in Montgomery County Power Station after August 31, 2020. In April 2021 the ALJ issued an order unabating the proceeding and in May 2021 the ALJ issued an order finding Entergy Texas’s application and notice of the application to be sufficient. In May 2021, Entergy Texas filed an amendment to the application to reflect the PUCT’s approval of the sale of a 7.56% partial interest in the Montgomery County Power Station to East Texas Electric Cooperative, Inc., which
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Advanced Metering Infrastructure (AMI)
closed in June 2021. In June 2021 the PUCT referred the proceeding to the State Office of Administrative Hearings. In July 2021 the ALJ with the State Office of Administrative Hearings adopted a procedural schedule setting a hearing on the merits for September 2021. In July 2021 the parties filed a motion to abate the procedural schedule noting they had reached an agreement in principle and to allow the parties time to finalize a settlement agreement, which motion was granted by the ALJ. In October 2021, Entergy Texas filed on behalf of the parties an unopposed settlement agreement that would adjust its generation cost recovery rider to recover an annual revenue requirement of approximately $88.3 million related to Entergy Texas’s investment in the Montgomery County Power Station through January 1, 2021, with Entergy Texas able to seek recovery of the remainder of its investment in its next base rate case. Also in October 2021 the ALJ granted a motion to admit evidence and remand the proceeding to the PUCT. In January 2022 the PUCT issued an order approving the unopposed settlement. In February 2022, Entergy Texas filed a relate-back rider to collect over five months an additional approximately $5 million, which is the difference between the interim revenue requirement approved in January 2021 and the revenue requirement approved in January 2022 that reflects Entergy Texas’s full generation capital investment and ownership in Montgomery County Power Station on January 1, 2021, plus carrying costs from January 2021 through January 2022 when the updated revenue requirement took effect. In April 2017 the Texas legislature enacted legislation that extends statutory support for AMI deployment to2022, Entergy Texas and directs that ifthe PUCT staff filed a joint proposed order supporting approval of Entergy Texas’s as-filed request. The PUCT approved the relate-back rider consistent with Entergy Texas’s as-filed request, and rates became effective over a five-month period, in August 2022.
In December 2020, Entergy Texas electsalso filed an application to deploy AMI, it shall do so as rapidly as practicable.amend its generation cost recovery rider to reflect its acquisition of the Hardin County Peaking Facility, which closed in June 2021. Because Hardin was to be acquired in the future, the initial generation cost recovery rider rates proposed in the application represented no change from the generation cost recovery rider rates established in Entergy Texas’s previous generation cost recovery rider proceeding. In July 2017,2021 the PUCT issued an order approving the application. In August 2021, Entergy Texas filed an update application to recover its actual investment in the acquisition of the Hardin County Peaking Facility. In September 2021 the PUCT referred the proceeding to the State Office of Administrative Hearings. A procedural schedule was established with a hearing scheduled in April 2022. In January 2022, Entergy Texas filed an update to its application to align the requested revenue requirement with the terms of the generation cost recovery rider settlement approved by the PUCT in January 2022. In March 2022, Entergy Texas filed on behalf of the parties an unopposed motion, which motion was granted by the ALJ with the State Office of Administrative Hearings, to abate the procedural schedule indicating that the parties had reached an agreement in principle. In April 2022, Entergy Texas filed on behalf of the parties a unanimous settlement agreement that would adjust its generation cost recovery rider to recover an annual revenue requirement of approximately $92.8 million, which is $4.5 million in incremental annual revenue above the $88.3 million approved in January 2022, related to Entergy Texas’s actual investment in the acquisition of the Hardin County Peaking Facility. Concurrently with filing of the unanimous settlement agreement, Entergy Texas submitted an agreed motion to admit evidence and remand the case to the PUCT for review and consideration of the settlement agreement, which motion was granted by the ALJ with the State Office of Administrative Hearings. The PUCT approved the settlement agreement and rates became effective in August 2022. In September 2022, Entergy Texas filed a relate-back rider designed to collect over three months an additional approximately $5.7 million, which is the revenue requirement, plus carrying costs, associated with Entergy Texas’s acquisition of Hardin County Peaking Facility from June 2021 through August 2022 when the updated revenue requirement took effect. No party requested a hearing on the application and in November 2022 the PUCT staff filed a recommendation that the application be approved as-filed. In December 2022, Entergy Texas filed a joint motion to admit evidence, which was approved by the PUCT, and a proposed order that would approve its as-filed application. A PUCT decision is expected in the first quarter of 2023. See Note 14 to the financial statements for further discussion of the Hardin County Peaking Facility purchase.
Green Pricing Option Tariffs
In January 2022, Entergy Texas filed an application seeking an order from the PUCT approving Entergy Texas’s deploymentrequesting approval to implement two voluntary renewable option tariffs, Rider Small Volume Renewable Option (Rider SVRO) and Rider Large Volume
Entergy Texas, proposedInc. and Subsidiaries
Management’s Financial Discussion and Analysis
Renewable Option (Rider LVRO). Both tariffs are voluntary offerings that give customers the ability to replace existing metersmatch some or all of their monthly electricity usage with advanced metersrenewable energy credits that enable two-way data communication; designare purchased by Entergy Texas and build a secureretired on the customer’s behalf. Voluntary participation in either Rider SVRO or Rider LVRO and reliable networkthe charges assessed under the respective tariff would be in addition to support such communications;the charges paid by customers under their otherwise applicable rate schedules and implement support systems. AMI is intended to serve asriders. In April 2022, Entergy Texas filed on behalf of the foundationparties an unopposed settlement agreement supporting approval of Entergy Texas’s modernized power grid. The filing included an estimateproposed green pricing option tariffs. As part of implementation costs for AMI of $132 million and identified a number of quantified and unquantified benefits.the settlement agreement, Entergy Texas proposed a seven-year depreciable life foragreed to revise the new advanced meters. Entergy Texas also proposed a surchargecost allocation between the rate tiers of Rider SVRO and committed to collaborating with and considering the input of customers to develop an asset-backed green 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.program. The PUCT approved the stipulation and settlement agreement in December 2017.August 2022.
COVID-19 Orders
In March 2020 the PUCT authorized electric utilities to record as a regulatory asset expenses resulting from the effects of the COVID-19 pandemic. In future proceedings, the PUCT will consider whether each utility's request for recovery of these regulatory assets is reasonable and necessary, the appropriate period of recovery, and any amount of carrying costs thereon. In March 2020 the PUCT ordered a moratorium on disconnections for nonpayment for all customer classes, but, in April 2020, revised the disconnect moratorium to apply only to residential customers. The PUCT allowed the moratorium to expire on June 13, 2020, but on July 17, 2020, the PUCT re-established the disconnect moratorium for residential customers until August 31, 2020. In January 2021, Entergy Texas implemented the AMI surcharge tariff beginningresumed disconnections for customers with January 2018 bills.past-due balances that have not made payment arrangements. As of December 31, 2019,2022, 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 throughhad a regulatory asset to be amortized at current depreciation rates, as approved byof $10.4 million for costs associated with the PUCT.COVID-19 pandemic. As part of its 2022 base rate case filing, Entergy Texas requested recovery of its regulatory asset over a three-year period beginning December 2022.
Fuel and Purchased Power Cost Recovery
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.
In July 2015 certain parties filed briefs in the open proceeding asserting that Entergy Texas should refund to retail customers an additional $10.9 million in bandwidth remedy payments Entergy Texas received related to calendar year 2006 production costs. In October 2015 an ALJ issued a proposal for decision recommending that the additional $10.9 million in 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 to the U.S. Court of Appeals for the Fifth Circuit of the Federal District Court ruling. 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 a notice of nonsuit in its appeal to the Travis County District Court regarding the PUCT’s January 2016 decision.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
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 above, and the terms and conditions in both settlements are interdependent. The A fuel reconciliation settlement was approved by the PUCT in March 2017is required to be filed at least once every three years and the refunds were made.outside of a base rate case filing.
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 January 2018 through March 2018. The fuel refund was approved by the PUCT in March 2018.
In September 2019, Entergy Texas filed an application to reconcile its fuel and purchased power costs for the period from April 2016 through March 2019. During the reconciliation period, Entergy Texas incurred approximately $1.6 billion in Texas jurisdictional eligible fuel and purchased power expenses, net of certain revenues credited to such expenses and other adjustments. Entergy Texas estimated an under-recovery balance of approximately $25.8 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning April 2019. In March 2020 an intervenor filed testimony proposing that the PUCT disallow: (1) $2 million in replacement power costs associated with generation outages during the reconciliation period; and (2) $24.4 million associated with the operation of the Spindletop natural gas storage facility during the reconciliation period. In April 2020, Entergy Texas filed rebuttal testimony refuting all points raised by the intervenor. In June 2020 the parties filed a stipulation and settlement agreement, which included a $1.2 million disallowance not associated with any particular issue raised by any party. The PUCT approved the settlement in August 2020.
In July 2020, Entergy Texas filed an application with the PUCT to implement an interim fuel refund of $25.5 million, including interest. Entergy Texas proposed that the interim fuel refund be implemented beginning with the first August 2020 billing cycle over a three-month period for smaller customers and in a lump sum amount in the billing month of August 2020 for transmission-level customers. The interim fuel refund was approved in July 2020, and Entergy Texas began refunds in August 2020.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
In May 2022, Entergy Texas filed an application with the PUCT to implement an interim fuel surcharge to collect the cumulative under-recovery of approximately $51.7 million, including interest, of fuel and purchased power costs incurred from May 1, 2020 through December 31, 2021. The under-recovery balance is primarily attributable to the impacts of Winter Storm Uri, including historically high natural gas prices, partially offset by settlements received by Entergy Texas from MISO related to Hurricane Laura. Entergy Texas proposed that the interim fuel surcharge be assessed over a period of six months beginning with the first billing cycle after the PUCT issues a final order, but no later than the first billing cycle of September 2022. Also in May 2022, the PUCT referred the proceeding to the State Office of Administrative Hearings. In July 2022, Entergy Texas filed on behalf of the parties an unopposed settlement resolving all issues in the proceeding. In addition, Entergy Texas filed on behalf of the parties a motion to admit evidence, to approve interim rates as requested in the initial application, and to remand the proceeding to the PUCT to consider the unopposed settlement. In August 2022 the ALJ with the State Office of Administrative Hearings issued an order granting Entergy Texas’s motion, approving interim rates effective with the first billing cycle of September 2022, and remanding the case to the PUCT for final approval. The interim fuel surcharge was approved by the PUCT in January 2023.
In September 2022, Entergy Texas filed an application with the PUCT to reconcile its fuel and purchased power costs for the period from April 2019 through March 2022. During the reconciliation period, Entergy Texas incurred approximately $1.7 billion in eligible fuel and purchased power expenses, net of certain revenues credited to such expenses and other adjustments. As of the end of the reconciliation period, Entergy Texas’s cumulative under-recovery balance was approximately $103.1 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning April 2022, pending future surcharges or refunds as approved by the PUCT. In November 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings and the ALJ with the State Office of Administrative Hearings adopted a procedural schedule setting a hearing on the merits for May 2023. A PUCT decision is currently pending.expected in September 2023.
Federal Regulation
See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.
Nuclear Matters
See the “Nuclear Matters” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of nuclear matters.
Industrial and Commercial Customers
Entergy Texas’s large industrial and commercial customers continually explore ways to reduce their energy costs. In particular, cogeneration is an option available to a portion of Entergy Texas’s industrial customer base. Entergy Texas responds by working with industrial and commercial customers and negotiating electric service contracts to provide, under existing rate schedules, competitive rates that match specific customer needs and load profiles. Entergy Texas actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand, from both new and existing customers.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Environmental Risks
Entergy Texas’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Texas is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of Entergy Texas’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements that could produce estimates that would have a material effect on the presentation of Entergy Texas’s financial position or results of operations.
Utility Regulatory Accounting
See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.
Impairment of Long-lived Assets and Trust Fund Investments
See “Impairment of Long-lived Assets and Trust Fund Investments” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the impairment of long-lived assets.
Taxation and Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.
Qualified Pension and Other Postretirement Benefits
Entergy Texas’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries’ Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension and qualified projected benefit obligation cost to changes in certain actuarial assumptions (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2023 Qualified Pension Cost | | Impact on 2022 Qualified Projected Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $263 | | $5,673 |
| Rate of return on plan assets | | (0.25%) | | $604 | | $— |
| Rate of increase in compensation | | 0.25% | | $218 | | $960 |
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2020 Qualified Pension Cost | | Impact on 2019 Qualified Projected Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $535 | | $9,465 |
| Rate of return on plan assets | | (0.25%) | | $783 | | $— |
| Rate of increase in compensation | | 0.25% | | $347 | | $1,676 |
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation changes in certain actuarial assumptions (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2023 Postretirement Benefit Cost | | Impact on 2022 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $89 | | $1,257 |
| Health care cost trend | | 0.25% | | $176 | | $982 |
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2020 Postretirement Benefit Cost | | Impact on 2019 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $— | | $2,673 |
| Health care cost trend | | 0.25% | | $97 | | $2,050 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Employer Contributions
Total qualified pension cost for Entergy Texas in 20192022 was $5.7 million.$29.8 million, including $22.4 million in settlement costs. Entergy Texas anticipates 20202023 qualified pension cost to be $8.4$4.4 million. Entergy Texas contributed $3.7$2.5 million to its qualified pension plans in 20192022 and estimates 20202023 pension contributions will be approximately $3.5$5.3 million, although the 20202023 required pension contributions will be known with more certainty when the January 1, 20202023 valuations are completed, which is expected by April 1, 2020.2023.
Total postretirement health care and life insurance benefit income for Entergy Texas in 20192022 was $6.5$11.1 million. Entergy Texas expects 20202023 postretirement health care and life insurance benefit income to approximate $6.7$8.8 million. In 2019,2022, Entergy Texas’ postretirement contributions (that is, contributions to the external trusts plus claims payments) were offset by trust claims reimbursements, resulting in a net reimbursement of $596$23 thousand. Entergy Texas estimates 2020that 2023 contributions will be approximately $61$86 thousand.
Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and Board of Directors of
Entergy Texas, Inc. and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy Texas, Inc. and Subsidiaries (the “Company”) as of December 31, 20192022 and 2018,2021, the related consolidated statements of income, cash flows, and changes in common equity (pages 405441 through 410446 and applicable items in pages 4953 through 236)245), for each of the three years in the period ended December 31, 2019,2022, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20192022 and 2018,2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2022, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Rate and Regulatory Matters —Entergy Texas, Inc. and Subsidiaries — Refer to Note 2 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Public Utility Commission of Texas (the “PUCT”), which has jurisdiction with respect to the rates of electric companies in Texas, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.
The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the PUCT and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the PUCT and the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs and refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the PUCT and the FERC, involved specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and significant auditor judgment to evaluate management estimates and the subjectivity of audit evidence.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the PUCT and the FERC included the following, among others:
•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 Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the PUCT and the FERC for the Company, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the PUCT’s 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.
•For regulatory matters in process, we inspected the Company’s filings with the PUCT and the FERC, including the base rate case filing, and considered the filings with the PUCT and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.
•We obtained an analysis from management and support 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 not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 21, 202024, 2023
We have served as the Company’s auditor since 2001.
|
| | | | | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | | |
| | | For the Years Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | |
| $1,488,955 |
| |
| $1,605,902 |
| |
| $1,544,893 |
|
| | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 162,544 |
| | 204,830 |
| | 225,517 |
|
| Purchased power | | 602,563 |
| | 614,012 |
| | 610,279 |
|
| Other operation and maintenance | | 258,924 |
| | 238,400 |
| | 230,437 |
|
| Taxes other than income taxes | | 76,366 |
| | 82,033 |
| | 79,254 |
|
| Depreciation and amortization | | 153,286 |
| | 128,534 |
| | 117,520 |
|
| Other regulatory charges - net | | 88,770 |
| | 131,667 |
| | 82,328 |
|
| TOTAL | | 1,342,453 |
| | 1,399,476 |
| | 1,345,335 |
|
| | | | | | | |
| OPERATING INCOME | | 146,502 |
| | 206,426 |
| | 199,558 |
|
| | | | | | | |
| OTHER INCOME | | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 28,445 |
| | 9,723 |
| | 6,722 |
|
| Interest and investment income | | 3,072 |
| | 2,188 |
| | 981 |
|
| Miscellaneous - net | | 546 |
| | (655 | ) | | 14 |
|
| TOTAL | | 32,063 |
| | 11,256 |
| | 7,717 |
|
| | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
|
| Interest expense | | 86,333 |
| | 87,203 |
| | 86,719 |
|
| Allowance for borrowed funds used during construction | | (13,269 | ) | | (5,513 | ) | | (4,098 | ) |
| TOTAL | | 73,064 |
| | 81,690 |
| | 82,621 |
|
| | | | | | | |
| INCOME BEFORE INCOME TAXES | | 105,501 |
| | 135,992 |
| | 124,654 |
|
| | | | | | | |
| Income taxes | | (53,896 | ) | | (26,243 | ) | | 48,481 |
|
| | | | | | | |
| NET INCOME | | 159,397 |
| | 162,235 |
| | 76,173 |
|
| | | | | | | |
| Preferred dividend requirements | | 580 |
| | — |
| | — |
|
| | | | | | | |
| EARNINGS APPLICABLE TO COMMON STOCK | |
| $158,817 |
| |
| $162,235 |
| |
| $76,173 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | |
| | | For the Years Ended December 31, |
| | | 2022 | | 2021 | | 2020 |
| | | (In Thousands) |
| | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | | $2,288,905 | | | $1,902,511 | | | $1,587,125 | |
| | | | | | |
| OPERATING EXPENSES | | | | | | |
| Operation and Maintenance: | | | | | | |
| Fuel, fuel-related expenses, and gas purchased for resale | | 443,765 | | | 335,742 | | | 238,428 | |
| Purchased power | | 717,501 | | | 588,941 | | | 510,633 | |
| Other operation and maintenance | | 312,340 | | | 281,713 | | | 250,170 | |
| Taxes other than income taxes | | 101,673 | | | 94,989 | | | 72,909 | |
| Depreciation and amortization | | 230,692 | | | 214,838 | | | 177,738 | |
| Other regulatory charges (credits) - net | | 49,175 | | | 59,581 | | | 90,398 | |
| TOTAL | | 1,855,146 | | | 1,575,804 | | | 1,340,276 | |
| | | | | | |
| OPERATING INCOME | | 433,759 | | | 326,707 | | | 246,849 | |
| | | | | | |
| OTHER INCOME | | | | | | |
| Allowance for equity funds used during construction | | 13,527 | | | 9,892 | | | 44,073 | |
| Interest and investment income | | 4,141 | | | 837 | | | 1,201 | |
| Miscellaneous - net | | (6,572) | | | 721 | | | (28) | |
| TOTAL | | 11,096 | | | 11,450 | | | 45,246 | |
| | | | | | |
| INTEREST EXPENSE | | | | | | |
| Interest expense | | 95,454 | | | 87,787 | | | 92,920 | |
| Allowance for borrowed funds used during construction | | (4,547) | | | (3,980) | | | (18,940) | |
| TOTAL | | 90,907 | | | 83,807 | | | 73,980 | |
| | | | | | |
| INCOME BEFORE INCOME TAXES | | 353,948 | | | 254,350 | | | 218,115 | |
| | | | | | |
| Income taxes | | 50,621 | | | 25,526 | | | 3,042 | |
| | | | | | |
| NET INCOME | | 303,327 | | | 228,824 | | | 215,073 | |
| | | | | | |
| Preferred dividend requirements | | 2,072 | | | 1,909 | | | 1,882 | |
| | | | | | |
| EARNINGS APPLICABLE TO COMMON STOCK | | $301,255 | | | $226,915 | | | $213,191 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
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| | | | | | | | | | | | | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | |
| | | For the Years Ended December 31, |
| | | 2022 | | 2021 | | 2020 |
| | | (In Thousands) |
| | | | | | |
| OPERATING ACTIVITIES | | | | | | |
| Net income | | $303,327 | | | $228,824 | | | $215,073 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation and amortization | | 230,692 | | | 214,838 | | | 177,738 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 41,648 | | | 48,813 | | | 36,033 | |
| Changes in assets and liabilities: | | | | | | |
| Receivables | | (35,131) | | | (16,455) | | | (30,082) | |
| Fuel inventory | | 15,962 | | | 10,819 | | | (5,938) | |
| Accounts payable | | 48,199 | | | (5,718) | | | (23,692) | |
| Taxes accrued | | 44,015 | | | (3,420) | | | 2,730 | |
| Interest accrued | | 4,926 | | | (1,854) | | | 1,864 | |
| Deferred fuel costs | | (209,835) | | | (133,636) | | | 72,355 | |
| Other working capital accounts | | (19,574) | | | (12,105) | | | (11,837) | |
| Provisions for estimated losses | | (649) | | | (140) | | | 274 | |
| Other regulatory assets | | (157,349) | | | 103,380 | | | (12,065) | |
| Other regulatory liabilities | | (30,499) | | | (28,747) | | | (57,477) | |
| Effect of securitization on regulatory asset | | 153,383 | | | — | | | — | |
| Pension and other postretirement liabilities | | 20,656 | | | (42,502) | | | (28,825) | |
| Other assets and liabilities | | (344) | | | (5,164) | | | 39,174 | |
| Net cash flow provided by operating activities | | 409,427 | | | 356,933 | | | 375,325 | |
| INVESTING ACTIVITIES | | | | | | |
| Construction expenditures | | (696,879) | | | (702,754) | | | (895,857) | |
| Allowance for equity funds used during construction | | 13,527 | | | 9,892 | | | 44,073 | |
| Proceeds from sale of assets | | — | | | 67,920 | | | — | |
| Payment for purchase of assets | | — | | | (36,534) | | | (4,931) | |
| Litigation proceeds from settlement agreement | | 4,134 | | | — | | | — | |
| Changes in money pool receivable - net | | (99,468) | | | 4,601 | | | 6,580 | |
| Changes in securitization account | | 15,750 | | | 9,604 | | | 1,487 | |
| Increase in other investments | | (1,133) | | | — | | | — | |
| Net cash flow used in investing activities | | (764,069) | | | (647,271) | | | (848,648) | |
| FINANCING ACTIVITIES | | | | | | |
| Proceeds from the issuance of long-term debt | | 606,168 | | | 127,931 | | | 937,725 | |
| Retirement of long-term debt | | (66,514) | | | (269,435) | | | (367,565) | |
| Capital contributions from parent | | — | | | 95,000 | | | 175,000 | |
| Proceeds from the issuance of preferred stock | | — | | | 3,713 | | | — | |
| Changes in money pool payable - net | | (79,594) | | | 79,594 | | | — | |
| Dividends paid: | | | | | | |
| Common stock | | (105,000) | | | — | | | (30,000) | |
| Preferred stock | | (2,060) | | | (1,881) | | | (2,064) | |
| Other | | 5,111 | | | 6,848 | | | (4,106) | |
| Net cash flow provided by financing activities | | 358,111 | | | 41,770 | | | 708,990 | |
| Net increase (decrease) in cash and cash equivalents | | 3,469 | | | (248,568) | | | 235,667 | |
| Cash and cash equivalents at beginning of period | | 28 | | | 248,596 | | | 12,929 | |
| Cash and cash equivalents at end of period | | $3,497 | | | $28 | | | $248,596 | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | |
| Cash paid during the period for: | | | | | | |
| Interest - net of amount capitalized | | $87,682 | | | $87,094 | | | $89,077 | |
| Income taxes | | $1,864 | | | $17,594 | | | $2,792 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | | |
| | | For the Years Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | |
| Net income | |
| $159,397 |
| |
| $162,235 |
| |
| $76,173 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation and amortization | | 153,286 |
| | 128,534 |
| | 117,520 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 20,143 |
| | (39,545 | ) | | 42,119 |
|
| Changes in assets and liabilities: | | |
| | |
| | |
|
| Receivables | | 58,445 |
| | (17,099 | ) | | (15,934 | ) |
| Fuel inventory | | (4,926 | ) | | 64 |
| | (25,054 | ) |
| Accounts payable | | (33,646 | ) | | 43,319 |
| | 32,842 |
|
| Prepaid taxes and taxes accrued | | (3,805 | ) | | 7,854 |
| | 30,308 |
|
| Interest accrued | | (5,363 | ) | | (1,201 | ) | | (421 | ) |
| Deferred fuel costs | | (6,696 | ) | | (47,604 | ) | | 12,758 |
|
| Other working capital accounts | | (13,822 | ) | | 1,328 |
| | (7,852 | ) |
| Provisions for estimated losses | | (5,748 | ) | | 3,741 |
| | 2,531 |
|
| Other regulatory assets | | 85,400 |
| | 63,350 |
| | 184,574 |
|
| Other regulatory liabilities | | (105,517 | ) | | (19,336 | ) | | 410,968 |
|
| Deferred tax rate change recognized as regulatory liability/asset | | — |
| | — |
| | (520,547 | ) |
| Pension and other postretirement liabilities | | (7,152 | ) | | (13,135 | ) | | (49,445 | ) |
| Other assets and liabilities | | (3,257 | ) | | 59,248 |
| | 10,856 |
|
| Net cash flow provided by operating activities | | 286,739 |
| | 331,753 |
| | 301,396 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
|
| Construction expenditures | | (898,090 | ) | | (451,988 | ) | | (348,027 | ) |
| Allowance for equity funds used during construction | | 28,526 |
| | 9,861 |
| | 6,874 |
|
| Proceeds from sale of assets | | — |
| | 3,753 |
| | — |
|
| Insurance proceeds | | — |
| | — |
| | 2,431 |
|
| Changes in money pool receivable - net | | (11,181 | ) | | 44,903 |
| | (44,222 | ) |
| Changes in securitization account | | 2,465 |
| | (2,502 | ) | | (232 | ) |
| Net cash flow used in investing activities | | (878,280 | ) | | (395,973 | ) | | (383,176 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | 986,019 |
| | — |
| | 148,277 |
|
| Retirement of long-term debt | | (578,593 | ) |
| (74,950 | ) |
| (71,683 | ) |
| Capital contributions from parent | | 185,000 |
| | — |
| | 115,000 |
|
| Proceeds from the issuance of preferred stock | | 33,188 |
| | — |
| | — |
|
| Change in money pool payable - net | | (22,389 | ) | | 22,389 |
| | — |
|
| Other | | 1,189 |
| | 1,324 |
| | (482 | ) |
| Net cash flow provided by (used in) financing activities | | 604,414 |
| | (51,237 | ) | | 191,112 |
|
| Net increase (decrease) in cash and cash equivalents | | 12,873 |
| | (115,457 | ) | | 109,332 |
|
| Cash and cash equivalents at beginning of period | | 56 |
| | 115,513 |
| | 6,181 |
|
| Cash and cash equivalents at end of period | |
| $12,929 |
| |
| $56 |
| |
| $115,513 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | |
| | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $89,402 |
| |
| $85,719 |
| |
| $84,556 |
|
| Income taxes | |
| $17,010 |
| |
| $20,787 |
| |
| ($21,107 | ) |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | |
| | | December 31, |
| | | 2022 | | 2021 |
| | | (In Thousands) |
| | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | | $500 | | | $28 | |
| Temporary cash investments | | 2,997 | | | — | |
| Total cash and cash equivalents | | 3,497 | | | 28 | |
| Securitization recovery trust account | | 10,879 | | | 26,629 | |
| Accounts receivable: | | | | |
| Customer | | 115,955 | | | 83,797 | |
| Allowance for doubtful accounts | | (2,352) | | | (5,814) | |
| Associated companies | | 115,549 | | | 31,720 | |
| Other | | 21,587 | | | 13,404 | |
| Accrued unbilled revenues | | 69,208 | | | 62,241 | |
| Total accounts receivable | | 319,947 | | | 185,348 | |
| Deferred fuel costs | | 258,115 | | | 48,280 | |
| | | | |
| Fuel inventory - at average cost | | 26,750 | | | 42,712 | |
| Materials and supplies - at average cost | | 93,031 | | | 72,884 | |
| | | | |
| Prepayments and other | | 20,568 | | | 17,515 | |
| TOTAL | | 732,787 | | | 393,396 | |
| | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | |
| Investments in affiliates - at equity | | 250 | | | 300 | |
| Non-utility property - at cost (less accumulated depreciation) | | 376 | | | 376 | |
| Other | | 18,975 | | | 18,128 | |
| TOTAL | | 19,601 | | | 18,804 | |
| | | | |
| UTILITY PLANT | | | | |
| Electric | | 7,409,461 | | | 7,181,567 | |
| Construction work in progress | | 339,139 | | | 183,965 | |
| TOTAL UTILITY PLANT | | 7,748,600 | | | 7,365,532 | |
| Less - accumulated depreciation and amortization | | 2,135,400 | | | 2,049,750 | |
| UTILITY PLANT - NET | | 5,613,200 | | | 5,315,782 | |
| | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | |
| Regulatory assets: | | | | |
| | | | |
| Other regulatory assets (includes securitization property of $269,523 as of December 31, 2022 and $23,818 as of December 31, 2021) | | 578,682 | | | 421,333 | |
| | | | |
| Other | | 99,694 | | | 112,096 | |
| TOTAL | | 678,376 | | | 533,429 | |
| | | | |
| TOTAL ASSETS | | $7,043,964 | | | $6,261,411 | |
| | | | |
| See Notes to Financial Statements. | | | | |
|
| | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | | |
| | | December 31, |
| | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | |
| $25 |
| |
| $26 |
|
| Temporary cash investments | | 12,904 |
| | 30 |
|
| Total cash and cash equivalents | | 12,929 |
| | 56 |
|
| Securitization recovery trust account | | 37,720 |
| | 40,185 |
|
| Accounts receivable: | | |
| | |
|
| Customer | | 59,365 |
| | 69,714 |
|
| Allowance for doubtful accounts | | (471 | ) | | (461 | ) |
| Associated companies | | 24,001 |
| | 64,441 |
|
| Other | | 17,050 |
| | 12,275 |
|
| Accrued unbilled revenues | | 50,048 |
| | 51,288 |
|
| Total accounts receivable | | 149,993 |
| | 197,257 |
|
| Fuel inventory - at average cost | | 47,593 |
| | 42,667 |
|
| Materials and supplies - at average cost | | 46,056 |
| | 41,883 |
|
| Prepayments and other | | 21,012 |
| | 15,903 |
|
| TOTAL | | 315,303 |
| | 337,951 |
|
| | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
|
| Investments in affiliates - at equity | | 396 |
| | 448 |
|
| Non-utility property - at cost (less accumulated depreciation) | | 376 |
| | 376 |
|
| Other | | 20,077 |
| | 19,218 |
|
| TOTAL | | 20,849 |
| | 20,042 |
|
| | | | | |
| UTILITY PLANT | | |
| | |
|
| Electric | | 5,199,027 |
| | 4,773,984 |
|
| Construction work in progress | | 760,354 |
| | 325,193 |
|
| TOTAL UTILITY PLANT | | 5,959,381 |
| | 5,099,177 |
|
| Less - accumulated depreciation and amortization | | 1,770,852 |
| | 1,684,569 |
|
| UTILITY PLANT - NET | | 4,188,529 |
| | 3,414,608 |
|
| | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
|
| Regulatory assets: | | |
| | |
|
| Other regulatory assets (includes securitization property of $160,375 as of December 31, 2019 and $236,336 as of December 31, 2018) | | 512,648 |
| | 598,048 |
|
| Other | | 33,393 |
| | 29,371 |
|
| TOTAL | | 546,041 |
| | 627,419 |
|
| | | | | |
| TOTAL ASSETS | |
| $5,070,722 |
| |
| $4,400,020 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
| | | | | | | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | |
| | | December 31, |
| | | 2022 | | 2021 |
| | | (In Thousands) |
| | | | |
| CURRENT LIABILITIES | | | | |
| | | | |
| Accounts payable: | | | | |
| Associated companies | | $70,321 | | | $142,929 | |
| Other | | 201,982 | | | 164,981 | |
| Customer deposits | | 38,764 | | | 37,271 | |
| Taxes accrued | | 93,033 | | | 49,018 | |
| Interest accrued | | 23,928 | | | 19,002 | |
| Current portion of unprotected excess accumulated deferred income taxes | | — | | | 27,188 | |
| | | | |
| | | | |
| | | | |
| Other | | 16,963 | | | 16,120 | |
| TOTAL | | 444,991 | | | 456,509 | |
| | | | |
| NON-CURRENT LIABILITIES | | | | |
| Accumulated deferred income taxes and taxes accrued | | 744,227 | | | 692,496 | |
| Accumulated deferred investment tax credits | | 8,711 | | | 9,325 | |
| Regulatory liability for income taxes - net | | 132,647 | | | 144,145 | |
| Other regulatory liabilities | | 45,247 | | | 37,060 | |
| Asset retirement cost liabilities | | 11,121 | | | 8,520 | |
| Accumulated provisions | | 7,593 | | | 8,242 | |
| | | | |
| Long-term debt (includes securitization bonds of $275,064 as of December 31, 2022 and $53,979 as of December 31, 2021) | | 2,895,913 | | | 2,354,148 | |
| Other | | 74,053 | | | 67,760 | |
| TOTAL | | 3,919,512 | | | 3,321,696 | |
| | | | |
| Commitments and Contingencies | | | | |
| | | | |
| EQUITY | | | | |
| Common stock, no par value, authorized 200,000,000 shares; issued and outstanding 46,525,000 shares in 2022 and 2021 | | 49,452 | | | 49,452 | |
| Paid-in capital | | 1,050,125 | | | 1,050,125 | |
| Retained earnings | | 1,541,134 | | | 1,344,879 | |
| Total common shareholder's equity | | 2,640,711 | | | 2,444,456 | |
| Preferred stock without sinking fund | | 38,750 | | | 38,750 | |
| TOTAL | | 2,679,461 | | | 2,483,206 | |
| | | | |
| TOTAL LIABILITIES AND EQUITY | | $7,043,964 | | | $6,261,411 | |
| | | | |
| See Notes to Financial Statements. | | | | |
|
| | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | | |
| | | December 31, |
| | | 2019 | | 2018 |
| | | (In Thousands) |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | |
| $— |
| |
| $500,000 |
|
| Accounts payable: | | | | |
| Associated companies | | 58,055 |
| | 119,371 |
|
| Other | | 188,460 |
| | 150,679 |
|
| Customer deposits | | 40,232 |
| | 43,387 |
|
| Taxes accrued | | 49,708 |
| | 53,513 |
|
| Interest accrued | | 18,992 |
| | 24,355 |
|
| Current portion of unprotected excess accumulated deferred income taxes | | 26,552 |
| | 87,627 |
|
| Deferred fuel costs | | 13,001 |
| | 19,697 |
|
| Other | | 10,521 |
| | 6,353 |
|
| TOTAL | | 405,521 |
| | 1,004,982 |
|
| | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 585,413 |
| | 552,535 |
|
| Accumulated deferred investment tax credits | | 10,559 |
| | 11,176 |
|
| Regulatory liability for income taxes - net | | 225,980 |
| | 264,623 |
|
| Other regulatory liabilities | | 42,085 |
| | 47,884 |
|
| Asset retirement cost liabilities | | 7,631 |
| | 7,222 |
|
| Accumulated provisions | | 8,108 |
| | 13,856 |
|
| Long-term debt (includes securitization bonds of $205,349 as of December 31, 2019 and $283,659 as of December 31, 2018) | | 1,922,956 |
| | 1,013,735 |
|
| Other | | 63,062 |
| | 61,605 |
|
| TOTAL | | 2,865,794 |
| | 1,972,636 |
|
| | | | | |
| Commitments and Contingencies | |
|
| |
|
|
| | | | | |
| EQUITY | | |
| | |
|
| Common stock, no par value, authorized 200,000,000 shares; issued and outstanding 46,525,000 shares in 2019 and 2018 | | 49,452 |
| | 49,452 |
|
| Paid-in capital | | 780,182 |
| | 596,994 |
|
| Retained earnings | | 934,773 |
| | 775,956 |
|
| Total common shareholder's equity | | 1,764,407 |
| | 1,422,402 |
|
| Preferred stock without sinking fund | | 35,000 |
| | — |
|
| TOTAL | | 1,799,407 |
| | 1,422,402 |
|
| | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $5,070,722 |
| |
| $4,400,020 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| For the Years Ended December 31, 2022, 2021, and 2020 |
| | | | | |
| | | | Common Equity | | |
| | Preferred Stock | | Common Stock | | Paid-in Capital | | Retained Earnings | | Total |
| | | | (In Thousands) |
| | | | | | | | | |
| Balance at December 31, 2019 | $35,000 | | | $49,452 | | | $780,182 | | | $934,773 | | | $1,799,407 | |
| Net income | — | | | — | | | — | | | 215,073 | | | 215,073 | |
| Capital contributions from parent | — | | | — | | | 175,000 | | | — | | | 175,000 | |
| Common stock dividends | — | | | — | | | — | | | (30,000) | | | (30,000) | |
| | | | | | | | | |
| Preferred stock dividends | — | | | — | | | — | | | (1,882) | | | (1,882) | |
| Other | — | | | — | | | (20) | | | — | | | (20) | |
| Balance at December 31, 2020 | $35,000 | | | $49,452 | | | $955,162 | | | $1,117,964 | | | $2,157,578 | |
| Net income | — | | | — | | | — | | | 228,824 | | | 228,824 | |
| Capital contributions from parent | — | | | — | | | 95,000 | | | — | | | 95,000 | |
| | | | | | | | | |
| Preferred stock issuance | 3,750 | | | — | | | (37) | | | — | | | 3,713 | |
| Preferred stock dividends | — | | | — | | | — | | | (1,909) | | | (1,909) | |
| | | | | | | | | |
| Balance at December 31, 2021 | $38,750 | | | $49,452 | | | $1,050,125 | | | $1,344,879 | | | $2,483,206 | |
| Net income | — | | | — | | | — | | | 303,327 | | | 303,327 | |
| | | | | | | | | |
| Common stock dividends | — | | | — | | | — | | | (105,000) | | | (105,000) | |
| | | | | | | | | |
| Preferred stock dividends | — | | | — | | | — | | | (2,072) | | | (2,072) | |
| | | | | | | | | |
| Balance at December 31, 2022 | $38,750 | | | $49,452 | | | $1,050,125 | | | $1,541,134 | | | $2,679,461 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| For the Years Ended December 31, 2019, 2018, and 2017 |
| | | | | | |
| | | | Common Equity | | |
| | Preferred Stock | | Common Stock | | Paid-in Capital | | Retained Earnings | | Total |
| | | | (In Thousands) |
| | | | | | | | | | |
| Balance at December 31, 2016 |
| $— |
| |
| $49,452 |
| |
| $481,994 |
| |
| $537,548 |
| |
| $1,068,994 |
|
| Net income | — |
| | — |
| | — |
| | 76,173 |
| | 76,173 |
|
| Capital contributions from parent | — |
| | — |
| | 115,000 |
| | — |
| | 115,000 |
|
| Balance at December 31, 2017 |
| $— |
| |
| $49,452 |
| |
| $596,994 |
| |
| $613,721 |
| |
| $1,260,167 |
|
| Net income | — |
| | — |
| | — |
| | 162,235 |
| | 162,235 |
|
| Balance at December 31, 2018 |
| $— |
| |
| $49,452 |
| |
| $596,994 |
| |
| $775,956 |
| |
| $1,422,402 |
|
| Net income | — |
| | — |
| | — |
| | 159,397 |
| | 159,397 |
|
| Capital contributions from parent | — |
| | — |
| | 185,000 |
| | — |
| | 185,000 |
|
| Preferred stock issuance | 35,000 |
| | — |
| | (1,812 | ) | | — |
| | 33,188 |
|
| Preferred stock dividends | — |
| | — |
| | — |
| | (580 | ) | | (580 | ) |
| Balance at December 31, 2019 |
| $35,000 |
| |
| $49,452 |
| |
| $780,182 |
| |
| $934,773 |
| |
| $1,799,407 |
|
| | | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
|
| | | | | | | | | | | | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | |
| | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| | (In Thousands) |
| | | | | | | | | | |
| Operating revenues |
| $1,488,955 |
| |
| $1,605,902 |
| |
| $1,544,893 |
| |
| $1,615,619 |
| |
| $1,707,203 |
|
| Net income |
| $159,397 |
| |
| $162,235 |
| |
| $76,173 |
| |
| $107,538 |
| |
| $69,625 |
|
| Total assets |
| $5,070,722 |
| |
| $4,400,020 |
| |
| $4,279,738 |
| |
| $4,033,081 |
| |
| $3,898,582 |
|
| Long-term obligations (a) |
| $1,922,956 |
| |
| $1,013,735 |
| |
| $1,587,150 |
| |
| $1,508,407 |
| |
| $1,451,967 |
|
| | | | | | | | | | |
| (a) Includes long-term debt (excluding currently maturing debt). |
| | | | | | | | | | |
| | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| | (Dollars In Millions) |
| | | | | | | | | | |
| Electric Operating Revenues: | |
| | |
| | |
| | |
| | |
|
| Residential |
| $658 |
| |
| $674 |
| |
| $636 |
| |
| $613 |
| |
| $633 |
|
| Commercial | 343 |
| | 381 |
| | 378 |
| | 356 |
| | 369 |
|
| Industrial | 373 |
| | 394 |
| | 384 |
| | 365 |
| | 372 |
|
| Governmental | 22 |
| | 25 |
| | 25 |
| | 24 |
| | 25 |
|
| Total billed retail | 1,396 |
| | 1,474 |
| | 1,423 |
| | 1,358 |
| | 1,399 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | 52 |
| | 59 |
| | 58 |
| | 178 |
| | 259 |
|
| Non-associated companies | 7 |
| | 39 |
| | 22 |
| | 40 |
| | 14 |
|
| Other | 34 |
| | 34 |
| | 42 |
| | 40 |
| | 35 |
|
| Total |
| $1,489 |
| |
| $1,606 |
| |
| $1,545 |
| |
| $1,616 |
| |
| $1,707 |
|
| | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | |
| | |
| | |
| | |
|
| Residential | 6,039 |
| | 6,135 |
| | 5,716 |
| | 5,836 |
| | 5,889 |
|
| Commercial | 4,667 |
| | 4,747 |
| | 4,548 |
| | 4,570 |
| | 4,548 |
|
| Industrial | 8,043 |
| | 8,052 |
| | 7,521 |
| | 7,493 |
| | 7,036 |
|
| Governmental | 259 |
| | 286 |
| | 273 |
| | 283 |
| | 276 |
|
| Total retail | 19,008 |
| | 19,220 |
| | 18,058 |
| | 18,182 |
| | 17,749 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | 1,472 |
| | 1,516 |
| | 1,534 |
| | 4,625 |
| | 5,853 |
|
| Non-associated companies | 343 |
| | 962 |
| | 729 |
| | 1,086 |
| | 254 |
|
| Total | 20,823 |
| | 21,698 |
| | 20,321 |
| | 23,893 |
| | 23,856 |
|
SYSTEM ENERGY RESOURCES, INC.
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
System Energy’s principal asset currently consists of an ownership interest and a leasehold interest in Grand Gulf. The capacity and energy from its 90% interest is sold under the Unit Power Sales Agreement to its only four customers, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% interest in Grand Gulf pursuant to the Unit Power Sales Agreement. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenues. As discussed in “Complaints Against System Energy” below, System Energy is currently involved in proceedings at the FERC commenced by the retail regulators of its customers regarding its return on equity, its capital structure, its renewal of the sale-leaseback of 11.5% of Grand Gulf, the treatment of uncertain tax positions in rate base, the prudence of its operations on Grand Gulf, and the rates it charges under the Unit Power Sales Agreement. The claims in these proceedings include claims for refunds and claims for rate adjustments; the aggregate amount of refunds claimed in these proceedings substantially exceeds the net book value of System Energy. In the event of an adverse decision in one or more of these proceedings requiring the payment of substantial additional refunds, System Energy would be required to seek financing to pay such refunds which may not be available on terms acceptable to System Energy, or may not be available at all, when required. See Note 2 to the financial statements for a discussion of these proceedings.
Results of Operations
20192022 Compared to 20182021
Net Income
NetSystem Energy experienced a net loss of $276.6 million in 2022 compared to net income increased $5of $106.8 million in 2021 primarily due to a regulatory charge of $551 million ($413 million net-of-tax) recorded in the second quarter 2022 to reflect the effects of the settlement agreement with the MPSC and offer of settlement to the LPSC, the APSC, and the City Council related to pending proceedings before the FERC. Partially offsetting the charge against System Energy’s earnings was an increase in operating revenues resulting from changesincreases in rate base as comparedrates. See Note 2 to prior year, and a lower effective income tax rate, after excluding the effectfinancial statements for discussion of the returnpartial settlement agreement. See “Complaints Against System Energy” below for further discussion of unprotected excess accumulated deferred income taxes to customers which is offset in income taxes.these items, the effects of the December 2022 FERC orders, and other proceedings involving System Energy at the FERC.
Income Taxes
The effective income tax rates were 13.4% for 2019were 25.1% for 2022 and (102.7%(1.9%) for 2018. The difference in the effective income tax rate of 13.4% versus the federal statutory rate of 21% for 2019 was primarily due to the amortization of excess accumulated deferred income taxes and certain book and tax differences related to utility plant items, partially offset by state income taxes. The difference in the effective income tax rate of (102.7%) versus the federal statutory rate of 21% for 2018 was primarily due to the amortization of excess accumulated deferred income taxes.2021. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates.rates, and for additional discussion regarding income taxes.
20182021 Compared to 2017
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of System Energy’s Annual Report on Form 10-K for the year ended December 31, 20182021, filed with the SEC on February 25, 2022, for discussion of results of operations for 20182021 compared to 2017.2020.
Income Tax Legislation
See the “Income Tax Legislation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the Tax Cuts and JobsInflation Reduction Act the federal income tax legislation enacted in December 2017. Note 3 to the financial statements contains additional discussion of the effect of the Tax Act on 2017, 2018, and 2019 results of operations and financial position, the provisions of the Tax Act, and the uncertainties associated with accounting for the Tax Act, and Note 2 to the financial statements discusses the regulatory proceedings that have considered the effects of the Tax Act.2022.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2019, 2018,2022, 2021, and 20172020 were as follows:
| | | | | | | | | | | | | | | | | |
| | 2022 | | 2021 | | 2020 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period | $89,201 | | | $242,469 | | | $68,534 | |
| | | | | |
| Net cash provided by (used in): | | | | | |
| Operating activities | 7,280 | | | 201,211 | | | (145,462) | |
| Investing activities | (264,184) | | | (193,392) | | | (206,443) | |
| Financing activities | 170,643 | | | (161,087) | | | 525,840 | |
| Net increase (decrease) in cash and cash equivalents | (86,261) | | | (153,268) | | | 173,935 | |
| | | | | |
| Cash and cash equivalents at end of period | $2,940 | | | $89,201 | | | $242,469 | |
|
| | | | | | | | | | | |
| | 2019 | | 2018 | | 2017 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $95,685 |
| |
| $287,187 |
| |
| $245,863 |
|
| | | | | | |
| Net cash provided by (used in): | | | | | |
| Operating activities | 300,141 |
| | 101,328 |
| | 371,278 |
|
| Investing activities | (119,553 | ) | | (286,161 | ) | | (174,250 | ) |
| Financing activities | (207,739 | ) | | (6,669 | ) | | (155,704 | ) |
| Net increase (decrease) in cash and cash equivalents | (27,151 | ) | | (191,502 | ) | | 41,324 |
|
| | | | | | |
| Cash and cash equivalents at end of period |
| $68,534 |
| |
| $95,685 |
| |
| $287,187 |
|
20192022 Compared to 20182021
Operating Activities
Net cash flow provided by operating activities increased $198.8decreased $193.9 million in 20192022 primarily due to:
to the decrease in the returnrefund of $235 million to Entergy Mississippi as a result of the unprotected excess accumulated deferred income taxes in 2018;
a decreasesettlement with the MPSC and an increase in spending of $48.5$34.8 million on nuclear refueling outagesoutage costs in 20192022 as compared to prior year; and
year, partially offset by a decrease of $51.7$36.5 million in income taxes paid in 2019.2022 and timing of collections of receivables. System Energy made income tax payments of $54$18.4 million in 20182022 in accordance with an intercompany income tax allocation agreement.System Energy made income tax payments of $55 million in 2021, which included payments made as a result of the amended Mississippi tax returns filed based on federal adjustments related to the resolution of the 2014-2015 IRS audit and additional payments made in accordance with an intercompany income tax allocation agreement. See Note 2 to the financial statements for discussion of the settlement with the MPSC. See Note 3 to the financial statements for discussion of the 2014-2015 IRS audit.
Investing Activities
Net cash flow used in investing activities decreasedincreased by $166.6$70.8 million in 20192022 primarily due to:
•an increase of $65.8 million in nuclear construction expenditures as a decreaseresult of $102.7spending in 2022 on Grand Gulf outage projects and upgrades; and
•an increase of $54.3 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;cycle.
The increase was partially offset by money pool activity; andactivity.
a decrease of $28.4 million in nuclear construction expenditures as a result of spending in 2018 on Grand Gulf outage projects.
DecreasesIncreases in System Energy’s receivable from the money pool are a sourceuse of cash flow and System Energy’s receivable from the money pool decreased by $47.8increased $19.2 million in 20192022 compared to decreasingincreasing by $4.5$71.7 million in 2018.2021. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
Financing Activities
Net cash flow used inSystem Energy’s financing activities increased $201.1provided $170.6 million of cash in 20192022 compared to using $161.1 million of cash in 2021 primarily due to:to the following activity:
•a $135 million capital contribution from Entergy Corporation in 2022 primarily to fund the issuancesettlement payment to Entergy Mississippi;
•the repayment in March 2018February 2021 of $100 million of 3.42% Series J notes by the System Energy nuclear fuel company variable interest entity; and
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
an increase of $56.5$96 million in common stock dividends and distributions in 2019. Commondistributions. No common stock dividends andor distributions were lowermade in 20182022 in order to maintain System Energy’s capital structure and in anticipation of the excess accumulated deferred income taxes being returned to customers as a result ofsettlement with the Tax Cuts and Jobs Act; andMPSC.
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 increase was partially offset by:
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.
In March 2019, System Energy issued $134 million of 2.50% Series 2019 revenue refunding bonds due April 2022. The proceeds were used to redeem, prior to maturity, $134 million of 5.875% Series 1998 pollution control revenue refunding bonds due April 2022.
See Note 5 to the financial statements for additional details of long-term debt.
20182021 Compared to 2017
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of System Energy’s Annual Report on Form 10-K for the year ended December 31, 20182021, filed with the SEC on February 25, 2022, for discussion of operating, investing, and financing cash flow activities for 20182021 compared to 2017.2020.
Capital Structure
System Energy’s debt to capital ratio is shown in the following table. The decreaseincrease in the debt to capital ratio is primarily due to a decreasethe net loss in long-term debt outstanding, partially offset by a decrease in retained earnings.2022.
| | | | | | | | | | | |
| | December 31,
2022 | | December 31,
2021 |
| Debt to capital | 45.0 | % | | 40.4 | % |
| Effect of subtracting cash | (0.1 | %) | | (3.0 | %) |
| Net debt to net capital (non-GAAP) | 44.9 | % | | 37.4 | % |
|
| | | | | |
| | December 31,
2019 | | December 31,
2018 |
| Debt to capital | 43.5 | % | | 46.1 | % |
| Effect of subtracting cash | (3.3 | %) | | (4.0 | %) |
| Net debt to net capital | 40.2 | % | | 42.1 | % |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings and long-term debt, including the currently maturing portion. Capital consists of debt and common equity. Net capital consists of capital less cash and cash equivalents. System Energy uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating System Energy’s financial condition. The net debt to net capital ratio is a non-GAAP measure. System Energy uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating System Energy’s financial condition because net debt indicates System Energy’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
System Energy seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend or both,a capital distribution, to the extent funds are legally available to do so, or a combination of the three, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments and other uses of cash such as the payment of expenses in the ordinary course, System Energy may issue incremental debt or reduce dividends, or both, to maintain its capital structure.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
Uses of Capital
System Energy requires capital resources for:
•construction and other capital investments;
•debt maturities or retirements;
•working capital purposes, including the financing of fuel costs;costs and tax payments; and
•dividend, distribution, and interest payments.
Following are the amounts of System Energy’s planned construction and other capital investments.
| | | | | | | | | | | | | | | | | |
| | 2023 | | 2024 | | 2025 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation | $135 | | | $190 | | | $135 | |
| Utility Support | 20 | | | 15 | | | 15 | |
| Total | $155 | | | $205 | | | $150 | |
|
| | | | | | | | | | | |
| | 2020 | | 2021 | | 2022 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation |
| $165 |
| |
| $80 |
| |
| $145 |
|
| Utility Support | 5 |
| | 15 |
| | 15 |
|
| Total |
| $170 |
| |
| $95 |
| |
| $160 |
|
In addition to routine spending to maintain operations, the planned capital investment estimate includes amounts associated with Grand Gulf investments and initiatives.
Following are the amounts of System Energy’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations..
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2023 | | 2024 | | 2025 | | 2026-2027 | | After 2027 |
| | (In Millions) |
| Long-term debt (a) | $332 | | | $27 | | | $298 | | | $131 | | | $271 | |
|
| | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2021-2022 | | 2023-2024 | | After 2024 | | Total |
| | (In Millions) |
| Long-term debt (a) |
| $35 |
| |
| $326 |
| |
| $287 |
| |
| $206 |
| |
| $854 |
|
| Purchase obligations (b) |
| $32 |
| |
| $54 |
| |
| $47 |
| |
| $— |
| |
| $133 |
|
| |
(a) | Includes estimated interest payments. (a)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. |
In addition to the contractual obligations given above, financial statements.
Other Obligations
System Energy expects to contribute approximately $10.5$15.5 million to its qualified pension plans and approximately $21$26 thousand to other postretirement health care and life insurance plans in 2020,2023, although the 20202023 required pension contributions will be known with more certainty when the January 1, 20202023 valuations are completed, which is expected by April 1, 2020.2023. See “Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Also in addition to the contractual obligations, System Energy has $464.9 million ofno unrecognized tax benefits and interest net of unused tax attributes and payments for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition, System Energy enters into nuclear fuel purchase agreements that contain minimum purchase obligations. As discussed in Note 8 to routine spending to maintain operations, the planned capital investment estimate includes specific Grand Gulf investments and initiatives.financial statements, System Energy recovers these costs through charges under the Unit Power Sales Agreement.
As a wholly-owned subsidiary, System Energy dividends its earnings to Entergy Corporation at a percentage determined monthly.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
Sources of Capital
System Energy’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•the Entergy System money pool;
•debt issuances;issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•equity contributions; and
•bank financing under new or existing facilities.
Circumstances such fuel and purchased power price fluctuations and unanticipated expenses, including unscheduled plant outages, could affect the timing and level of internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations, System Energy may refinance, redeem, or otherwiseexpects to continue, when economically feasible, to retire higher-cost debt prior to maturity, to the extentand replace it with lower-cost debt if market conditions and interest rates are favorable.permit.
All debt issuances by System Energy require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in its bond indenture and other agreements. System Energy has sufficient capacity under these tests to meet its foreseeable capital needs.needs for the next twelve months and beyond.
System Energy’s receivables from the money pool were as follows as of December 31 for each of the following years.
| | | | | | | | | | | | | | | | | | | | |
| 2022 | | 2021 | | 2020 | | 2019 |
| (In Thousands) |
| $94,981 | | $75,745 | | $4,004 | | $59,298 |
|
| | | | | | |
| 2019 | | 2018 | | 2017 | | 2016 |
| (In Thousands) |
| $59,298 | | $107,122 | | $111,667 | | $33,809 |
See Note 4 to the financial statements for a description of the money pool.
The System Energy nuclear fuel company variable interest entity has a credit facility in the amount of $120 million scheduled to expire in September 2021.June 2025. As of December 31, 2019, $31.62022, $72.6 million in loans were outstanding under the System Energy nuclear fuel company variable interest entity credit facility. See Note 4 to the financial statements for additional discussion of the variable interest entity credit facility.
System Energy obtained authorizations from the FERC through November 2020October 2023 for the following:
•short-term borrowings not to exceed an aggregate amount of $200 million at any time outstanding;
•long-term borrowings and security issuances;issuances not to exceed an aggregate amount of $1,090 million at any time outstanding; and
•borrowings by its nuclear fuel company variable interest entity.
See Note 4 to the financial statements for further discussion of System Energy’s short-term borrowing limits.
Federal Regulation
See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
Complaints Against System Energy
System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf. System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. System Energy and the Unit Power Sales Agreement are currently the subject of several litigation proceedings at the FERC, including challenges with respect to System Energy’s authorized return on equity and capital structure, renewal of its sale-leaseback arrangement, treatment of uncertain tax positions, a broader investigation of rates under the Unit Power Sales Agreement, and a prudence complaint challenging the extended power uprate completed at Grand Gulf in 2012 and the operation and management of Grand Gulf, particularly in the 2016-2020 time period. The claims in these proceedings include claims for refunds and claims for rate adjustments; the aggregate amount of refunds claimed in these proceedings substantially exceeds the net book value of System Energy. Following are discussions of the proceedings.
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,
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
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. As discussed below in “System Energy Settlement with the MPSC,” beginning with the July 2022 service month, bills issued to Entergy Mississippi under the Unit Power Sales Agreement reflect a return on equity of 9.65%.
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 beenwere 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 15-month refund period in connection with the LPSC return on equity complaint expired on July 26, 2019.
The portion of the LPSC’s complaint dealing with return on equity was subsequently consolidated with the APSC and MPSC complaint for hearing. The parties are required to addressaddressed an order (issued in a separate FERC proceeding involving New England transmission owners) that proposed modifying the FERC’s standard methodology for
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
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 iswas 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.testimony. For the first refund period, System Energy’s testimony argues for a return on equity of 10.10% (median) or 10.70% (midpoint). For the second refund period, System Energy’s testimony shows that the calculated returns on equity for the first period fall within the range of presumptively just and reasonable returns on equity, and thus the second complaint should be dismissed (and the first period return on equity used going forward). If the FERC nonetheless were to set a new return on equity for the second period (and going forward), System Energy argues the return on equity should be either 10.32% (median) or 10.69% (midpoint).
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
In May 2019 the FERC trial staff filed its direct and answering testimony in the return on equity proceeding. For the first refund period, the FERC trial staff calculates an authorized return on equity for System Energy of 9.89% based on the application of FERC’s proposed methodology. The FERC trial staff’s direct and answering testimony noted that an authorized return on equity of 9.89% for the first refund period was within the range of presumptively just and reasonable returns on equity for the second refund period, as calculated using a study period ending January 31, 2019 for the second refund period.
In June 2019, System EntergyEnergy 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 rearguesre-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
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
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,System Energy, the FERC issued an order addressing the methodology for determining the return on equity applicable to transmission owners in MISO. Thereafter, the participantsprocedural schedule in the System Energy proceeding agreed to amend the procedural schedulewas amended to allow the participants to file supplemental testimony addressing the order in the MISO transmission owner proceeding.proceeding (Opinion No. 569).
In February 2020 the LPSC, the MPSC and APSC, and the FERC trial staff filed supplemental testimony addressing Opinion No. 569 and how it would affect the return on equity evaluation for the two complaint periods concerning System Energy. For the first refund period, based on their respective interpretations and applications of the Opinion No. 569 methodology, the LPSC argues for an authorized return on equity for System Energy of 8.44%; the MPSC and APSC argue for an authorized return on equity of 8.41%; and the FERC trial staff argues for an authorized return on equity of 9.22%. For the second refund period and on a prospective basis, based on their respective interpretations and applications of the Opinion No. 569 methodology, the LPSC argues for an authorized return on equity for System Energy of 7.89%; the MPSC and APSC argue that an authorized return on equity of 8.01% may be appropriate; and the FERC trial staff argues for an authorized return on equity of 8.66%.
In April 2020, System Energy filed supplemental answering testimony addressing Opinion No. 569. System Energy argues that the Opinion No. 569 methodology is conceptually and analytically defective for purposes of establishing just and reasonable authorized return on equity determinations and proposes an alternative approach. As its primary recommendation, System Energy continues to support the return on equity determinations in its March 2019 testimony for the first refund period and its June 2019 testimony for the second refund period. Under the newOpinion No. 569 methodology, System Energy calculates a “presumptively just and reasonable range” for the authorized return on equity for the first refund period of 8.57% to 9.52%, and for the second refund period of 8.28% to 9.11%. System Energy argues that these ranges are not just and reasonable results. Under its proposed alternative methodology, System Energy calculates an authorized return on equity of 10.26% for the first refund period, which also falls within the presumptively just and reasonable range calculated for the second refund period and prospectively.
In May 2020 the FERC issued an order on rehearing of Opinion No. 569 (Opinion No. 569-A). In June 2020 the procedural schedule the hearing in the System Energy proceeding will commencewas further revised in order to allow parties to address the Opinion No. 569-A methodology. Pursuant to the revised schedule, in June 2020, and the initial decision will be due in October 2020.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
Pursuant to the revised procedural schedule, in July 2020, System Energy filed supplemental testimony addressing Opinion No. 569-A. System Energy argues that strict application of the Opinion No. 569-A methodology produces results inconsistent with investor requirements and does not provide a sound basis on which to evaluate System Energy’s authorized return on equity. As its primary recommendation, System Energy argues for the use of a methodology that incorporates four separate financial models, including the constant growth form of the discounted cash flow model and the empirical capital asset pricing model. Based on application of its recommended methodology, System Energy argues for an authorized return on equity of 10.12% for the first refund period, which also falls within the presumptively just and reasonable range calculated for the second refund period and prospectively. Under the Opinion No. 569-A methodology, System Energy calculates an authorized return on equity of 9.44% for the first refund period, which also falls within the presumptively just and reasonable range calculated for the second refund period and prospectively.
The parties and FERC trial staff filed final rounds of testimony in August 2020. The hearing before a FERC ALJ occurred in late-September through early-October 2020, post-hearing briefing took place in November and December 2020.
In March 2021 the FERC ALJ issued an initial decision. With regard to System Energy’s authorized return on equity, the ALJ determined that the existing return on equity of 10.94% is no longer just and reasonable, and that the replacement authorized return on equity, based on application of the Opinion No. 569-A methodology, should be 9.32%. The ALJ further determined that System Energy should pay refunds for a fifteen-month refund period (January 2017-April 2018) based on the difference between the current return on equity and the replacement authorized return on equity. The ALJ determined that the April 2018 complaint concerning the authorized return on equity should be dismissed, and that no refunds for a second fifteen-month refund period should be due. With regard to System Energy’s capital structure, the ALJ determined that System Energy’s actual equity ratio is excessive and that the just and reasonable equity ratio is 48.15% equity, based on the average equity ratio of the proxy group used to evaluate the return on equity for the second complaint. The ALJ further determined that System Energy should pay refunds for a fifteen-month refund period (September 2018-December 2019) based on the difference between the actual equity ratio and the 48.15% equity ratio. If the ALJ’s initial decision is upheld, the estimated refund for this proceeding is approximately $63 million, which includes interest through December 31, 2022, and the estimated resulting annual rate reduction would be approximately $35 million. The estimated refund will continue to accrue interest until a final FERC decision is issued.
The ALJ initial decision is an interim step in the FERC litigation process, and an ALJ’s determinations made in an initial decision are not controlling on the FERC. In April 2021, System Energy filed its brief on exceptions, in which it challenged the initial decision’s findings on both the return on equity and capital structure issues. Also in April 2021 the LPSC, APSC, MPSC, City Council, and the FERC trial staff filed briefs on exceptions. Reply briefs opposing exceptions were filed in May 2021 by System Energy, the FERC trial staff, the LPSC, APSC, MPSC, and the City Council. Refunds, if any, that might be required will only become due after the FERC issues its order reviewing the initial decision.
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As discussed in “System Energy Settlement with the MPSC” below, beginning with the July 2022 service month, bills issued to Entergy Mississippi under the Unit Power Sales Agreement were adjusted to reflect a capital structure not to exceed 52% equity.
In August 2022 the D.C. Circuit Court of Appeals issued an order addressing appeals of FERC’s Opinion No. 569 and 569-A, which established the methodology applied in the ALJ’s initial decision in the proceeding against System Energy discussed above. The appellate order addressed the methodology for determining the return on equity applicable to transmission owners in MISO. The D.C. Circuit found the FERC’s use of the Risk Premium model as part of the methodology to be arbitrary and capricious, and remanded the case back to the FERC. The remanded case is pending FERC action.
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 seekssought 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
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Agreement formula rate, System Energy was not over or double recovering any costs, and ratepayers will save approximately $850 millioncosts over the initial and renewal terms of the leases. System Energy argued that claims for refunds associated with liabilities arising from uncertain tax positions should be rejected because the liabilities do not provide cost-free capital, the repayment timing of the liabilities is uncertain, and the outcome of the underlying tax positions is uncertain. System Energy’s testimony also challenged the refund calculations supplied by the other parties.
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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).positions. The FERC trial staff also argued that System Energy recovered $32 million more than it should have in depreciation expense for capital additions. In September 2019, System Energy filed cross-answering testimony disputing the FERC trial staff’s arguments for refunds, stating that the FERC trial staff’s position regarding depreciation rates for capital additions is not unreasonable, andbut explaining that any change in depreciation expense is only one element of a Unit Power Sales Agreement rebillingre-billing calculation. Adjustments to depreciation expense in any rebillingre-billing under the Unit Power Sales Agreement formula rate will also involve changes to accumulated depreciation, accumulated deferred income taxes, and other formula elements as needed. In October 2019 the LPSC filed rebuttal testimony increasing the amount of refunds sought for liabilities associated with uncertain tax positions. The LPSC now seeks approximately $512 million plus interest. At the same time, theinterest, which is approximately $248 million through December 31, 2022.The FERC trial staff also filed rebuttal testimony conceding thatin which it was no longer seeking up to $602 million related toseeks refunds of a similar amount as the LPSC for the liabilities associated with uncertain tax positions; instead, it is seeking approximately $511 million plus interest.positions. The LPSC testimony also argued that adjustments to depreciation rates should affect rate base on a prospective basis only.
A hearing was held before a FERC ALJ in November 20192019. In April 2020 the ALJ issued the initial decision. Among other things, the ALJ determined that refunds were due on three main issues. First, with regard to the lease renewal payments, the ALJ determined that System Energy is recovering an unjust acquisition premium through the lease renewal payments, and that System Energy’s recovery from customers through rates should be limited to the cost of service based on the remaining net book value of the leased assets, which is approximately $70 million. The ALJ found that the remedy for this issue should be the refund of lease payments (approximately $17.2 million per year since July 2015) with interest determined at the FERC quarterly interest rate, which would be offset by the addition of the net book value of the leased assets in the cost of service. The ALJ did not calculate a value for the refund expected as a result of this remedy. In addition, System Energy would no longer recover the lease payments in rates prospectively. Second, with regard to the liabilities associated with uncertain tax positions, the ALJ determined that the liabilities are accumulated deferred income taxes and that System Energy’s rate base should have been reduced for those liabilities. The ALJ also found that System Energy should include liabilities associated with uncertain tax positions as a rate base reduction going forward. Third, with regard to the depreciation expense adjustments, the ALJ found that System Energy should correct for the error in re-billings retroactively and prospectively, but that System Energy should not be permitted to recover interest on any retroactive return on enhanced rate base resulting from such corrections.
In June 2020, System Energy, the LPSC, and the FERC trial staff filed briefs on exceptions, challenging several of the initial decision’s findings. System Energy’s brief on exceptions challenged the initial decision’s limitations on recovery of the lease renewal payments, its proposed rate base refund for the liabilities associated with uncertain tax positions, and its proposal to asymmetrically treat interest on bill corrections for depreciation expense adjustments. The LPSC’s and the FERC trial staff’s briefs on exceptions each challenged the initial decision’s allowance for recovery of the cost of service associated with the lease renewal based on the remaining net book value of the leased assets, its calculation of the remaining net book value of the leased assets, and the amount of the initial decision’s proposed rate base refund for the liabilities associated with uncertain tax positions. The LPSC’s brief on exceptions also challenged the initial decision’s proposal that depreciation expense adjustments include retroactive adjustments to rate base and its finding that section 203 of the Federal Power Act did not apply to the lease renewal. The FERC trial staff’s brief on exceptions also challenged the initial decision’s finding that the FERC need not institute a formal investigation into System Energy’s tariff. In October 2020, System Energy, the LPSC, the MPSC, the APSC, and the City Council filed briefs opposing exceptions. System Energy opposed the exceptions filed by the LPSC and the FERC trial staff. The LPSC, MPSC, APSC, City Council, and the FERC trial
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staff opposed the exceptions filed by System Energy. Also in October 2020 the MPSC, APSC, and the City Council filed briefs adopting the exceptions of the LPSC and the FERC trial staff.
In addition, in September 2020, the IRS issued a Notice of Proposed Adjustment (NOPA) and Entergy executed it. The NOPA memorializes the IRS’s decision to adjust the 2015 consolidated federal income tax return of Entergy Corporation and certain of its subsidiaries, including System Energy, with regard to the uncertain decommissioning tax position. Pursuant to the audit resolution documented in the NOPA, the IRS allowed System Energy’s inclusion of $102 million of future nuclear decommissioning costs in System Energy’s cost of goods sold for the 2015 tax year, roughly 10% of the requested deduction, but disallowed the balance of the position. In September 2020, System Energy filed a motion to lodge the NOPA into the record in the FERC proceeding. In October 2020 the LPSC, the APSC, the MPSC, the City Council, and the FERC trial staff filed oppositions to System Energy’s motion. As a result of the NOPA issued by the IRS in September 2020, System Energy filed, in October 2020, a new Federal Power Act section 205 filing at FERC to establish an ongoing rate base credit for the accumulated deferred income taxes resulting from the decommissioning uncertain tax position. On a prospective basis beginning with the October 2020 bill, System Energy proposes to include the accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position as a credit to rate base under the Unit Power Sales Agreement. In November 2020 the LPSC, APSC, MPSC, and City Council filed a protest to the filing, and System Energy responded.
In November 2020 the IRS issued a Revenue Agent’s Report (RAR) for the 2014/2015 tax year and in December 2020 Entergy executed it. The RAR contained the same adjustment to the uncertain nuclear decommissioning tax position as that which the IRS had announced in the NOPA. In December 2020, System Energy filed a motion to lodge the RAR into the record in the FERC proceeding addressing the uncertain tax position rate base issue. In January 2021 the LPSC, APSC, MPSC, and City Council filed a protest to the motion.
As a result of the RAR, in December 2020, System Energy filed amendments to its new Federal Power Act section 205 filings to establish an ongoing rate base credit for the accumulated deferred income taxes resulting from the decommissioning uncertain tax position and to credit excess accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position. The amendments both propose the inclusion of the RAR as support for the filings. In December 2020 the LPSC, APSC, and City Council filed a protest in response to the amendments, reiterating their prior objections to the filings. In February 2021 the FERC issued an order accepting System Energy’s Federal Power Act section 205 filings subject to refund, setting them for hearing, and holding the hearing in abeyance.
In December 2020, System Energy filed a new Federal Power Act section 205 filing to provide a one-time, historical credit of $25.2 million for the accumulated deferred income taxes that would have been created by the decommissioning uncertain tax position if the IRS’s decision had been known in 2016. In January 2021 the LPSC, APSC, MPSC, and City Council filed a protest to the filing. In February 2021 the FERC issued an order accepting System Energy’s Federal Power Act section 205 filing subject to refund, setting it for hearing, and holding the hearing in abeyance. The one-time credit was made during the first quarter 2021.
In December 2022 the FERC issued an order on the ALJ’s initial decision, which affirmed it in part and modified it in part. The FERC’s order directed System Energy to calculate refunds on three issues, and to provide a compliance report detailing the calculations. The FERC’s order also disallows the future recovery of sale-leaseback renewal costs, which is estimated at approximately $11.5 million annually for purchases from Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans through July 2036. The three refund issues are rental expenses related to the renewal of the sale-leaseback arrangements; refunds, if any, for the revenue requirement impact of including accumulated deferred income taxes resulting from the decommissioning uncertain tax positions from 2004 through the present; and refunds for the net effect of correcting the depreciation inputs for capital additions.
In January 2023, System Energy filed its compliance report with the FERC. With respect to the sale-leaseback renewal costs, System Energy calculated a refund of $89.8 million, which represented all of the sale-
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leaseback renewal rental costs that System Energy recovered in rates, with interest. With respect to the decommissioning uncertain tax position issue, System Energy calculated that no additional refunds are owed because it had already provided a one-time historical credit (for the period January 2016 through September 2020) of $25.2 million based on the accumulated deferred income taxes that resulted from the IRS’s partial acceptance of the decommissioning tax position, and because it has been providing an ongoing rate base credit for the accumulated deferred income taxes that resulted from the IRS’s partial acceptance of the decommissioning tax position since October 2020. With respect to the depreciation refund, System Energy calculated a refund of $13.7 million, which is the net total of a refund to customers for excess depreciation expense previously collected, plus interest, offset by the additional return on rate base that System Energy previously did not collect, without interest. See “System Energy Settlement with the MPSC” below for discussion of the regulatory charge and corresponding regulatory liability recorded in June 2022 related to these proceedings. The $103.5 million in total refunds calculated in the compliance filing were reclassified from long-term other regulatory liabilities to a current regulatory liability as of December 31, 2022. In January 2023, System Energy paid the refunds of $103.5 million, which included refunds of $41.7 million to Entergy Arkansas, $27.8 million to Entergy Louisiana, and $34 million to Entergy New Orleans. Based on the December 2022 FERC order and analysis of the remaining litigation, management determined that System Energy’s regulatory liability related to complaints against System Energy as of December 31, 2022 is adequate.
In February 2023 the LPSC, the APSC, and the City Council filed protests to System Energy’s January 2023 compliance report, in which they challenged System Energy’s calculation of the refunds associated with the decommissioning tax position but did not protest the other components of the compliance report. Each of them argued that System Energy should have paid additional refunds for the decommissioning tax position issue, and the City Council estimated the total additional refunds owed to customers of Entergy Louisiana, Entergy New Orleans, and Entergy Arkansas for that issue as $493 million, including interest (and without factoring in the $25.2 million refund that System Energy already paid in 2021). The FERC will review System Energy’s compliance refund report and the retail regulators’ protests and issue a further order; there is no deadline for this order. If the FERC were to order additional refunds at a level consistent with the LPSC, the APSC, and the City Council position on the remedy for the formerly uncertain tax positions, System Energy’s continued financial viability would be jeopardized.
In January 2023, System Energy also filed a request for rehearing of the FERC’s determinations in the December 2022 order on sale-leaseback refund issues and future lease cost disallowances, the FERC’s prospective policy on uncertain tax positions, and the proper accounting of System Energy’s accumulated deferred income taxes adjustment for the Tax Cuts and Jobs Act of 2017; and a motion for confirmation of its interpretation of the December 2022 order’s remedy concerning the decommissioning tax position. In January 2023 the retail regulators filed a motion for confirmation of their interpretation of the refund requirement in the December 2022 FERC order and a provisional request for rehearing. In February 2023 the FERC issued a notice that the rehearing requests have been deemed denied by operation of law. The deemed denial of the rehearing request initiates the sixty-day period in which aggrieved parties may petition for federal appellate court review of the underlying FERC orders; however the FERC may issue a substantive order on rehearing as long as it continues to have jurisdiction over the case.
As a result of the FERC order’s directives regarding the recovery of the sale-leaseback transaction, in December 2022 System Energy reduced the Grand Gulf sale-leaseback regulatory liability by $56 million, reduced the related accumulated deferred income tax asset by $94 million, and reduced the Grand Gulf sale-leaseback accumulated deferred income tax regulatory liability by $25 million, resulting in an increase in income tax expense of $13 million. In addition, the FERC determined that System Energy recognized excess depreciation expense related to property subject to the sale-leaseback property. As a result, in December 2022, System Energy recorded a reduction in depreciation expense and the related accumulated depreciation of $33 million.
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LPSC Additional Complaints
In May 2020 the LPSC authorized its staff to file additional complaints at the FERC related to the rates charged by System Energy for Grand Gulf energy and capacity supplied to Entergy Louisiana under the Unit Power Sales Agreement. The LPSC directive noted that the initial decision issued by the presiding ALJ in the Grand Gulf sale-leaseback complaint proceeding did not address, for procedural reasons, certain rate issues raised by the LPSC and declined to order further investigation of rates charged by System Energy. The LPSC directive authorized its staff to file complaints at the FERC “necessary to address these rate issues, to request a full investigation into the rates charged by System Energy for Grand Gulf power, and to seek rate refund, rate reduction, and such other remedies as may be necessary and appropriate to protect Louisiana ratepayers.” The LPSC directive further stated that the LPSC has seen “information suggesting that the Grand Gulf plant has been significantly underperforming compared to other nuclear plants in the United States, has had several extended and unexplained outages, and has been plagued with serious safety concerns.” The LPSC expressed concern that the costs paid by Entergy Louisiana's retail customers may have been detrimentally impacted, and authorized “the filing of a FERC complaint to address these performance issues and to seek appropriate refund, rate reduction, and other remedies as may be appropriate.”
Unit Power Sales Agreement Complaint
The first of the additional complaints was filed by the LPSC, the APSC, the MPSC, and the City Council in September 2020. The complaint raises two sets of rate allegations: violations of the filed rate and a corresponding request for refunds for prior periods; and elements of the Unit Power Sales Agreement are unjust and unreasonable and a corresponding request for refunds for the 15-month refund period and changes to the Unit Power Sales Agreement prospectively. Several of the filed rate allegations overlap with the previous complaints. The filed rate allegations not previously raised are that System Energy: failed to provide a rate base credit to customers for the “time value” of sale-leaseback lease payments collected from customers in advance of the time those payments were due to the owner-lessors; improperly included certain lease refinancing costs in rate base as prepayments; improperly included nuclear decommissioning outage costs in rate base; failed to include categories of accumulated deferred income taxes as a reduction to rate base; charged customers based on a higher equity ratio than would be appropriate due to excessive retained earnings; and did not correctly reflect money pool investments and imprudently invested cash into the money pool. The elements of the Unit Power Sales Agreement that the complaint alleges are unjust and unreasonable include: incentive and executive compensation, lack of an equity re-opener, lobbying, and private airplane travel. The complaint also requests a rate investigation into the Unit Power Sales Agreement and System Energy’s billing practices pursuant to section 206 of the Federal Power Act, including any issue relevant to the Unit Power Sales Agreement and its inputs. System Energy filed its answer opposing the complaint in November 2020. In its answer, System Energy argued that all of the claims raised in the complaint should be dismissed and agreed that bill adjustment with respect to two discrete issues were justified. System Energy argued that dismissal is warranted because all claims fall into one or more of the following categories: the claims have been raised and are being litigated in another proceeding; the claims do not present a prima facie case and do not satisfy the threshold burden to establish a complaint proceeding; the claims are premised on a theory or request relief that is incompatible with federal law or FERC policy; the claims request relief that is inconsistent with the filed rate; the claims are barred or waived by the legal doctrine of laches; and/or the claims have been fully addressed and do not warrant further litigation. In December 2020, System Energy filed a bill adjustment report indicating that $3.4 million had been credited to customers in connection with the two discrete issues concerning the inclusion of certain accumulated deferred income taxes balances in rates. In January 2021 the complainants filed a response to System Energy’s November 2020 answer, and in February 2021, System Energy filed a response to the complainant’s response.
In May 2021 the FERC issued an order addressing the complaint, establishing a refund effective date of September 21, 2020, establishing hearing procedures, and holding those procedures in abeyance pending FERC’s review of the initial decision in the Grand Gulf sale-leaseback renewal complaint discussed above. System Energy agreed that the hearing should be held in abeyance but sought rehearing of FERC’s decision as related to matters set
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for hearing that were beyond the scope of FERC’s jurisdiction or authority. The complainants sought rehearing of FERC’s decision to hold the hearing in abeyance and filed a motion to proceed, which motion System Energy subsequently opposed. In June 2021, System Energy’s request for rehearing was denied by operation of law, and System Energy filed an appeal of FERC’s orders in the Court of Appeals for the Fifth Circuit. The appeal was initially stayed for a period of 90 days, but the stay expired. In November 2021 the Fifth Circuit dismissed the appeal as premature.
In August 2021 the FERC issued an order addressing System Energy’s and the complainants’ rehearing requests. The FERC dismissed part of the complaint seeking an equity re-opener, maintained the abeyance for issues related to the proceeding addressing the sale-leaseback renewal and uncertain tax positions, lifted the abeyance for issues unrelated to that proceeding, and clarified the scope of the hearing.
In November 2021 the LPSC, the APSC, and the City Council filed direct testimony and requested the FERC to order refunds for prior periods and prospective amendments to the Unit Power Sales Agreement. The LPSC’s refund claims include, among other things, allegations that: (1) System Energy should not have included certain sale-leaseback transaction costs in prepayments; (2) System Energy should have credited rate base to reflect the time value of money associated with the advance collection of lease payments; (3) System Energy incorrectly included refueling outage costs that were recorded in account 174 in rate base; and (4) System Energy should have excluded several accumulated deferred income tax balances in account 190 from rate base. The LPSC is also seeking a retroactive adjustment to retained earnings and capital structure in conjunction with the implementation of its proposed refunds. In addition, the LPSC seeks amendments to the Unit Power Sales Agreement going forward to address below-the-line costs, incentive compensation, the working capital allowance, litigation expenses, and the 2019 termination of the capital funds agreement. The APSC argues that: (1) System Energy should have included borrowings from the Entergy System money pool in its determination of short-term debt in its cost of capital; and (2) System Energy should credit customers with System Energy’s allocation of earnings on money pool investments. The City Council alleges that System Energy has maintained excess cash on hand in the money pool and that retention of excess cash was imprudent. Based on this allegation, the City Council’s witness recommends a refund of approximately $98.8 million for the period 2004-September 2021 or other alternative relief. The City Council further recommends that the FERC impose a hypothetical equity ratio such as 48.15% equity to capital on a prospective basis.
In January 2022, System Energy filed answering testimony arguing that the FERC should not order refunds for prior periods or any prospective amendments to the Unit Power Sales Agreement. In response to the LPSC’s refund claims, System Energy argues, among other things, that: (1) the inclusion of sale-leaseback transaction costs in prepayments was correct; (2) that the filed rate doctrine bars the request for a retroactive credit to rate base for the time value of money associated with the advance collection of lease payments; (3) that an accounting misclassification for deferred refueling outage costs has been corrected, caused no harm to customers, and requires no refunds; and (4) that its accounting and ratemaking treatment of specified accumulated deferred income tax balances in account 190 has been correct. System Energy further responds that no retroactive adjustment to retained earnings or capital structure should be ordered because there is no general policy requiring such a remedy, and there was no showing that the retained earnings element of the capital structure was incorrectly implemented. Further, System Energy presented evidence that all of the costs that are being challenged were long known to the retail regulators and were approved by them for inclusion in retail rates, and the attempt to retroactively challenge these costs, some of which have been included in rates for decades, is unjust and unreasonable. In response to the LPSC’s proposed going-forward adjustments, System Energy presents evidence to show that none of the proposed adjustments are needed. On the issue of below-the-line expenses, during discovery procedures System Energy identified a historical allocation error in certain months and agreed to provide a bill credit to customers to correct the error. In response to the APSC’s claims, System Energy argues that the Unit Power Sales Agreement does not include System Energy’s borrowings from the Entergy System money pool or earnings on deposits to the Entergy System money pool in the determination of the cost of capital; and accordingly, no refunds are appropriate on those issues. In response to the City Council’s claims, System Energy argues that it has reasonably managed its cash and that the City Council’s theory of cash management is defective because it fails to adequately consider the relevant
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cash needs of System Energy and it makes faulty presumptions about the operation of the Entergy System money pool. System Energy further points out that the issue of its capital structure is already subject to pending FERC litigation.
In March 2022 the FERC trial staff filed direct and answering testimony in response to the LPSC, the APSC, and the City Council’s direct testimony. In its testimony, the FERC trial staff recommends refunds for two primary reasons: (1) it concluded that System Energy should have excluded specified accumulated deferred income tax balances in account 190 associated with rate refunds; and (2) it concluded that System Energy should have excluded specified accumulated deferred income tax balances in account 190 associated with a deemed contract satisfaction and reissuance that occurred in 2005. The FERC trial staff recommends refunds of $84.1 million, exclusive of any tax gross-up or FERC interest. In addition, the FERC trial staff recommends the following prospective modifications to the Unit Power Sales Agreement: (1) inclusion of a rate base credit to recognize the time value of money associated with the advance collection of lease payments; (2) exclusion of executive incentive compensation costs for members of the Office of the Chief Executive and long-term performance unit costs where awards are based solely or primarily on financial metrics; and (3) exclusion of unvested, accrued amounts for stock options, performance units, and restricted stock awards. With respect to issues that ultimately concern the reasonableness of System Energy’s rate of return, the FERC trial staff states that it is unnecessary to consider such issues in this proceeding, in light of the pending case concerning System Energy’s return on equity and capital structure. On all other material issues raised by the LPSC, the APSC, and the City Council, the FERC trial staff recommends either no refunds or no modification to the Unit Power Sales Agreement.
In April 2022, System Energy filed cross-answering testimony in response to the FERC trial staff’s recommendations of refunds for the accumulated deferred income taxes issues and proposed modifications to the Unit Power Sales Agreement for the executive incentive compensation issues. In June 2022 the FERC trial staff submitted revised answering testimony, in which it recommended additional refunds associated with the accumulated deferred income tax balances in account 190 associated with a deemed contract satisfaction and reissuance that occurred in 2005. Based on the testimony revisions, the FERC trial staff’s recommended refunds total $106.6 million, exclusive of any tax gross-up or FERC awarded interest. Also in June 2022, System Energy filed revised and supplemental cross-answering testimony to respond to the changes in the FERC trial staff’s testimony and oppose its revised recommendation.
In May 2022 the LPSC, the APSC, and the City Council filed rebuttal testimony. The LPSC’s testimony asserts new claims, including that: (1) certain of the sale-leaseback transaction costs may have been imprudently incurred; (2) accumulated deferred income taxes associated with sale-leaseback transaction costs should have been included in rate base; (3) accumulated deferred income taxes associated with federal investment tax credits should have been excluded from rate base; (4) monthly net operating loss accumulated deferred income taxes should have been excluded from rate base; and (5) several categories of proposed rate changes, including executive incentive compensation, air travel, industry dues, and legal costs, also warrant historical refunds. The LPSC’s rebuttal testimony argues that refunds for the alleged tariff violations and other claims must be calculated by rerunning the Unit Power Sales Agreement formula rate; however, it includes estimates of refunds associated with some, but not all, of its claims, totaling $286 million without interest. The City Council’s rebuttal testimony also proposes a new, alternate theory and claim for relief regarding System Energy’s participation in the Entergy System money pool, under which it calculates estimated refunds of approximately $51.7 million. The APSC’s rebuttal testimony agrees with the LPSC’s direct testimony that retained earnings should be adjusted in a comprehensive refund calculation. The testimony quantifies the estimated impacts of three issues: (1) a $1.5 million reduction in the revenue requirement under the Unit Power Sales Agreement if System Energy’s borrowings from the money pool are included in short-term debt; (2) a $1.9 million reduction in the revenue requirement if System Energy’s allocated share of money pool earnings are credited through the Unit Power Sales Agreement; and (3) a $1.9 million reduction in the revenue requirement for every $50 million of refunds ordered in a given year, without interest. In total, excluding the settled issues noted below, the claims seek more than $700 million in refunds and interest, based on charges to all Unit Power Sales Agreement purchasers including Entergy Mississippi.
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Management’s Financial Discussion and Analysis
In June 2022 a new procedural schedule was adopted, providing for additional rounds of testimony and for the hearing to begin in September 2022. The hearing concluded in December 2022. Also in December 2022, a motion to extend the briefing schedule and the deadline for the initial decision was granted. The initial decision is due in May 2023.
In November 2022, System Energy filed a partial settlement agreement with the APSC, the City Council, and the LPSC that resolves the following issues raised in the Unit Power Sales Agreement complaint: advance collection of lease payments, aircraft costs, executive incentive compensation, money pool borrowings, advertising expenses, deferred nuclear refueling outage costs, industry association dues, and termination of the capital funds agreement. The settlement provides that System Energy will provide a black-box refund of $18 million (inclusive of interest), plus additional refund amounts with interest to be calculated for certain issues to be distributed to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans as the Utility operating companies other than Entergy Mississippi purchasing under the Unit Power Sales Agreement. The settlement further provides that if the APSC, the City Council, or the LPSC agrees to the global settlement System Energy entered into with the MPSC (discussed below), and such global settlement includes a black-box refund amount, then the black-box refund for this settlement agreement shall not be incremental or in addition to the global black-box refund amount. The settlement agreement addresses other matters as well, including adjustments to rate base beginning in October 2022, exclusion of certain other costs, and inclusion of money pool borrowings, if any, in short-term debt within the cost of capital calculation used in the Unit Power Sales Agreement. The settlement agreement is pending FERC approval.
LPSC Petition for Writ of Mandamus
In August 2022 the LPSC filed a petition for a writ of mandamus asking the Fifth Circuit Court of Appeals to order the FERC to act within ninety days on certain pending proceedings, including the Grand Gulf prudence complaint, the return on equity and capital structure complaints, and the Grand Gulf sale-leaseback renewal complaint. In September 2022 the FERC and System Energy filed oppositions to the LPSC’s petition, and the APSC and the City Council filed interventions in support of the petition. In December 2022 the Fifth Circuit Court of Appeals heard oral argument on the petition. In January 2023, the Fifth Circuit Court of Appeals issued an order directing the FERC to explain the length of time it takes for final action on complaints filed under section 206 of the Federal Power Act, including the complaint proceedings raised by the LPSC’s petition. In February 2023 the FERC responded, and the Fifth Circuit Court of Appeals issued an order denying the petition.
Grand Gulf Prudence Complaint
The second of the additional complaints was filed at the FERC in March 2021 by the LPSC, the APSC, and the City Council against System Energy, Entergy Services, Entergy Operations, and Entergy Corporation. The second complaint contains two primary allegations. First, it alleges that, based on the plant’s capacity factor and alleged safety performance, System Energy and the other respondents imprudently operated Grand Gulf during the period 2016-2020, and it seeks refunds of at least $360 million in alleged replacement energy costs, in addition to other costs, including those that can only be identified upon further investigation. Second, it alleges that the performance and/or management of the 2012 extended power uprate of Grand Gulf was imprudent, and it seeks refunds of all costs of the 2012 uprate that are determined to result from imprudent planning or management of the project. In addition to the requested refunds, the complaint asks that the FERC modify the Unit Power Sales Agreement to provide for full cost recovery only if certain performance indicators are met and to require pre-authorization of capital improvement projects in excess of $125 million before related costs may be passed through to customers in rates. In April 2020.2021, System Energy and the other respondents filed their motion to dismiss and answer to the complaint. System Energy requested that the FERC dismiss the claims within the complaint. With respect to the claim concerning operations, System Energy argues that the complaint does not meet its legal burden because, among other reasons, it fails to allege any specific imprudent conduct. With respect to the claim concerning the uprate, System Energy argues that the complaint fails because, among other reasons, the complainants’ own conduct prevents them from raising a serious doubt as to the prudence of the uprate. System
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
Energy also requests that the FERC dismiss other elements of the complaint, including the proposed modifications to the Unit Power Sales Agreement, because they are not warranted. Additional responsive pleadings were filed by the complainants and System Energy during the period from March through July 2021. In November 2022 the FERC issued an order setting the complaint for settlement and hearing procedures. In February 2023 the FERC issued an order denying rehearing and thereby affirming its order setting the complaint for settlement and hearing procedures. Settlement procedures are ongoing.
System Energy Formula Rate Annual Protocols Formal Challenge Concerning 2020 Calendar Year Bills
System Energy’s Unit Power Sales Agreement includes formula rate protocols that provide for the disclosure of cost inputs, an opportunity for informal discovery procedures, and a challenge process. In February 2022, pursuant to the protocols procedures, the LPSC, the APSC, the MPSC, the City Council, and the Mississippi Public Utilities Staff filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2020. The formal challenge alleges: (1) that it was imprudent for System Energy to accept the IRS’s partial acceptance of a previously uncertain tax position; (2) that System Energy should have delayed recording the result of the IRS’s partial acceptance of the previously uncertain tax position until after internal tax allocation payments were made; (3) that the equity ratio charged in rates was excessive; (4) that sale-leaseback rental payments should have been excluded from rates; and (5) that all issues in the ongoing Unit Power Sales Agreement complaint proceeding should also be reflected in calendar year 2020 bills. While System Energy disagrees that any refunds are owed for the 2020 calendar year bills, the formal challenge estimates that the financial impact of the first through fourth allegations is approximately $53 million; it does not provide an estimate of the financial impact of the fifth allegation. However, $17 million of the $53 million is attributable to the sale-leaseback rental payments. These were refunded to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans in January 2023 as a result of the FERC order received in the Grand Gulf sale-leaseback renewal complaint and uncertain tax position rate base issue. Entergy Mississippi’s portion of the refund was included within the settlement with the MPSC, as discussed below.
In March 2022, System Energy filed an answer to the formal challenge in which it requested that the FERC deny the formal challenge as a matter of law, or else hold the proceeding in abeyance pending the resolution of related dockets.
System Energy Settlement with the MPSC
In June 2022, System Energy, Entergy Mississippi, and additional named Entergy parties involved in thirteen docketed proceedings before the FERC filed with the FERC a partial settlement agreement and offer of settlement. The settlement memorializes the Entergy parties’ agreement with the MPSC to globally resolve all actual and potential claims between the Entergy parties and the MPSC associated with those FERC proceedings and with System Energy’s past implementation of the Unit Power Sales Agreement. The Unit Power Sales Agreement is a FERC-jurisdictional formula rate tariff for sales of energy and capacity from System Energy’s owned and leased share of Grand Gulf to Entergy Mississippi, Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans. Entergy Mississippi purchases the greatest single amount, nearly 40% of System Energy’s share of Grand Gulf, after its additional purchases from affiliates are considered. The settlement therefore limits System Energy’s overall refund exposure associated with the identified proceedings because they will be resolved completely as between the Entergy parties and the MPSC.
The FERC proceedings that are resolved as between the Entergy parties and the MPSC include the return on equity and capital structure complaints, the Grand Gulf Sale-leaseback renewal complaint and uncertain tax position rate base issue, the Unit Power Sales Agreement complaint, and the Grand Gulf prudence complaint, all of which are discussed above. They also include the proceedings concerning System Energy’s return of excess accumulated deferred income taxes after the Tax Cuts and Jobs Act and the proceedings established to address System Energy’s October 2020 and December 2020 Federal Power Act section 205 filings to provide credits to customers related to the IRS’s decision as to the uncertain decommissioning tax position, also as discussed. The settlement also resolves
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
the MPSC’s involvement in the formal challenge filed by the retail regulators of System Energy’s customers in connection with the implementation of the Unit Power Sales Agreement annual formula rate protocols for the 2020 test year, which is discussed above.
The settlement provides for a black-box refund of $235 million from System Energy to Entergy Mississippi, which was to be paid within 120 days of the settlement’s effective date (either the date of the FERC approval of the settlement without material modification, or the date that all settling parties agree to accept modifications or otherwise modify the settlement in response to a proposed material modification by the FERC). In addition, beginning with the July 2022 service month, the settlement provides for Entergy Mississippi’s bills from System Energy to be adjusted to reflect: an authorized rate of return on equity of 9.65%, a capital structure not to exceed 52% equity, a rate base reduction for the advance collection of sale-leaseback rental costs, and the exclusion of certain long-term incentive plan performance unit costs from rates.
The settlement was expressly contingent upon the approval of the FERC and the MPSC. It was approved by the MPSC in June 2022 and the FERC in November 2022. The remaining retail regulators of Entergy’s utility operating company purchasers under the Unit Power Sales Agreement (the APSC, the LPSC, and the City Council) were offered an option to elect to join the settlement, but none of them has elected to do so yet.
System Energy previously recorded a provision and associated liability of $37 million for elements of the applicable litigation. In June 2022, System Energy recorded a regulatory charge of $551 million ($413 million net-of-tax), increasing the regulatory liability to $588 million, which consisted of $235 million for the settlement with the MPSC and $353 million for potential future refunds to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans. System Energy paid the black-box refund of $235 million to Entergy Mississippi in November 2022. In addition, as discussed above in “Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue,” $103.5 million of the total remaining regulatory liability of $353 million was reclassified to a current regulatory liability as of December 31, 2022 to reflect the refunds being paid to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans in January 2023 as a result of the FERC’s order in December 2022 on those issues.
Unit Power Sales Agreement
In August 2017,December 2021, 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.expenses. The proposed amendments would result in lowerhigher 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 2017February 2022 the FERC accepted System Energy’sEntergy’s proposed Unit Power Sales Agreement amendments, subject to further proceedings to consider the justness and reasonablenessincreased depreciation rates with an effective date 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 OctoberMarch 1, 2017,2022, 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.procedures. Settlement procedures are ongoing.
Nuclear Matters
System Energy owns and, through an affiliate, operates Grand Gulf. System Energy is, therefore, subject to the risks related to owning and operating a nuclear plant. These include risks related to: the use, storage, and handling and disposal of high-level and low-level radioactive materials; the substantial financial requirements, both for capital investments and operational needs, to position Entergy’s nuclear fleetGrand Gulf to meet its operational goals,goals; the performance and capacity factors of Grand Gulf, including the financial requirements to address emerging issues like stress corrosion cracking of certain materials within the plant systems and the Fukushima event;related to equipment reliability; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license renewal and amendments, and decommissioning; the performance and capacity factors of these nuclear plants; the availability of interim or permanent sites for the disposal of spent nuclear fuel and nuclear waste, including the fees charged for such disposal; the sufficiency
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
of nuclear decommissioning trust fund assets and earnings to complete decommissioning of eachthe site when required; and limitations on the amounts and types of insurance commercially available for losses in connection with nuclear plant operations and catastrophic events such as a nuclear accident. In the event of an unanticipated early shutdown of Grand Gulf, System Energy may be
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. Grand Gulf’s operating license expires in 2044.
Environmental Risks
System Energy’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that System Energy is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of System Energy’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and there is the potential for future changes in the assumptions and measurements that could produce estimates that would have a material impact on the presentation of System Energy’s financial position or results of operations.
Nuclear Decommissioning Costs
See “Nuclear Decommissioning Costs” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.
Utility Regulatory Accounting
See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.
Impairment of Long-lived Assets and Trust Fund Investments
See “Impairment of Long-lived Assets and Trust Fund Investments” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the impairment of long-lived assets and trust fund investments.assets.
Taxation and Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.
Qualified Pension and Other Postretirement Benefits
System Energy’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2023 Qualified Pension Cost | | Impact on 2022 Projected Qualified Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $236 | | $6,882 |
| Rate of return on plan assets | | (0.25%) | | $498 | | $— |
| Rate of increase in compensation | | 0.25% | | $194 | | $1,248 |
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2020 Qualified Pension Cost | | Impact on 2019 Projected Qualified Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $737 | | $10,902 |
| Rate of return on plan assets | | (0.25%) | | $666 | | $— |
| Rate of increase in compensation | | 0.25% | | $422 | | $2,072 |
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2023 Postretirement Benefit Cost | | Impact on 2022 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $55 | | $954 |
| Health care cost trend | | 0.25% | | $146 | | $845 |
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2020 Postretirement Benefit Cost | | Impact on 2019 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $31 | | $1,507 |
| Health care cost trend | | 0.25% | | $64 | | $1,164 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Employer Contributions
Total qualified pension cost for System Energy in 20192022 was $12.3 million.$21.7 million, including $9.9 million in settlement costs. System Energy anticipates 20202023 qualified pension cost to be $17.6$8.1 million. System Energy contributed $20.2$28.6 million to its qualified pension plans in 20192022 and estimates 20202023 pension contributions will approximate $10.5$15.5 million, although the 20202023 required pension contributions will be known with more certainty when the January 1, 20202023 valuations are completed, which is expected by April 1, 2020.2023.
Total postretirement health care and life insurance benefit income for System Energy in 20192022 was $1 million. System Energy expects 20202023 postretirement health care and life insurance benefit income to approximate $1.3 million.$348 thousand. System Energy contributed $829$944 thousand to its other postretirement plans in 20192022 and expects 20202023 contributions to approximate $21$26 thousand.
Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholder and Board of Directors of
System Energy Resources, Inc.
Opinion on the Financial Statements
We have audited the accompanying balance sheets of System Energy Resources, Inc. (the “Company”) as of December 31, 20192022 and 2018,2021, the related statements of income,operations, cash flows, and changes in common equity (pages 425470 through 430474 and applicable items in pages 4953 through 236)245), for each of the three years in the period ended December 31, 2019,2022, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20192022 and 2018,2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2022, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that is material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing separate opinion on the critical audit matters or on the accounts or disclosures to which they relate.
Rate and Regulatory Matters —System Energy Resources, Inc. — Refer to Note 2 to the financial statements
Critical Audit Matter Description
The Company is subject to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.
The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the FERC sets the rates the Company is allowed to charge customers based on allowable costs, including a reasonable
return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the (1) likelihood of recovery in future rates of incurred costs, (2) likelihood of refunds to customers, and (3) ongoing complaints filed with the FERC against the Company. Auditing management’s judgments regarding the outcome of future decisions by the FERC, involved specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and significant auditor judgment to evaluate management estimates and the subjectivity of audit evidence.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the FERC included the following, among others:
•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 Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the FERC for the Company, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of 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.
•For regulatory matters in process, including the Return on Equity and Capital Structure Complaints, the Grand Gulf Sale-Leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue, the Unit Power Sales Agreement Complaint, the Grand Gulf Prudence Complaint, and the SERI Formula Rate Annual Protocols Formal Challenge Concerning 2020 Calendar Year Bills, we inspected the Company’s and intervenors’ filings with the FERC, initial Administrative Law Judge decisions and FERC orders issued related to the complaints, and settlement offers and agreements related to the complaints for any evidence that might contradict management’s assertions.
•We obtained an analysis from management and support 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 not yet addressed in a regulatory order, including the complaints filed with the FERC against the Company, to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 21, 202024, 2023
We have served as the Company’s auditor since 2001.
| | | | | | | | | | | | | | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. |
| STATEMENTS OF OPERATIONS |
| | |
| | | For the Years Ended December 31, |
| | | 2022 | | 2021 | | 2020 |
| | | (In Thousands) |
| | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | | $658,812 | | | $570,848 | | | $495,458 | |
| | | | | | |
| OPERATING EXPENSES | | | | | | |
| Operation and Maintenance: | | | | | | |
| Fuel, fuel-related expenses, and gas purchased for resale | | 50,216 | | | 58,313 | | | 23,026 | |
| Nuclear refueling outage expenses | | 24,482 | | | 27,244 | | | 27,737 | |
| Other operation and maintenance | | 226,557 | | | 214,322 | | | 178,249 | |
| Decommissioning | | 40,235 | | | 38,693 | | | 37,181 | |
| Taxes other than income taxes | | 29,428 | | | 27,842 | | | 28,657 | |
| Depreciation and amortization | | 111,889 | | | 105,978 | | | 110,395 | |
| Other regulatory charges (credits) - net | | 503,162 | | | 26,214 | | | (26,531) | |
| TOTAL | | 985,969 | | | 498,606 | | | 378,714 | |
| | | | | | |
| OPERATING INCOME (LOSS) | | (327,157) | | | 72,242 | | | 116,744 | |
| | | | | | |
| OTHER INCOME (DEDUCTIONS) | | | | | | |
| Allowance for equity funds used during construction | | 8,312 | | | 6,188 | | | 9,122 | |
| Interest and investment income | | 5,096 | | | 82,744 | | | 36,478 | |
| Miscellaneous - net | | (19,616) | | | (18,991) | | | (10,012) | |
| TOTAL | | (6,208) | | | 69,941 | | | 35,588 | |
| | | | | | |
| INTEREST EXPENSE | | | | | | |
| Interest expense | | 37,381 | | | 38,393 | | | 34,467 | |
| Allowance for borrowed funds used during construction | | (1,325) | | | (1,047) | | | (1,809) | |
| TOTAL | | 36,056 | | | 37,346 | | | 32,658 | |
| | | | | | |
| INCOME (LOSS) BEFORE INCOME TAXES | | (369,421) | | | 104,837 | | | 119,674 | |
| | | | | | |
| Income taxes | | (92,828) | | | (1,977) | | | 20,543 | |
| | | | | | |
| NET INCOME (LOSS) | | ($276,593) | | | $106,814 | | | $99,131 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. |
| INCOME STATEMENTS |
| | | |
| | | For the Years Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | |
| $573,410 |
| |
| $456,707 |
| |
| $633,458 |
|
| | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 82,438 |
| | 64,778 |
| | 71,700 |
|
| Nuclear refueling outage expenses | | 33,376 |
| | 20,715 |
| | 17,968 |
|
| Other operation and maintenance | | 206,444 |
| | 196,505 |
| | 207,344 |
|
| Decommissioning | | 35,729 |
| | 34,336 |
| | 43,347 |
|
| Taxes other than income taxes | | 29,018 |
| | 28,090 |
| | 26,180 |
|
| Depreciation and amortization | | 106,630 |
| | 97,527 |
| | 137,767 |
|
| Other regulatory credits - net | | (35,210 | ) | | (28,924 | ) | | (37,831 | ) |
| TOTAL | | 458,425 |
| | 413,027 |
| | 466,475 |
|
| | | | | | | |
| OPERATING INCOME | | 114,985 |
| | 43,680 |
| | 166,983 |
|
| | | | | | | |
| OTHER INCOME | | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 8,709 |
| | 8,750 |
| | 6,345 |
|
| Interest and investment income | | 29,488 |
| | 35,985 |
| | 17,538 |
|
| Miscellaneous - net | | (5,516 | ) | | (5,775 | ) | | (6,711 | ) |
| TOTAL | | 32,681 |
| | 38,960 |
| | 17,172 |
|
| | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
|
| Interest expense | | 35,328 |
| | 38,424 |
| | 37,141 |
|
| Allowance for borrowed funds used during construction | | (2,131 | ) | | (2,218 | ) | | (1,551 | ) |
| TOTAL | | 33,197 |
| | 36,206 |
| | 35,590 |
|
| | | | | | | |
| INCOME BEFORE INCOME TAXES | | 114,469 |
| | 46,434 |
| | 148,565 |
|
| | | | | | | |
| Income taxes | | 15,349 |
| | (47,675 | ) | | 69,969 |
|
| | | | | | | |
| NET INCOME | |
| $99,120 |
| |
| $94,109 |
| |
| $78,596 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. |
| STATEMENTS OF CASH FLOWS |
| | |
| | | For the Years Ended December 31, |
| | | 2022 | | 2021 | | 2020 |
| | | (In Thousands) |
| | | | | | |
| OPERATING ACTIVITIES | | | | | | |
| Net income (loss) | | ($276,593) | | | $106,814 | | | $99,131 | |
| Adjustments to reconcile net income (loss) to net cash flow provided by (used in) operating activities: | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 194,411 | | | 198,067 | | | 184,429 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | (85,720) | | | 11,191 | | | (455,732) | |
| Changes in assets and liabilities: | | | | | | |
| Receivables | | (19,530) | | | 6,054 | | | 13,932 | |
| Accounts payable | | (11,948) | | | 23,973 | | | (11,587) | |
| Taxes accrued | | (25,321) | | | (50,059) | | | 69,145 | |
| Interest accrued | | (123) | | | (1,008) | | | 729 | |
| Other working capital accounts | | (38,764) | | | 25,096 | | | (34,158) | |
| Other regulatory assets | | (19,575) | | | 143,417 | | | (48,880) | |
| Other regulatory liabilities | | 21,252 | | | 40,884 | | | 140,965 | |
| | | | | | |
| Pension and other postretirement liabilities | | (35,354) | | | (49,308) | | | 15,596 | |
| Other assets and liabilities | | 304,545 | | | (253,910) | | | (119,032) | |
| Net cash flow provided by (used in) operating activities | | 7,280 | | | 201,211 | | | (145,462) | |
| INVESTING ACTIVITIES | | | | | | |
| Construction expenditures | | (164,797) | | | (100,474) | | | (193,857) | |
| Allowance for equity funds used during construction | | 8,312 | | | 6,188 | | | 9,122 | |
| Nuclear fuel purchases | | (96,659) | | | (45,180) | | | (94,991) | |
| Proceeds from the sale of nuclear fuel | | 18,855 | | | 21,724 | | | 25,836 | |
| Decrease (increase) in other investments | | 300 | | | (300) | | | — | |
| Proceeds from nuclear decommissioning trust fund sales | | 346,504 | | | 1,022,170 | | | 418,943 | |
| Investment in nuclear decommissioning trust funds | | (357,463) | | | (1,025,779) | | | (432,249) | |
| Changes in money pool receivable - net | | (19,236) | | | (71,741) | | | 55,294 | |
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | — | | | — | | | 5,459 | |
| Net cash flow used in investing activities | | (264,184) | | | (193,392) | | | (206,443) | |
| FINANCING ACTIVITIES | | | | | | |
| Proceeds from the issuance of long-term debt | | 1,022,472 | | | 662,423 | | | 1,147,903 | |
| Retirement of long-term debt | | (986,829) | | | (727,510) | | | (891,410) | |
| Capital contribution from parent | | 135,000 | | | — | | | 350,000 | |
| | | | | | |
| | | | | | |
| Common stock dividends and distributions paid | | — | | | (96,000) | | | (80,653) | |
| | | | | | |
| Net cash flow provided by (used in) financing activities | | 170,643 | | | (161,087) | | | 525,840 | |
| Net increase (decrease) in cash and cash equivalents | | (86,261) | | | (153,268) | | | 173,935 | |
| Cash and cash equivalents at beginning of period | | 89,201 | | | 242,469 | | | 68,534 | |
| Cash and cash equivalents at end of period | | $2,940 | | | $89,201 | | | $242,469 | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | |
| Cash paid during the period for: | | | | | | |
| Interest - net of amount capitalized | | $39,848 | | | $39,340 | | | $35,061 | |
| Income taxes | | $18,413 | | | $54,959 | | | $384,329 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
(Page left blank intentionally)
|
| | | | | | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. |
| STATEMENTS OF CASH FLOWS |
| | | |
| | | For the Years Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | |
| Net income | |
| $99,120 |
| |
| $94,109 |
| |
| $78,596 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 212,170 |
| | 186,719 |
| | 240,962 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 95 |
| | 24,040 |
| | 7,827 |
|
| Changes in assets and liabilities: | | |
| | |
| | |
|
| Receivables | | (23,382 | ) | | 18,169 |
| | 9,210 |
|
| Accounts payable | | 18,204 |
| | (7,067 | ) | | 15,969 |
|
| Prepaid taxes and taxes accrued | | 19,247 |
| | (51,999 | ) | | 62,466 |
|
| Interest accrued | | (1,302 | ) | | (94 | ) | | (660 | ) |
| Other working capital accounts | | 15,879 |
| | (45,415 | ) | | 12,083 |
|
| Other regulatory assets | | (43,712 | ) | | (2,044 | ) | | 60,012 |
|
| Other regulatory liabilities | | 130,949 |
| | (156,802 | ) | | 331,251 |
|
| Deferred tax rate change recognized as regulatory liability/asset | | — |
| | — |
| | (325,707 | ) |
| Pension and other postretirement liabilities | | 11,177 |
| | (23,235 | ) | | 4,024 |
|
| Other assets and liabilities | �� | (138,304 | ) | | 64,947 |
| | (124,755 | ) |
| Net cash flow provided by operating activities | | 300,141 |
| | 101,328 |
| | 371,278 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
|
| Construction expenditures | | (166,695 | ) | | (194,696 | ) | | (91,705 | ) |
| Allowance for equity funds used during construction | | 8,709 |
| | 8,750 |
| | 6,345 |
|
| Nuclear fuel purchases | | (18,170 | ) | | (125,272 | ) | | (49,728 | ) |
| Proceeds from the sale of nuclear fuel | | 26,223 |
| | 30,634 |
| | 69,516 |
|
| Proceeds from nuclear decommissioning trust fund sales | | 500,384 |
| | 573,561 |
| | 565,416 |
|
| Investment in nuclear decommissioning trust funds | | (517,828 | ) | | (583,683 | ) | | (596,236 | ) |
| Changes in money pool receivable - net | | 47,824 |
| | 4,545 |
| | (77,858 | ) |
| Net cash flow used in investing activities | | (119,553 | ) | | (286,161 | ) | | (174,250 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | 1,103,917 |
| | 741,785 |
| | 150,100 |
|
| Retirement of long-term debt | | (1,187,406 | ) | | (662,904 | ) | | (150,103 | ) |
| Changes in short-term credit borrowings - net | | — |
| | (17,830 | ) | | (49,063 | ) |
| Common stock dividends and distributions | | (124,250 | ) | | (67,720 | ) | | (106,610 | ) |
| Other | | — |
| | — |
| | (28 | ) |
| Net cash flow used in financing activities | | (207,739 | ) | | (6,669 | ) | | (155,704 | ) |
| Net increase (decrease) in cash and cash equivalents | | (27,151 | ) | | (191,502 | ) | | 41,324 |
|
| Cash and cash equivalents at beginning of period | | 95,685 |
| | 287,187 |
| | 245,863 |
|
| Cash and cash equivalents at end of period | |
| $68,534 |
| |
| $95,685 |
| |
| $287,187 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | |
| | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $21,052 |
| |
| $17,183 |
| |
| $26,251 |
|
| Income taxes | |
| $2,284 |
| |
| $53,956 |
| |
| ($2,227 | ) |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. |
| BALANCE SHEETS |
| ASSETS |
| | |
| | | December 31, |
| | | 2022 | | 2021 |
| | | (In Thousands) |
| | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | | $78 | | | $87 | |
| Temporary cash investments | | 2,862 | | | 89,114 | |
| Total cash and cash equivalents | | 2,940 | | | 89,201 | |
| Accounts receivable: | | | | |
| Associated companies | | 158,601 | | | 118,977 | |
| Other | | 6,145 | | | 7,003 | |
| Total accounts receivable | | 164,746 | | | 125,980 | |
| | | | |
| Materials and supplies - at average cost | | 135,346 | | | 127,093 | |
| Deferred nuclear refueling outage costs | | 33,377 | | | 10,123 | |
| | | | |
| Prepayments and other | | 9,097 | | | 1,870 | |
| TOTAL | | 345,506 | | | 354,267 | |
| | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | |
| Decommissioning trust funds | | 1,142,914 | | | 1,385,254 | |
| TOTAL | | 1,142,914 | | | 1,385,254 | |
| | | | |
| UTILITY PLANT | | | | |
| Electric | | 5,425,449 | | | 5,362,494 | |
| | | | |
| Construction work in progress | | 102,987 | | | 97,968 | |
| Nuclear fuel | | 193,004 | | | 171,438 | |
| TOTAL UTILITY PLANT | | 5,721,440 | | | 5,631,900 | |
| Less - accumulated depreciation and amortization | | 3,412,257 | | | 3,396,136 | |
| UTILITY PLANT - NET | | 2,309,183 | | | 2,235,764 | |
| | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | |
| Regulatory assets: | | | | |
| | | | |
| Other regulatory assets | | 415,121 | | | 395,546 | |
| | | | |
| Other | | 1,422 | | | 1,793 | |
| TOTAL | | 416,543 | | | 397,339 | |
| | | | |
| TOTAL ASSETS | | $4,214,146 | | | $4,372,624 | |
| | | | |
| See Notes to Financial Statements. | | | | |
|
| | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. |
| BALANCE SHEETS |
| ASSETS |
| | | |
| | | December 31, |
| | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | |
| $93 |
| |
| $68 |
|
| Temporary cash investments | | 68,441 |
| | 95,617 |
|
| Total cash and cash equivalents | | 68,534 |
| | 95,685 |
|
| Accounts receivable: | | |
| | |
|
| Associated companies | | 121,972 |
| | 148,571 |
|
| Other | | 7,547 |
| | 5,390 |
|
| Total accounts receivable | | 129,519 |
| | 153,961 |
|
| Materials and supplies - at average cost | | 108,766 |
| | 97,225 |
|
| Deferred nuclear refueling outage costs | | 14,493 |
| | 44,424 |
|
| Prepaid taxes | | — |
| | 5,415 |
|
| Prepayments and other | | 6,045 |
| | 2,985 |
|
| TOTAL | | 327,357 |
| | 399,695 |
|
| | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
|
| Decommissioning trust funds | | 1,054,098 |
| | 869,543 |
|
| TOTAL | | 1,054,098 |
| | 869,543 |
|
| | | | | |
| UTILITY PLANT | | |
| | |
|
| Electric | | 5,070,859 |
| | 5,036,116 |
|
| Construction work in progress | | 164,996 |
| | 70,156 |
|
| Nuclear fuel | | 149,574 |
| | 234,889 |
|
| TOTAL UTILITY PLANT | | 5,385,429 |
| | 5,341,161 |
|
| Less - accumulated depreciation and amortization | | 3,285,487 |
| | 3,212,080 |
|
| UTILITY PLANT - NET | | 2,099,942 |
| | 2,129,081 |
|
| | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
|
| Regulatory assets: | | |
| | |
|
| Other regulatory assets | | 490,083 |
| | 446,371 |
|
| Accumulated deferred income tax | | 8,023 |
| | — |
|
| Other | | 3,192 |
| | 4,124 |
|
| TOTAL | | 501,298 |
| | 450,495 |
|
| | | | | |
| TOTAL ASSETS | |
| $3,982,695 |
| |
| $3,848,814 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
| | | | | | | | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. |
| BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | |
| | | December 31, |
| | | 2022 | | 2021 |
| | | (In Thousands) |
| | | | |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | | $300,037 | | | $50,329 | |
| | | | |
| Accounts payable: | | | | |
| Associated companies | | 21,701 | | | 23,682 | |
| Other | | 58,178 | | | 62,573 | |
| Taxes accrued | | 7,597 | | | 32,918 | |
| | | | |
| Interest accrued | | 11,591 | | | 11,714 | |
| | | | |
| Sale-leaseback/depreciation regulatory liability | | 103,497 | | | — | |
| Other | | 4,071 | | | 4,101 | |
| TOTAL | | 506,672 | | | 185,317 | |
| | | | |
| NON-CURRENT LIABILITIES | | | | |
| Accumulated deferred income taxes and taxes accrued | | 376,070 | | | 382,931 | |
| Accumulated deferred investment tax credits | | 44,692 | | | 43,003 | |
| Regulatory liability for income taxes - net | | 110,840 | | | 113,165 | |
| Other regulatory liabilities | | 665,024 | | | 744,944 | |
| Decommissioning | | 1,042,461 | | | 1,007,603 | |
| Pension and other postretirement liabilities | | 40,750 | | | 76,104 | |
| Long-term debt | | 477,868 | | | 690,967 | |
| Other | | 2 | | | 37,230 | |
| TOTAL | | 2,757,707 | | | 3,095,947 | |
| | | | |
| Commitments and Contingencies | | | | |
| | | | |
| COMMON EQUITY | | | | |
| Common stock, no par value, authorized 1,000,000 shares; issued and outstanding 789,350 shares in 2022 and 2021 | | 1,086,850 | | | 951,850 | |
| | | | |
| Retained earnings (accumulated deficit) | | (137,083) | | | 139,510 | |
| TOTAL | | 949,767 | | | 1,091,360 | |
| | | | |
| TOTAL LIABILITIES AND EQUITY | | $4,214,146 | | | $4,372,624 | |
| | | | |
| See Notes to Financial Statements. | | | | |
|
| | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. |
| BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | | |
| | | December 31, |
| | | 2019 | | 2018 |
| | | (In Thousands) |
| | | | | |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | |
| $10 |
| |
| $6 |
|
| Accounts payable: | | |
| | |
|
| Associated companies | | 14,619 |
| | 11,031 |
|
| Other | | 64,144 |
| | 47,565 |
|
| Taxes accrued | | 13,832 |
| | — |
|
| Interest accrued | | 11,993 |
| | 13,295 |
|
| Current portion of unprotected excess accumulated deferred income taxes | | — |
| | 4,426 |
|
| Other | | 3,381 |
| | 2,832 |
|
| TOTAL | | 107,979 |
| | 79,155 |
|
| | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 821,963 |
| | 805,296 |
|
| Accumulated deferred investment tax credits | | 40,181 |
| | 38,673 |
|
| Regulatory liability for income taxes - net | | 142,845 |
| | 158,998 |
|
| Other regulatory liabilities | | 533,415 |
| | 381,887 |
|
| Decommissioning | | 931,729 |
| | 896,000 |
|
| Pension and other postretirement liabilities | | 109,816 |
| | 98,639 |
|
| Long-term debt | | 548,097 |
| | 630,744 |
|
| Other | | 34,602 |
| | 22,224 |
|
| TOTAL | | 3,162,648 |
| | 3,032,461 |
|
| | | | | |
| Commitments and Contingencies | |
|
| |
|
|
| | | | | |
| COMMON EQUITY | | |
| | |
|
| Common stock, no par value, authorized 1,000,000 shares; issued and outstanding 789,350 shares in 2019 and 2018 | | 601,850 |
| | 601,850 |
|
| Retained earnings | | 110,218 |
| | 135,348 |
|
| TOTAL | | 712,068 |
| | 737,198 |
|
| | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $3,982,695 |
| |
| $3,848,814 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
| | | | | | | | | | | | | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. |
| STATEMENTS OF CHANGES IN COMMON EQUITY |
| For the Years Ended December 31, 2022, 2021, and 2020 |
| | | |
| | Common Equity | | |
| | Common Stock | | | | Retained Earnings (Accumulated Deficit) | | Total |
| | (In Thousands) |
| | | | | | | |
| Balance at December 31, 2019 | $601,850 | | | | | $110,218 | | | $712,068 | |
| Net income | — | | | | | 99,131 | | | 99,131 | |
| Capital contribution from parent | 350,000 | | | | | — | | | 350,000 | |
| Common stock dividends and distributions | — | | | | | (80,653) | | | (80,653) | |
| Balance at December 31, 2020 | $951,850 | | | | | $128,696 | | | $1,080,546 | |
| Net income | — | | | | | 106,814 | | | 106,814 | |
| | | | | | | |
| Common stock dividends and distributions | — | | | | | (96,000) | | | (96,000) | |
| Balance at December 31, 2021 | $951,850 | | | | | $139,510 | | | $1,091,360 | |
| Net loss | — | | | | | (276,593) | | | (276,593) | |
| Capital contribution from parent | 135,000 | | | | | — | | | 135,000 | |
| | | | | | | |
| Balance at December 31, 2022 | $1,086,850 | | | | | ($137,083) | | | $949,767 | |
| | | | | | | |
| See Notes to Financial Statements. | | | | | | | |
|
| | | | | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. |
| STATEMENTS OF CHANGES IN COMMON EQUITY |
| For the Years Ended December 31, 2019, 2018, and 2017 |
| | | | |
| | Common Equity | | |
| | Common Stock | | Retained Earnings | | Total |
| | (In Thousands) |
| | | | | | |
| Balance at December 31, 2016 |
| $679,350 |
| |
| $59,473 |
| |
| $738,823 |
|
| Net income | — |
| | 78,596 |
| | 78,596 |
|
| Common stock dividends and distributions | (21,000 | ) | | (85,610 | ) | | (106,610 | ) |
| Balance at December 31, 2017 |
| $658,350 |
| |
| $52,459 |
| |
| $710,809 |
|
| Net income | — |
| | 94,109 |
| | 94,109 |
|
| Common stock dividends and distributions | (56,500 | ) | | (11,220 | ) | | (67,720 | ) |
| Balance at December 31, 2018 |
| $601,850 |
| |
| $135,348 |
| |
| $737,198 |
|
| Net income | — |
| | 99,120 |
| | 99,120 |
|
| Common stock dividends and distributions | — |
| | (124,250 | ) | | (124,250 | ) |
| Balance at December 31, 2019 |
| $601,850 |
| |
| $110,218 |
| |
| $712,068 |
|
| | | | | | |
| See Notes to Financial Statements. | |
| | |
| | |
|
|
| | | | | | | | | | | | | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | |
| | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| | (Dollars In Thousands) |
| | | | | | | | | | |
| Operating revenues |
| $573,410 |
| |
| $456,707 |
| |
| $633,458 |
| |
| $548,291 |
| |
| $632,405 |
|
| Net income |
| $99,120 |
| |
| $94,109 |
| |
| $78,596 |
| |
| $96,744 |
| |
| $111,318 |
|
| Total assets |
| $3,982,695 |
| |
| $3,848,814 |
| |
| $3,938,887 |
| |
| $3,927,712 |
| |
| $3,728,875 |
|
| Long-term obligations (a) |
| $548,097 |
| |
| $630,744 |
| |
| $466,484 |
| |
| $501,129 |
| |
| $572,665 |
|
| Electric energy sales (GWh) | 9,940 |
| | 6,264 |
| | 6,675 |
| | 5,384 |
| | 10,547 |
|
| | | | | | | | | | |
| (a) Includes long-term debt (excluding currently maturing debt). |
Item 2. Properties
Information regarding the registrant’s properties is included in Part I. Item 1. - Entergy’s Business under the sections titled “Utility - Property and Other Generation Resources” and “Entergy Wholesale Commodities - Property” in this report.
Item 3. Legal Proceedings
Details of the registrant’s material environmental regulation and proceedings and other regulatory proceedings and litigation that are pending or those terminated in the fourth quarter of 20192021 are discussed in Part I. Item 1. - Entergy’s Business under the sections titled “Retail Rate Regulation,” “Environmental Regulation,” and “Litigation.” and “Impairment of Long-lived Assets” in Note 14to the financial statements.
Item 4. Mine Safety Disclosures
Not applicable.
INFORMATION ABOUT EXECUTIVE OFFICERS OF ENTERGY CORPORATION
Executive Officers
| | | | | | | | | | | | | | | | | | | | |
| Name | | Age | | Position | | Period |
| Leo P. Denault (a) | | 63 | | Chairman of the Board of Entergy Corporation | | 2013-2023 |
| | | | Chief Executive Officer of Entergy Corporation | | 2013-2022 |
| | | | | | |
NameAndrew S. Marsh (a) | | Age51 | | Position | | Period |
Leo P. Denault (a) | | 60 | | Chairman of the Board and Chief Executive Officer of Entergy Corporation | | 2013-Present2022-Present |
| | | | Chairman of the Board of Entergy Corporation | | 2023-Present |
| | | | Executive Vice President and Chief Financial Officer of Entergy Corporation | | 2013-2022 |
| | | | Director of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy | | 2013-2022 |
| | | | Executive Vice President and Chief Financial Officer of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy | | 2014-2022 |
| | | | | | |
| A. Christopher Bakken, III (a) | | 5861 | | Executive Vice President, Entergy Infrastructure of Entergy Corporation | | 2022-Present |
| | | | Executive Vice President and Chief Nuclear Officer of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy | | 2016-Present2016-2022 |
| | | | Project Director, Hinkley Point C of EDF Energy | | 2009-2016 |
| | | | | | |
| Marcus V. Brown (a) | | 5861 | | Executive Vice President and General Counsel of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy | | 2013-Present |
| | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Andrew S. MarshName | | Age | | Position | | Period |
| Kimberly A. Fontan (a) | | 4849 | | Executive Vice President and Chief Financial Officer of Entergy Corporation | | 2013-Present2022-Present |
| | | | Director of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy | | 2013-Present2022-Present |
| | | | Executive Vice President and Chief Financial Officer of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy | | 2014-Present |
| 2022-Present |
| | | | | | |
Name | | Age | | Position | | Period |
Roderick K. West (a) | | 51 | | Group President Utility Operations of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas | | 2017-Present |
| | | | President, Chief Executive Officer, and Director of System Energy | | 2017-Present |
| | | | Director of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy | | 2017-Present |
| | | | President and Chief Executive Officer of Entergy New Orleans | | 2018 |
| | | | Executive Vice President of Entergy Corporation | | 2010-2017 |
| | | | Chief Administrative Officer of Entergy Corporation | | 2010-2016 |
| | | | | | |
Paul D. Hinnenkamp (a) | | 58 | | Executive Vice President and Chief Operating Officer of Entergy Corporation | | 2017-Present |
| | | | Director of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas | | 2015-Present |
| | | | Senior Vice President and Chief Operating Officer of Entergy Corporation | | 2015-2017 |
| | | | Senior Vice President, Capital Project Management and Technology of Entergy Services, Inc. | | 2015 |
| | | | Vice President, Capital Project Management and Technology of Entergy Services, Inc. | | 2013-2015 |
| | | | | | |
Kimberly A. Fontan (a) | | 46 | | Senior Vice President and Chief Accounting Officer of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy | | 2019-Present2019-2022 |
| | | | Vice President, System Planning of Entergy Services, Inc.Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas | | 2017-2019 |
| | | | | | |
| Roderick K. West (a) | | 54 | | Group President Utility Operations of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas | | 2017-Present |
| | | | President, Chief Executive Officer, and Director of System Energy | | 2017-Present |
| | | | Director of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy | | 2017-Present |
| | | | President and Chief Executive Officer of Entergy New Orleans | | 2018 |
| | | | | | |
| Jason Chapman | | 52 | | Acting Senior Vice President, RegulatoryCorporate Business Services of Entergy Services Inc. | | 2015-20172023-Present |
| | | | Vice President, Regulatory AffairsEnterprise Shared Services of Entergy LouisianaServices | | 2014-20152019-2023 |
| | | | Vice President, Global Business Services, Xylem, Inc. | | 2016-2019 |
Peter S. Norgeot, Jr. | | | | | | |
| Kimberly Cook-Nelson (a) | | 5450 | | Executive Vice President and Chief Nuclear Officer of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy | | 2022-Present |
| | | | Director of System Energy | | 2022-Present |
| | | | Chief Operating Officer, Nuclear Operations of Entergy Services | | 2021-2022 |
| | | | Vice President, System Planning of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas | | 2019-2021 |
| | | | Vice President, Operations Support of Entergy Services | | 2016-2019 |
| | | | | | |
| Kathryn A. Collins | | 59 | | Senior Vice President Transformationand Chief Human Resources Officer of Entergy Corporation | | 2018-Present2020-Present |
| | | | Senior Chief Human Resources Officer, Arcosa, Inc. | | 2018-2020 |
| | | | Vice President, Power Generation of Entergy ServicesHuman Resources, Trinity, Inc. | | 2017-20182014-2018 |
| | | | Vice President, Fossil Generation of Entergy Services | | 2015-2017 |
| | | | Vice President, Power Plant Operations, Steam of Entergy Services | | 2014-2015 |
| | | | | | |
| Julie E. Harbert (a) | | 4649 | | Senior Vice President, Corporate Business Services of Entergy Corporation | | 2019-Present2019-2023 |
| | | | Vice President, Shared Services of Entergy Services Inc. | | 2017-2019 |
| | | | Senior Vice President, Global Business Services of Philips Health Tech | | 2015-2017 |
| | | | Vice President and Group Head of Operations, Global Shared Services of IBM | | 2014 |
| | | | | | | | | | | | | | | | | | | | |
(a)Name | In addition, this officer is an executive officer and/or director | Age | | Position | | Period |
| Anastasia Minor | | 53 | | Chief Transformation Officer of various other wholly owned subsidiariesEntergy Services | | 2023-Present |
| | | | Senior Vice President, Strategy and Financial Planning of Entergy Services | | 2022-2023 |
| | | | Vice President, Financial Business Partners of Entergy Services | | 2017-2022 |
| | | | | | |
| Peter S. Norgeot, Jr. (a) | | 57 | | Executive Vice President and Chief Operating Officer of Entergy Corporation | | 2022-Present |
| | | | Director of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas | | 2022-Present |
| | | | Senior Vice President, Operations and Development of Entergy Corporation | | 2022 |
| | | | Senior Vice President, Sustainable Planning, Development and Operations of Entergy Corporation | | 2021-2022 |
| | | | Senior Vice President, Transformation of Entergy Corporation | | 2018-2021 |
| | | | Senior Vice President, Power Generation of Entergy Services | | 2017-2018 |
| | | | | | |
| Reginald T. Jackson (a) | | 56 | | Senior Vice President and Chief Accounting Officer of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and its operating companies.System Energy | | 2022-Present |
| | | | Vice President, Internal Audit and General Auditor of Entergy Services | | 2020-2022 |
| | | | Director, Real Estate and Security of Entergy Services | | 2014-2020 |
(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.
Each officer of Entergy Corporation is elected yearly by the Board of Directors. Each officer’s age and title are provided as of December 31, 2019.2022.
PART II
Item 5. Market for Registrants’ Common Equity and Related Stockholder Matters
Entergy Corporation
The shares of Entergy Corporation’s common stock are listed on the New York Stock and Chicago Stock Exchanges under the ticker symbol ETR. As of January 31, 2020,2023, there were 23,69620,696 stockholders of record of Entergy Corporation. See “Dividends and Stock Repurchases” in the “Capital Expenditure Plans and Other Uses of Capital” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 7 to the financial statements for details of Entergy Corporation’s payment of dividends.
Unregistered Sales of Equity Securities and Use of Proceeds
Issuer Purchases of Equity Securities (1)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Total Number of Shares Purchased | | Average Price Paid per Share | | Total Number of Shares Purchased as Part of a Publicly Announced Plan | | Maximum $ Amount of Shares that May Yet be Purchased Under a Plan (2) |
| | | | | | | | | |
10/01/20192022 - 10/31/20192022 | | — |
| |
| $— |
| — | — |
| $350,052,918 |
| $350,052,918 |
|
11/01/20192022 - 11/30/20192022 | | — |
| |
| $— |
| — | — |
| $350,052,918 |
| $350,052,918 |
|
12/01/20192022 - 12/31/20192022 | | — |
| |
| $— |
| — | — |
| $350,052,918 |
| $350,052,918 |
|
| Total | | | — |
| |
| $— |
| — | — |
| | |
In accordance with Entergy’s stock-based compensation plans, Entergy periodically grants stock options to key employees, which may be exercised to obtain shares of Entergy’s common stock. According to the plans, these shares can be newly issued shares, treasury stock, or shares purchased on the open market. Entergy’s management has been authorized by the Board to repurchase on the open market shares up to an amount sufficient to fund the exercise of grants under the plans. In addition to this authority, the Board has authorized share repurchase programs to enable opportunistic purchases in response to market conditions. In October 2010 the Board granted authority for a $500 million share repurchase program. The amount of share repurchases under these programs may vary as a result of material changes in business results or capital spending or new investment opportunities. In addition, in the first quarter 2019,2022, Entergy withheld 76,73579,738 shares of its common stock at $86.03$110.35 per share, 82,55077,207 shares of its common stock at $86.51$111.16 per share, 38,32635,940 shares of its common stock at $87.10$111.77 per share, 9321,219 shares of its common stock at $89.19$109.01 per share, and 2,280577 shares of its common stock at $93.25$106.62 per share, 232 shares of its common stock at $110.77 per share, 87 shares of its common stock at $109.01 per share, and 82 shares of its common stock at $111.47 per share to pay income taxes due upon vesting of restricted stock granted and payout of performance units as part of its long-term incentive program.
| |
(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. |
(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 and 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.
Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy
There is no market for the common equity of the Registrant Subsidiaries. Information with respect to restrictions that limit the ability of the Registrant Subsidiaries to pay dividends or distributions is presented in Note 7 to the financial statements.
Item 6. Reserved
Selected Financial Data
Refer to “SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON OF ENTERGY CORPORATION AND SUBSIDIARIES, ENTERGY ARKANSAS, LLC AND SUBSIDIARIES, ENTERGY LOUISIANA, LLC AND SUBSIDIARIES, ENTERGY MISSISSIPPI, LLC, ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES, ENTERGY TEXAS, INC. AND SUBSIDIARIES, and SYSTEM ENERGY RESOURCES, INC.” which follow each company’s financial statements in this report, for information with respect to selected financial data and certain operating statistics.Table of Contents
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Refer to “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS OF ENTERGY CORPORATION AND SUBSIDIARIES, ENTERGY ARKANSAS, LLC AND SUBSIDIARIES, ENTERGY LOUISIANA, LLC AND SUBSIDIARIES, ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES, ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES, ENTERGY TEXAS, INC. AND SUBSIDIARIES, and SYSTEM ENERGY RESOURCES, INC.”
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Refer to “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS OF ENTERGY CORPORATION AND SUBSIDIARIES - Market and Credit Risk Sensitive Instruments.”
Item 8. Financial Statements and Supplementary Data
Refer to “TABLE OF CONTENTS - Entergy Corporation and Subsidiaries, Entergy Arkansas, LLC and Subsidiaries, Entergy Louisiana, LLC and Subsidiaries, Entergy Mississippi, LLC and Subsidiaries, Entergy New Orleans, LLC and Subsidiaries, Entergy Texas, Inc. and Subsidiaries, and System Energy Resources, Inc.”
Item 9. Changes Inin and Disagreements Withwith Accountants Onon Accounting and Financial Disclosure
No event that would be described in response to this item has occurred with respect to Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, or System Energy.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
As of December 31, 2019,2022, evaluations were performed under the supervision and with the participation of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy (individually(each individually a “Registrant” and collectively the “Registrants”) management, including their respective Principal Executive Officers (PEO) and Principal Financial Officers (PFO). The evaluations assessed the effectiveness of the Registrants’ disclosure controls and procedures. Based on the evaluations, each PEO and PFO has concluded that, as to the Registrant or Registrants for which they serve as PEO or PFO, the Registrant’s or Registrants’ disclosure controls and procedures are effective to ensure that information required to be disclosed by each Registrant in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms; and that the Registrant’s or Registrants’ disclosure controls and procedures are also effective in reasonably assuring that such information is accumulated and communicated to the Registrant’s or Registrants’ management, including their respective PEOs and PFOs, as appropriate to allow timely decisions regarding required disclosure.
Internal Control over Financial Reporting (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The managements of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy (individually(each individually a “Registrant” and collectively the “Registrants”) are responsible for establishing and maintaining adequate internal control over financial reporting for the Registrants. Each Registrant’s internal control system is designed to provide reasonable assurance regarding the preparation and fair presentation of each Registrant’s financial statements presented in accordance with generally accepted accounting principles.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Each Registrant’s management assessed the effectiveness of each Registrant’s internal control over financial reporting as of December 31, 2019.2022. In making this assessment, each Registrant’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. The 2013 COSO Framework was utilized for management’s assessment.
Based on each management’s assessment and the criteria set forth by the 2013 COSO Framework, each Registrant’s management believes that each Registrant maintained effective internal control over financial reporting as of December 31, 2019.2022.
The report of Deloitte & Touche LLP, Entergy Corporation’s independent registered public accounting firm, regarding Entergy Corporation’s internal control over financial reporting is included herein. The report of Deloitte & Touche LLP is not applicable to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy because these Registrants are non-accelerated filers.
Changes in Internal Controls over Financial Reporting
Under the supervision and with the participation of each Registrant’s management, including its respective PEO and PFO, each Registrant evaluated changes in internal control over financial reporting that occurred during the quarter ended December 31, 20192022 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.
Attestation Report of Registered Public Accounting Firm
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and Board of Directors of
Entergy Corporation and Subsidiaries
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Entergy Corporation and Subsidiaries (the “Corporation”) as of December 31, 2019,2022, based on criteria established in Internal Control -Integrated—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019,2022, based on criteria established in Internal Control -– Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 20192022 of the Corporation and our report dated February 21, 202024, 2023 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Item 9A, Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Corporation’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 21, 202024, 2023
Item 9B. Other Information
None.
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
PART III
Item 10. Directors, Executive Officers, and Corporate Governance of the Registrants (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Information required by this item concerning directors of Entergy Corporation is set forth under the heading “Proposal 1 – Election of Directors” contained in the Proxy Statement of Entergy Corporation, to be filed in connection with its Annual Meeting of Stockholders to be held May 8, 2020,5, 2023 (the “2023 Entergy Proxy Statement”), and is incorporated herein by reference.
All officers and directors listed below held the specified positions with their respective companies as of the date of filing this report, unless otherwise noted.
| | | | | | | | | | | | | | | | | | | | |
| Name | | Age | | Position | | Period |
| Entergy Arkansas, LLC |
| | | | | | |
NameDirectors | | Age | | Position | | Period |
Entergy Arkansas, LLC |
| | | | | | |
Directors | | | | | | |
| Laura R. Landreaux | | 4649 | | President and Chief Executive Officer of Entergy Arkansas | | 2018-Present |
| | | | Director of Entergy Arkansas | | 2018-Present |
| | | | Operational Finance Director of Entergy Arkansas | | 2017-2018 |
| Kimberly A. Fontan | | | | Vice President, Regulatory Affairs of Entergy Arkansas | | 2014-2017 |
| | | | | | |
Paul D. Hinnenkamp | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
AndrewPeter S. MarshNorgeot, Jr. | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Roderick K. West | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| | | | | | |
| Officers | | | | | | |
A. Christopher Bakken III | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Marcus V. Brown | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
Leo P. DenaultKimberly Cook-Nelson | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
Paul D. HinnenkampKimberly A. Fontan |
| | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
Laura R. LandreauxReginald T. Jackson | | | | See information under the Entergy Arkansas Directors Section above. | | |
Andrew S. Marsh | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
Kimberly A. FontanLaura R. Landreaux |
| | | See information under the Entergy Arkansas Directors Section above. | | |
| Andrew S. Marsh |
| | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Roderick K. West |
| | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC |
| Directors | | | | | | |
| Phillip R. May, Jr. | | 60 | | President and Chief Executive Officer of Entergy Louisiana | | 2013-Present |
| | | | Director of Entergy Louisiana | | 2013-Present |
| | | | | | |
ENTERGY LOUISIANA, LLC |
DirectorsKimberly A. Fontan | | | | | | |
Phillip R. May, Jr. | | 57 | | President and Chief Executive Officer of Entergy Louisiana | | 2013-Present |
| | | | Director of Entergy Louisiana | | 2013-Present |
| | | | | | |
Paul D. Hinnenkamp | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
AndrewPeter S. MarshNorgeot, Jr. | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Roderick K. West | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| | | | | | |
| Officers | | | | | | |
A. Christopher Bakken III | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Marcus V. Brown | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
Leo P. DenaultKimberly Cook-Nelson | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
Paul D. HinnenkampKimberly A. Fontan | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
Andrew S. MarshReginald T. Jackson | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
Phillip R. May, Jr.Andrew S. Marsh | | | | See information under the Entergy Louisiana Directors Section above. | | |
Kimberly A. Fontan | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Phillip R. May, Jr. | | | | See information under the Entergy Louisiana Directors Section above. | | |
| Roderick K. West | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, LLC |
| Directors | | | | | | |
| Haley R. Fisackerly | | 57 | | President and Chief Executive Officer of Entergy Mississippi | | 2008-Present |
| | | | Director of Entergy Mississippi | | 2008-Present |
| | | | | | |
ENTERGY MISSISSIPPI, LLC |
DirectorsKimberly A. Fontan | | | | | | |
Haley R. Fisackerly | | 54 | | President and Chief Executive Officer of Entergy Mississippi | | 2008-Present |
| | | | Director of Entergy Mississippi | | 2008-Present |
| | | | | | |
Paul D. Hinnenkamp | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
AndrewPeter S. MarshNorgeot, Jr. | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Roderick K. West | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
|
| | | | | | | | | | | | | | | | | | | |
| Officers | | | | | | |
Marcus V. BrownA. Christopher Bakken | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
Leo P. DenaultMarcus V. Brown | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Haley R. Fisackerly | | | | See information under the Entergy Mississippi Directors Section above. | | |
Paul D. HinnenkampKimberly A. Fontan | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
Andrew S. MarshReginald T. Jackson | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
Kimberly A. FontanAndrew S. Marsh | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Roderick K. West | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, LLC |
| Directors | | | | | | |
| Deanna D. Rodriguez | | 58 | | President and Chief Executive Officer of Entergy New Orleans | | 2021-Present |
| | | | Director of Entergy New Orleans | | 2021-Present |
| | | | Vice President, Regulatory and Public Affairs of Entergy Texas | | 2014-2021 |
| | | | | | |
| | | | | | |
ENTERGY NEW ORLEANS, LLC |
DirectorsPeter S. Norgeot, Jr. | | | | | | |
David D. Ellis | | 51 | | President and Chief Executive Officer of Entergy New Orleans | | 2018-Present |
| | | | Director of Entergy New Orleans | | 2018-Present |
| | | | President and Chief Executive Officer, Global Power Technologies | | 2018 |
| | | | Managing Director and Chairman of Comverge International, Inc. | | 2010-2017 |
| | | | | | |
Paul D. Hinnenkamp | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
Andrew S. MarshRoderick K. West | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
Roderick K. West | | | | | | |
| Officers | | | | | | |
| A. Christopher Bakken | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
|
| | | | | | |
Officers | | | | | | |
| Marcus V. Brown | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
Leo P. DenaultKimberly A. Fontan | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
David D. EllisReginald T. Jackson | | | | See information under the Entergy New Orleans Directors Section above. | | |
Paul D. Hinnenkamp | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Andrew S. Marsh | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
Kimberly A. FontanDeanna D. Rodriguez | | | | See information under the Entergy New Orleans Directors Section above. | | |
| Roderick K. West | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| | | | | | | | | | | | | | | | | | | | |
Roderick K. WestENTERGY TEXAS, INC. |
| Directors | | | | | | |
| Eliecer Viamontes | | 40 | | President and Chief Executive Officer of Entergy Texas | | 2021-Present |
| | | | Director of Entergy Texas | | 2021-Present |
| | | | Vice President, Utility Distribution Operations of Entergy Services | | 2020-2021 |
| | | | Senior Director of Labor Relations and Corporate Safety, Florida Power and Light Corporation | | 2018-2020 |
| | | | | | |
| Kimberly A. Fontan | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
|
| Peter S. Norgeot, Jr. | | | | | | |
ENTERGY TEXAS, INC. |
Directors | | | | | | |
Sallie T. Rainer | | 57 | | President and Chief Executive Officer of Entergy Texas | | 2012-Present |
| | | | Director of Entergy Texas | | 2012-Present |
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Paul D. Hinnenkamp | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
Andrew S. MarshRoderick K. West | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
Roderick K. West | | | | | | |
| Officers | | | | | | |
| A. Christopher Bakken | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
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Officers | | | | | | |
| Marcus V. Brown | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
Leo P. DenaultKimberly A. Fontan | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
Paul D. HinnenkampReginald T. Jackson | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
| Andrew S. Marsh | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
Kimberly A. FontanEliecer Viamontes | | | | See information under the Entergy Texas Directors Section above. | | |
| Roderick K. West | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
Sallie T. Rainer | | | | See information under the Entergy Texas Directors Section above. | | |
Roderick K. West | | | | See information under the Information about Executive Officers of Entergy Corporation in Part I. | | |
The directors and officers of Entergy Texas are elected annually to serve by the unanimous consent of its sole common stockholder. The directors and officers of Entergy Arkansas, LLC, Entergy Louisiana, LLC, Entergy Mississippi, LLC and Entergy New Orleans LLC are elected annually to serve by the unanimous consent of the sole common membership owner, Entergy Utility Holding Company, LLC. Entergy Corporation’s directors are elected annually at the annual meeting of shareholders. Entergy Corporation’s officers are elected annually at the annual organizationala meeting of theits Board of Directors, which immediately follows the annual meeting of shareholders. The age of each officer and director for whom information is presented above is as of December 31, 2019.2022.
Corporate Governance GuidelinesDirectors, Director Nomination Process and Audit Committee Charters
EachThe information required under Item 10 concerning directors and nominees for election as directors of Entergy Corporation at the annual meeting of shareholders (Item 401 of Regulation S-K), the director nomination process (Item 407(c)(3) of Regulation S-K), the audit committee (Item 407(d)(4) and (d)(5) of Regulation S-K), and the compliance with the reporting requirements of Section 16 (“Section 16”) of the Audit, Corporate Governance, and Personnel CommitteesSecurities Exchange Act of 1934, as amended (the “Exchange Act”) (Item 405 of Regulation S-K) is incorporated herein by reference to information to be contained in the 2023 Entergy Corporation’s Board of Directors operates under a written charter. In addition, the Board has adopted Corporate Governance Guidelines. Each charter and the guidelines are available through Entergy’s website (www.entergy.com) or upon written request.
Audit Committee of the Entergy Corporation Board
The following directors are members of the Audit Committee of Entergy Corporation’s Board of Directors:
Patrick J. Condon (Chairman)
Philip L. Frederickson
M. Elise Hyland
Karen A. Puckett
All Audit Committee members are independent. In additionProxy Statement to the general independence requirements of the NYSE, all Audit Committee members must meet the heightened independence standards imposed bybe filed with the SEC and NYSE. All Audit Committee members possesspursuant to Regulation 14A under the levelExchange Act.
Code of Ethics
Effective October 2018, the Entergy Corporation Board of Directors adopted aCorporation’s Code of Business Conduct and Ethics (Code of Business Conduct) is the code of ethics that applies to membersEntergy’s Chief Executive Officer and other senior financial officers, including those of the Entergy Corporation Board of Directors and all Entergy officers and employees.Registrant Subsidiaries. The Code of Business Conduct is filed as Exhibit 14 to this report and Ethics includes Special Provisions Relating to Principal Executive Officer and Senior Financial Officers. It is to be read in conjunction with Entergy’s omnibus code of integrity under whichavailable on Entergy operates, called the Code of Entegrity, as well as system policies. All employees are expected to abide by the Codes. Non-bargaining employees are required to acknowledge annually that they understand and abide by the Code of Entegrity.Corporation’s website at www.entergy.com. The Code of Business Conduct and Ethics, includingwill be made available, without charge, in print to any shareholder who requests such document from Entergy Corporation’s Corporate Secretary at Entergy Corporation, 639 Loyola Avenue, New Orleans, Louisiana 70113.
If any substantive amendments to the Code of Business Conduct are made or any waivers thereto, andare granted, including any implicit waiver, from a provision of the Code of Entegrity are available through Entergy’s website (www.entergy.com)Business Conduct, for any director or upon written request.
Nominations to the Entergy Corporation Board of Directors; Nominating Procedure
Shareholders wishing to recommend a candidate to the Corporate Governance Committee should do so by submitting the recommendation in writing to Entergy Corporation’s Secretary at 639 Loyola Avenue, P.O. Box 61000, New Orleans, LA 70161, and it will be forwarded to the Corporate Governance Committee members for their consideration. Any recommendation should include:
the number of sharesexecutive officer of Entergy Corporation, stock held byEntergy will disclose 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 representationnature of such candidates’ intent to serve asamendment or waiver on Entergy’s website, www.entergy.com, or in a director for the entire term if elected.report on Form 8-K.
Once the Corporate Governance Committee receives the recommendation, it may request additional information from the candidate about the candidate’s independence, qualifications, and other information that would assist the Corporate Governance Committee in evaluating the candidate, as well as certain information that must be disclosed about the candidate in the Proxy Statement, if nominated. The Corporate Governance Committee will apply the same standards in considering director candidates recommended by shareholders as it applies to other candidates.
Item 11. Executive Compensation
ENTERGY CORPORATION
Information concerning compensation earned by the directors and officers of Entergy Corporation is set forth in itsthe 2023 Entergy Proxy Statement, to be filed in connection with the Annual Meeting of Shareholders to be held May 8, 2020,5, 2023, under the headings “Compensation Discussion and Analysis,” “Annual Compensation Programs Risk Assessment,” “Executive Compensation“Compensation Tables,” “Pay Ratio Disclosure,” “Our 2020 Director Nominees,” and “2019“2022 Non-Employee Director Compensation,” all of which information is incorporated herein by reference. References inIn this section, Entergy Corporation is also referred to as “Entergy” or the “Company” refer to Entergy Corporation.“Company.”
ENTERGY ARKANSAS, ENTERGY LOUISIANA, ENTERGY MISSISSIPPI, ENTERGY NEW ORLEANS, AND ENTERGY TEXAS
COMPENSATION DISCUSSION AND ANALYSIS
In this section,This Compensation Discussion and Analysis (“CD&A”) describes the executive compensation policies, programs, philosophy, and decisions regarding the Named Executive Officers (“NEOs”) for 2022. It also explains how and why the Talent and Compensation Committee (previously the Personnel Committee) of Entergy Corporation’s Board of Directors arrived at the compensation earneddecisions involving the NEOs in 2019 by the following executive officers (referred to herein as “Named Executive Officers”) is discussed.2022 who were:
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Name(1) | Title |
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NameA.(1)
| Title |
A. Christopher Bakken, III | Executive Vice President, Nuclear Operations/Chief Nuclear OfficerEntergy Infrastructure |
Marcus V. Brown | Executive Vice President and General Counsel |
Leo P. Denault(2) | Former Chairman of the Board and Chief Executive Officer |
David D. Ellis | President and Chief Executive Officer, Entergy New Orleans |
| Haley R. Fisackerly | President and Chief Executive Officer, Entergy Mississippi |
Laura R. LandreauxKimberly A. Fontan(3) | President and Chief Executive Officer, Entergy Arkansas |
Andrew S. Marsh | Executive Vice President and Chief Financial Officer, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas |
| Laura R. Landreaux | President and Chief Executive Officer, Entergy Arkansas |
Andrew S. Marsh(2) | Chairman of the Board and Chief Executive Officer |
| Phillip R. May, Jr. | President and Chief Executive Officer, Entergy Louisiana |
Sallie T. RainerDeanna D. Rodriguez | President and Chief Executive Officer, Entergy New Orleans |
| Eliecer Viamontes | President and Chief Executive Officer, Entergy Texas |
| Roderick K. West | Group President, Utility Operations, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas |
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(1) | (1)Messrs. Bakken, Brown, Denault, Marsh, and West and Ms. Fontan 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. |
Entergy Corporation’s Office of the Chief Executive Compensation Programs(“OCE”). No additional compensation was paid in 2022 to any of these officers for their service as NEOs of the Utility operating companies.
(2)On November 1, 2022, Mr. Marsh became Entergy Corporation’s Chief Executive Officer following Mr. Denault’s resignation as the Company’s Chief Executive Officer. Also on November 1, 2022, Mr. Denault was elected Executive Chair and Practicesin such role continued serving as Chairman of the Board. Effective January 31, 2023, Mr. Denault resigned from the position of Executive Chair and from the Board and Mr. Marsh was elected Chairman of the Board.
(3)Ms. Fontan, who previously served as Senior Vice President and Chief Accounting Officer, succeeded Mr. Marsh as Executive Vice President and Chief Financial Officer on November 1, 2022.
All of Entergy Corporation regularly reviewsArkansas’s, Entergy Louisiana’s, Entergy Mississippi’s, Entergy New Orleans’s, and Entergy Texas’s directors are employees of Entergy or its executivesubsidiaries and do not receive any additional compensation programs to align them with commonly viewed best practices in the market and to reflect feedback from discussions with investors on executive compensation.for their services as director.
Entergy Corporation’s Compensation Principles and Philosophy
Entergy Corporation’s executive compensation programs are based on a philosophy of pay for performance that is embodied inaimed at achieving the designCompany’s strategy and business objectives. Entergy Corporation believes its executive pay programs advance the interests of all of its annual stakeholders, as they are thoughtfully designed to:
•Motivateand reward the achievement of results that are deemed by the Talent and Compensation Committee to be consistent with the overall goals and strategic direction that the Board has approved for the Company.
•Attract and retain a highly experienced, diverse, and successful management team.
•Create sustainable value for the benefit of all of Entergy Corporation’s stakeholders, including its customers, employees, communities, and owners.
•Align the interests of Entergy Corporation’s executives with the Company’s long-term incentive plans. Itbusiness strategy by tying equity-based awards to performance metrics designed to focus Entergy Corporation’s executives on driving continuous improvement in operational and financial results to the benefit of all stakeholders, including Entergy Corporation’s customers, employees, communities, and owners.
Compensation Best Practices
The Talent and Compensation Committee reviews Entergy’s executive compensation programs on an ongoing basis to evaluate whether they support the Company’s executive compensation principles and philosophy and are aligned with the interests of our stakeholders. The Company’s executive compensation practices include the following, each of which the Talent and Compensation Committee believes thereinforces our executive pay programs:compensation principles and philosophy:
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• | 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.
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• | 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.
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• | 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.
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• | Create sustainable value for the benefit of all of Entergy Corporation’s stakeholders, including its owners, customers, employees and communities.
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Executive Compensation Best Practices:
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What Entergy Corporation DoesPractice | *Description |
| Pay for Performance | ExecutiveThe executive compensation programs yield pay outcomes that the Company believes are highly correlated towith performance and focused ondrive long-term value creationcreation. |
*Annual and Long-Term Incentive Measures Drive Desired Employee Behaviors
| Performance measures for the annual and long-term incentive programs are designed to incentivize employee behaviors that serve the Company’s key stakeholders: |
| • | Customers – Net Promoter Score (NPS). |
| • | Employees – Diversity, Inclusion, & Belonging (DIB) and Safety. |
| • | Communities – Environmental Stewardship, DIB. |
| • | Owners – Adjusted Earnings Per Share, Credit, TSR. |
Double triggerTrigger Change-in-Control | The Company requires both a change-in-control and an involuntary termination without cause or voluntary termination with good reason for cash severance payments and immediate vesting of unvested equity acceleration in the event of a change in controlawards. |
*Long-Term Incentives Paid in Stock | Clawback policyAll long-term incentives are settled in shares of Entergy common stock. |
*Stock Ownership Guidelines | MaximumThe Company requires executive officers to own a significant amount of Entergy stock. |
| Cap on Incentive Awards for OCE Members | The maximum payout for members of the OCE is capped at 200% of the target underopportunity for the Annual Incentive Planannual incentive and Long-Termlong-term Performance Unit Program for members of the Office of the Chief Executive(PUP) awards. |
*Rigorous Goals | Rigorous goal setting aligned withThe Company sets financial goals based on externally disclosed annual and multi-year financial targetsguidance and outlooks and non-financial goals based on rigorous internal review. |
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*Practice | Minimum vesting periods for equity-based awardsDescription |
*Clawback Policy | Long-termIf the Company is required to restate its financial statements due to noncompliance with financial reporting requirements under the securities laws or if there is a material miscalculation of a performance measure related to incentive compensation, mix weighted more towardregardless of whether the financials are restated, the Company’s clawback policy requires the Company to recover from current and former executive officers incentive compensation overpayments made during the three years preceding such restatement or material miscalculation, as applicable.
If the Board determines that a current or former executive officer engaged in fraud resulting in a restatement of the Company’s financial statements or a material miscalculation of an incentive compensation performance units than service-based equity awardsmeasure, the Company may seek to recover all or part of the incentive compensation affected by the fraudulent act and paid or payable to such executive officer during the three years preceding the restatement or the material miscalculation, as applicable. |
*No Hedging of Company Stock | All long-term incentive compensation is settledDirectors, executive officers, and employees of Entergy and its subsidiaries may not directly or indirectly engage in Entergy Corporationtransactions intended to hedge or offset the market value of the Company’s common stock owned by them. |
*No Pledging of Company Stock | RigorousDirectors and executive officers of Entergy and its subsidiaries may not directly or indirectly pledge Entergy common stock ownership and share retention requirementsas collateral for any obligation. |
*No Excessive Perquisites | Annual Say on Pay voteExecutive officers receive limited ongoing perquisites that make up a small portion of total compensation. |
What Entergy Corporation Doesn’t DoNo Tax Gross-Ups | * | No 280GThe Company does not provide tax “gross up” payments in the event of a change in control |
* | No tax “gross up” payments on any executive perquisites forgross ups to OCE members, of the Office of the Chief Executive, other than relocation benefitsbenefits. |
*No Dividends on Unearned Performance Awards | The Company does not pay dividends on unearned performance awards. |
No optionRepricing or Exchange of Underwater Stock Options | The Company’s equity incentive plan does not permit repricing or cash buy-outs forthe exchange of underwater stock options without shareholderthe approval of its shareholders. |
*No Employment Agreements | No agreements providing for severance payments toThe Company does not have employment contracts with its executive officers that exceed 2.99 times annual base salary and annual incentive awards without shareholder approvalofficers. |
*Independent Compensation Consultant | No unusualThe Talent and Compensation Committee retains an independent compensation consultant to advise on the executive compensation programs and practices. |
| Annual Say-on-Pay | The Company values the input of its shareholders on the executive compensation programs. Entergy’s Board seeks an annual non-binding advisory vote from shareholders to approve the executive compensation disclosed in the CD&A, tabular disclosure, and related narrative of the Company’s annual proxy statements. |
| Annual Compensation Risk Assessment | A risk assessment of the compensation programs is performed on an annual basis to ensure that the programs and policies do not incentivize unnecessary or excessive perquisites |
* | No hedging or pledging of Entergy Corporation common stock |
* | No fixed term employment agreements |
* | No new officer participation in the System Executive Retirement Plan |
* | No grants of supplemental service credit to newly-hired officers under any of Entergy Corporation’s non-qualified retirement plansrisk-taking behavior. |
2022 Incentive Payouts
Performance measures and targets for the 2022 annual incentive awards were determined by the Talent and Compensation Committee in December 2021 and January 2022, respectively. Performance measures and targets for the 2020 – 2022 performance period for the long-term PUP awards were established in December 2019 Executiveand January 2020, respectively. In January 2023 the Talent and Compensation Program ChangesCommittee certified the results for the Entergy Achievement Multiplier (“EAM”), the formulaic payout factor that determines the funding available for the 2022
During 2019,annual incentive awards, and certified the following changes were made to Entergy Corporation’s executive officer compensation programs:results for the long-term PUP awards for the 2020 – 2022 long-term performance period.
Annual Incentive PlanAwards
In recognition of Entergy Corporation’s successful execution on its strategy to exitDecember 2021 the Entergy Wholesale Commodities merchant power business, Entergy Corporation decided to establish a new, single earnings measure not calculated in accordance with generally accepted accounting principles inTalent and Compensation Committee determined that the United States (“GAAP”) for guidance
and investor reporting purposesEAM that would better reflect its ongoing businessdetermine the overall funding level for the 2022 annual incentive awards would be based on financial and respondnon-financial measures with the financial measure weighted 60% and the non-financial measures, which address key aspects of our performance on strategies designed to feedback received from investors onensure the earningslong-term health and success of the Company, collectively accounting for the remaining 40%.
Financial Measure: Keeping with the Talent and Compensation Committee’s goal of aligning performance measures on whichwith financial results that link to externally communicated investor guidance, Entergy Corporation had previously reported and guided. This new measure, EntergyTax Adjusted Earnings Per Share (“ETR Tax Adjusted EPS”), was used as the financial measure to determine the EAM.
Non-Financial Measures: To demonstrate Entergy’s strong commitment to creating long-term sustainable value for its key stakeholders - customers, communities, employees, and owners - and to link executive compensation more directly to the achievement of those objectives, the Talent and Compensation Committee decided that 40% of the EAM would be determined on the basis of progress achieved in the following areas, each of which would be weighted equally: Safety; Diversity, Inclusion, and Belonging; Environmental Stewardship; and the Customer Net Promoter Score, or NPS.
The 2022 annual incentive targets and results determined by the Talent and Compensation Committee were:
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Annual Incentive Performance Goals(1) | 2022 Percentage of EAM | Target | 2022 Results | Level of Achievement |
| ETR Tax Adjusted EPS ($) | 60% | 6.30 | 6.58 | 195% |
Safety (SIF Rate)(2) | 10% | 0.03 | 0.06 | 44% |
| Customer NPS | 10% | 12.00 | 5.60 | 31% |
| Diversity, Inclusion, and Belonging | 10% | Qualitative(3) | 90% |
| Environmental Stewardship | 10% | Qualitative(3) | 119% |
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| EAM as a percentage of target | | 100% | | 145% |
(1)“What Entergy Corporation Pays and Why – 2022 Compensation Decisions – Annual Incentive Compensation – 2022 Performance Assessment” for the minimum and maximum achievement levels.
(2)SIF Rate refers to rate of serious injuries and fatalities per 100 employees or contractors. The employee and contractor targets and results are averaged to arrive at reported results. The 2022 target was top quartile performance among electric utilities for 2022, as reported by the Edison Electric Institute.
(3)This qualitative assessment is informed by quantitative measures. See “What Entergy Corporation Pays and Why – 2022 Compensation Decisions – ESG Measures and Targets” for a discussion of the performance assessment of the Diversity, Inclusion, and Belonging and Environmental Stewardship performance measures.
After consideration of individual performance, the Talent and Compensation Committee awarded the NEOs payouts averaging 130% of target, with a payout of 130% of target to Mr. Denault.
Long-Term Performance Unit Program
In January 2020 the Talent and Compensation Committee chose relative TSR and Cumulative ETR Adjusted Earnings Per Share (“Cumulative ETR Adjusted EPS”) as the performance measures for the 2020 – 2022
performance period, with relative TSR weighted 80% and ETR Adjusted EPS weighted 20%. Cumulative ETR Adjusted EPS adjusts the Company’sEntergy’s as reported (GAAP) earnings per share results to eliminate the impact of itsthe Entergy Wholesale Commodities merchant power business significant tax items and other non-routine items. With this changeitems, consistent with the manner in the external guidance measure, and given the Personnel Committee’s desire to maintain an appropriate degree of alignment between the Company’s externallywhich we communicated earnings guidance and outlooks to investors at the time the measure was chosen.
The targets and results for the targets under2020 – 2022 performance period as determined by the Talent and Compensation Committee were:
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| Long-Term PUP Measures | 2020-2022 PUP Target | 2020-2022 PUP Results |
| Relative TSR | Median | 4th Quartile(2) |
Cumulative ETR Adjusted EPS($)(1) | 17.85 | 18.46 |
| Payout (as a percentage of target) | 100% | 27% |
(1)The Cumulative ETR Adjusted EPS measure was replaced in 2021 by Adjusted FFO/Debt Ratio to avoid the use of duplicative measures in the annual incentive plan, the committee adopted new performance measures to determine the maximum funding leveland long-term incentive programs. See “2022 Performance Measures and Methodology” below for additional discussion of the annual incentive plan with each performance measure weighted equally:
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.
Long-Term Incentives
In keeping with the change in Entergy Corporation’s external guidance measure, the committee also adopted a new earnings measure for use in measuring performance under the Long-Term Performance Unit Program. In particular, the committee decided that, for the 2019-2021 the Long-Term Performance Unit Program period, the performance measures will be (1) cumulative ETR Adjusted EPS, adjusted to eliminate the effect of any Pre-Determined Exclusions; and (2) relative total shareholder return with relative total shareholder return weighted eighty percent and cumulative ETR Adjusted EPS accounting for the remaining twenty percent.current long-term Performance Unit Program.
Short-Term and Long-Term Incentive Targets Tailored to Role
Beginning in 2019, the short and long-term incentive targets for officers who are members of Entergy Corporation’s Office (2)The Company ranked 16th of the Chief Executive are being determined based on job-specific market data for the officer’s role. Previously, the targets were the average of the market data for the officers within a specific management level, without regard to the officer’s specific job functions. The targets for the Named Executive Officers who are Presidents of the Utility operating20 companies continue to be determined based on the average of the market data for the officers within a specific management level, without regard to their specific job function. Entergy Corporation believes that this change for the members of the Office of the Chief Executive will help assure that each officer’s incentive targets are market competitive with respect to the officer’s particular role.
2019 Incentive Pay Outcomes
Entergy Corporation believes the 2019 incentive pay outcomes for the Named Executive Officers demonstrated the application of Entergy Corporation’s pay for performance philosophy.
Annual Incentive Plan
Awards under the Executive Annual Incentive Plan, or Annual Incentive Plan, are tied to Entergy Corporation’s financial and operational performance through the Entergy Achievement Multiplier (“EAM”), which is the performance metric used to determine the maximum funding available for awards under the plan. The 2019 EAM was determined based on the two equally weighted performance metrics discussed in the “2019 Executive Compensation Program Changes” section above.
2019 Annual Incentive Plan Payout
For 2019, the Personnel Committee, based on the recommendation of the Finance Committee, determined that management exceeded its ETR Tax Adjusted EPS goal of $5.30 per share by $1.23 per share and fell short of its ETR Adjusted Operating Cash Flow goal of $3.1 billion by approximately $134 million. Based on the targets and ranges previously established by the Personnel Committee, these results resulted in a calculated EAM of 139%.
Long-Term Performance Unit Program
Under the Long-Term Performance Unit Program, units are granted with performance measured over a three-year period based on Entergy Corporation’s total shareholder return in relation to the total shareholder return of the companies included in the Philadelphia Utility Index. Payouts, if any, are based on Entergy Corporation’s performance on these measures against pre-established performance goals.
Long-Term Performance Unit Program Payout
For the three-year performance period ending in 2019, Entergy Corporation’s total shareholder return was in the top quartile of the companies incomprising the Philadelphia Utility Index yielding a payout of 200% of target for the Named Executive Officers. Payouts were made in shares of Entergy Corporation stock which are required to be held by the executive officers until they satisfy the executive stock ownership guidelines.performance period.
What Entergy Corporation Pays and Why
How Entergy Corporation Makes Compensation Decisions
Role of the Talent and Compensation Committee
The Talent and Compensation Committee, which is composed solely of independent directors, determines the compensation for each member of the OCE and oversees the design and administration of Entergy’s executive compensation programs. Each year, the Talent and Compensation Committee reviews and considers a comprehensive assessment and analysis of the executive compensation programs, including the elements of each OCE member’s compensation, with input from the committee’s independent compensation consultant. When establishing the compensation programs for the NEOs, the Talent and Compensation Committee also considers input and recommendations from management, including Entergy’s Chief Executive Officer and Entergy’s Chief Human Resource Officer, who attend the Talent and Compensation Committee meetings as appropriate. The committee annually conducts an independence assessment of its advisors including the compensation consultant, consistent with NYSE listing standards and SEC rules governing proxy disclosure.
Role of the Independent Compensation Consultant
In 2022, the Talent and Compensation Committee continued to retain Pay Governance, LLC (“Pay Governance”) as its independent compensation consultant. Pay Governance attended each of the 2022 Talent and Compensation Committee meetings and provided advice, including reviewing and commenting on market compensation data used to establish the compensation of the executive officers and Entergy Corporation’s directors, the terms and performance goals applicable to incentive plan awards, the process for certifying achievement of the incentive goals, and analysis with respect to specific projects and information regarding trends and competitive practices.The compensation consultant also meets with the Talent and Compensation Committee members without management present.
Competitive Positioning
➢ Market Data for Compensation Comparison
Annually, the PersonnelTalent and Compensation Committee reviews:
Published•published and private compensation survey data compiledanalyzed and provided by Pay Governance, LLC (“Pay Governance”), the Personnel Committee’s independent compensation consultant;Governance;
Both•both utility and general industry data to determine total cashdirect compensation (base salary, annual, and annuallong-term incentive) for non-industry specific roles; and
Data•data from utility companies to determine total cashdirect compensation for management roles that are utility-specific, such as Group President, Utility Operations; andOperations.
Utility market data to determine long-term incentives for all positions.
➢ How the PersonnelTalent and Compensation Committee Uses the Market Data
The PersonnelTalent and Compensation Committee uses this survey data to develop compensation opportunities that are designed to deliver total targetdirect compensation within a targeted range of approximately the 50th percentile of the surveyed companies in the aggregate. In most cases, the committee considers its objectives to have been met if Entergy Corporation’s Chief Executive Officer and the eight other executive officers (including the applicable Named Executive Officers) who constitute the Office of the Chief Executive each has a target compensation opportunity that falls within a targeted range of 85% - 115% of the 50th percentile of the survey data. In general, compensation levels for an executive officer who is new to a position tend to be atcloser to the lower end25th percentile of the competitive range,surveyed companies, while seasoned executive officers with strong performance whowhose experience and skill set are viewed as critical to retain wouldmay be positioned at or somewhat above the higher end of the competitive range. Generally, differences in the levels of total direct compensation among the Named Executive Officers are primarily driven by the scope of their responsibilities, differences in the competitive market pay range for similar positions and considerations of internal pay equity.median.
➢ Proxy Peer Group
Although the survey data described above areis the primary data used in benchmarking compensation, the committee usesTalent and Compensation Committee used compensation information from the companies included in the Philadelphia Utility Index to evaluate the overall reasonableness of Entergy Corporation’sthe Company’s compensation programs and to determine relative total shareholder returnTSR performance levels for the 2017-2019 Long-Term Performance Unit Program awards. Companies2022 – 2024 PUP performance period. The Talent and Compensation Committee identified the Philadelphia Utility Index as the appropriate industry peer group for determining relative TSR performance levels because the companies included in this index, in the aggregate, are viewed as comparable to the Company in terms of business and scale.
The Talent and Compensation Committee approved the 2022 compensation model and framework based on compensation information from the companies included in the Philadelphia Utility Index at the time the proxy data was compiled were as follows:of December 31, 2021, which were:
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Ÿ | AES Corporation | ŸConsolidated Edison Inc. | El Paso Electric Co.Eversource Energy | Public Service Enterprise Group, Inc. |
Ÿ | Ameren Corporation | ŸDominion Energy | Eversource EnergyExelon Corporation | Southern Company |
Ÿ | American Electric Power Co. Inc. | ŸDTE Energy Company | ExelonFirstEnergy Corporation | WEC Energy, Inc. |
Ÿ | American Water Works Company, Inc. | ŸDuke Energy Corporation | FirstEnergy CorporationNextEra Energy, Inc. | Xcel Energy, Inc. |
Ÿ | CenterPoint Energy Inc. | Ÿ | NextEra Energy, Inc. |
Ÿ | Consolidated Edison Inc. | Ÿ | PG&E Corporation |
Ÿ | Dominion Energy | Ÿ | Public Service Enterprise Group, Inc. |
Ÿ | DTE Energy Company | Ÿ | Southern Company |
Ÿ | Duke Energy Corporation | Ÿ | Xcel Energy, Inc. |
Ÿ | Edison International | Pinnacle West Capital Corporation | |
2022 Compensation ElementsStructure and Incentive Metrics
The following table summarizes the elements of total direct compensation (“TDC”) granted or paid toIn 2022, the executive officers under the 2019 executive compensation programs. The programs use a mixconsisted of fixedbase salary and variable compensation elements and are designed to provide alignment with both short- and long-term business goals through annual and long-term incentives. An executive officer’s TDC is based primarily on corporate performance, market-based compensation levels and individual performance with each of these elements reviewed annually for each Named Executive Officer.incentives as outlined in the table below:
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Compensation ComponentElement | Primary PurposeForm | Performance MeasuredObjective | Metrics/Performance Period |
Base Salary (Cash) | Cash | Provides a base level of competitive cash compensation for executive talent. | Experience, job scope, market data, individual performance and internal equity | AnnualN/A |
Annual Incentive (Cash)Awards | Cash | Motivates and rewards executives for performance on both key financial and operational measures during the year.year; incentivizes behaviors that serve the Company’s four stakeholders - customers, employees, communities, and owners. | • | ETR Tax Adjusted EPS ETR Adjusted Operating Cash Flow
| 1 year |
Long-Term Performance Unit Program (Equity)• | FocusesSafety |
| • | Customer NPS |
| • | DIB |
| • | Environmental Stewardship |
| Measured over a one-year period |
| PUP Awards | Equity | Provides market competitive compensation that retains skills and knowledge while increasing our executives’ ownership in the Company further enhancing their focus on driving continuous improvement in operational results to the benefit of all stakeholders. Designed to focus our executives on growing earnings anddriving utility growth, building long-term shareholder value, and increases the executives’ ownership in Entergy Corporation common stock.a strong balance sheet. | • | Relative total shareholder returnCumulative ETR Adjusted EPS
| 3 yearsTSR |
Stock Options (Equity)• | Align interests of executives with long-term shareholder value, provide competitive compensation, and increase the executives’ ownership in Entergy Corporation’s common stock. | Stock price, job scope, market data, and individual performance | 3 yearsAdjusted FFO/Debt Ratio |
Restricted
Measured over a 3-year performance period |
Stock (Equity)Options | Equity | Enhances management’s focus on driving continuous improvement in operational results to the benefit of all stakeholders. Aligns interests of executivesmanagement with long-term shareholder value, provides market competitive compensation, retains executive talent, and increases the executives’management’s ownership in Entergy Corporation’s common stock.the Company. | Service-based with 3-year pro rata vesting |
Restricted Stock price, job scope, | Equity | Enhances management’s focus on driving continuous improvement in operational results to the benefit of all stakeholders. Provides market data,competitive compensation, retains talent, and individual performance
increases management’s ownership in the Company. | 3 yearsService-based with 3-year pro rata vesting |
Fixed2022 Compensation Decisions
Base Salary
The Personnel Committee determines salary for each NEO is based on the base salaries for alloutcome of an annual merit review, the Named Executive Officersneed to retain an experienced team, job promotion, individual performance, scope of responsibility, leadership skills and values, current compensation, and internal equity. For the NEOs who are members of the OfficeOCE, the Talent and Compensation Committee also considers the results of the Chief Executive based on competitiveannual market assessment of OCE compensation data, performance considerations, and advice as
provided by the committee’sits independent compensation consultant. ForThe Talent and Compensation Committee considers changes in the other Named Executive Officers, their salaries are established by their immediate supervisors using the same criteria. The base salaries of the Named Executive Officers are consideredNEOs at least annually, as part of the performance review process, and upon a Named Executive Officer’s promotion or other change in job responsibilities. In 2019, in 2022, all of the Named Executive Officers,NEOs, other than Mr. Denault, received merit increases in their base salaries ranging from approximately 2.5%2.99% to 4.5%. In 2019,5.2% effective April 1, 2022. Mr. Denault did not receive a merit increase in April 2022 as the Talent and Compensation Committee believed that his base salary. Instead, the Personnel Committee increasedsalary was generally consistent with market levels for comparably situated executives. In connection with their November 2022 promotions, Mr. Denault’s TDC by increasing his annual and long-term incentive target opportunities; thus, increasing the share of his compensation that is “at risk.” The increases inMarsh’s base salary increased from $732,021 to $1,100,000 and Ms. Fontan’s base salary increased from $369,850 to $625,000. These adjustments were based onmade after considering the competitive market data previously discussed in this CD&A under “What Entergy Corporation Paysdescribed above as well as their previous compensation levels and Why.”the compensation paid to their predecessors.
The following table sets forth the 20182021 and 20192022 year-end base salaries for the Named Executive Officers. ChangesNEOs. Except as indicated above, changes in base salaries for 20192022 were effective in April.
| Named Executive Officer(1) | | Named Executive Officer(1) | | 2021 Base Salary | | 2022 Base Salary |
| A. Christopher Bakken III | | A. Christopher Bakken III | | $693,911 | | $714,728 |
| | Named Executive Officer | | 2018 Base Salary | | 2019 Base Salary | |
| A. Christopher Bakken, III | | $638,125 | | $654,078 | |
| Marcus V. Brown | | $650,000 | | $666,250 | |
| Leo P. Denault | | $1,260,000 | | $1,260,000 | Leo P. Denault | | $1,300,000 | | $1,300,000 |
| David D. Ellis | | $305,000 | | $313,388 | |
| Haley R. Fisackerly | | $365,959 | | $376,023 | Haley R. Fisackerly | | $399,891 | | $414,840 |
| Kimberly A. Fontan | | Kimberly A. Fontan | | $358,000 | | $625,000 |
| Laura R. Landreaux | | $308,000 | | $316,470 | Laura R. Landreaux | | $380,000 | | $394,204 |
| Andrew S. Marsh | | $622,000 | | $650,000 | Andrew S. Marsh | | $710,700 | | $1,100,000 |
| Phillip R. May, Jr. | | $381,550 | | $392,043 | Phillip R. May, Jr. | | $416,928 | | $435,643 |
| Sallie T. Rainer | | $338,123 | | $347,422 | |
| Deanna D. Rodriguez | | Deanna D. Rodriguez | | $330,000 | | $347,172 |
| Eliecer Viamontes | | Eliecer Viamontes | | $340,000 | | $350,154 |
| Roderick K. West | | $696,598 | | $714,013 | Roderick K. West | | $753,819 | | $776,434 |
Variable Compensation(1)The compensation levels for each of these officers were determined using competitive compensation data provided by Pay Governance.
Short-TermAnnual Incentive Compensation
AnnualThe NEOs are eligible for annual incentive awards under our 2019 Omnibus Incentive Plan (“2019 OIP”). The maximum funding available for the annual incentive awards is determined by the EAM performance measure. At the beginning of each year, after a review of the Company’s strategic plan, the Talent and Compensation Committee engages in a rigorous process to determine the financial, strategic, and operational measures and the targets for each measure that will be used to determine the EAM. The Talent and Compensation Committee also annually establishes target opportunities for each NEO who is a member of the OCE. For the other NEOs, 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. Accordingly, their respective incentive award opportunities differ from one another based on either their management level or the external market data developed by Pay Governance. At December 31, 2022, Mr. Fisackerly, Ms. Landreaux, Mr. May, Ms. Rodriguez, and Mr. Viamontes were promoted from ML level 4 to ML level 3 positions. In 2022, the target opportunities (as a percentage of base salary) for Ms. Fontan, Mr. Fisackerly, Ms. Landreaux, Mr. Marsh, Ms. Rodriguez, and Mr. Viamontes were increased in conjunction with their promotions during the year as follows: from 40% to 55% for Mr. Fisackerly; from 60% to 75% for Ms. Fontan; from 40% to 55% for Ms. Landreaux; from 85% to 120% for Mr. Marsh; from 40% to 50% for Ms. Rodriguez; and from 40% to 55% for Mr. Viamontes. These adjustments were made after considering the competitive market data described above as well as their previous compensation levels. The target opportunities for the other NEOs in 2022 remained at the same level as those established for 2021.
Awards underIn January, after the Executive Annual Incentive Plan,end of the fiscal year, the Finance and Talent and Compensation Committees jointly review the Company’s results, and the Talent and Compensation Committee determines the EAM based on the level of achievement of the performance measures established. The Talent and Compensation Committee retains
discretion to modify the EAM based on its assessment of the degree of management’s success in achieving the Company’s strategic objectives and overcoming any challenges that occurred during the year.
Individual executive officer awards are determined based on the Talent and Compensation Committee’s or Annual Incentive Plan, are tied to Entergy Corporation’smanagement’s consideration of each executive’s role in executing the Company’s strategies and delivering the financial and operational performance throughachieved, but also the individual’s accountability for any challenges and achievements the Company experienced during the year.
2022 Performance Measures and Methodology
For 2022 and consistent with the 2021 program design, the Talent and Compensation Committee decided that the EAM which iswould be based on both financial and non-financial measures, with the financial measure weighted 60% and four non-financial measures each weighted at 10%. Targets and ranges of performance were established for each of the measures, with no payout for results less than the designated minimum, a 25% payout opportunity for results at the minimum, a 100% payout opportunity for results at target, and a 200% payout opportunity for results equal to or exceeding the maximum. Payout opportunities for results between the minimum and maximum performance achievement levels were determined by straight line interpolation, with the EAM result being determined by the weighted average of the payout opportunities for each of the performance metric used to determinemeasures.
Financial Measure and Target
For the maximum funding available for awards underEAM financial measure, the plan. Entergy Corporation uses the following process to determine annual incentive awards:
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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:
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◦ | Take into account changes in the business environment and specific challenges facing Entergy Corporation; |
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◦ | Reflect an appropriate balancing of the various risks and opportunities recognized at the time the targets are set; and |
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◦ | Are aligned with external expectations communicated to Entergy Corporation’s shareholders. |
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• | 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.
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• | 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.
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• | 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.
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2019 Targets
Using the process described above, in December 2018, the PersonnelTalent and Compensation Committee decided to use ETR Tax Adjusted EPS and ETR Adjusted Operating Cash Flow, with eachEPS. This measure weighted equally, as the performance measures for determining the 2019 EAM pool. ETR Tax Adjusted EPS is based on ETR Adjusted EPS, which is the primary earnings measure used by which the Company externally and the measure on which it provides annual earningsexternal guidance, which is then adjusted to add back the net effect (positive or negative) of any significant tax strategy items that were excluded to arrive at ETR Adjusted EPS and to eliminate the effect of: (i) major storms, including the impact on total debt of pending securitizations, (ii) resolutions during the year of certain unresolved regulatory litigation matters, (iii) unrealized gains or losses on equity securities, (iv) effects ifof federal income tax law changes, and (v) any ofadjustments to contributions to pension investments or trusts related to post-retirement benefits that are elective and deviate from original plan assumptions (collectively, the Pre-Determined Exclusions. 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.“Pre-Determined Exclusions”). The PersonnelTalent and Compensation Committee determined that target performance for this metric would equal management’s expectation for ETR Adjusted EPS as reflected in its financial plan, or $6.30 per share, with minimum performance determined to be $6.00 per share and maximum performance being $6.60 per share.
ETR Tax Adjusted EPS and ETR Adjusted Operating Cash Flow werewas used as the appropriate metrics to usefinancial measure for this purposethe EAM because:
They are•It is based on an objective financial measuresmeasure that Entergy Corporationthe Company and its investors consider to be important in evaluating its financial performance;performance.
They are•It is based on the same metrics we usemeasure used for internal and external financial reporting; andreporting.
They provide•It provides both discipline and transparency.
The PersonnelTalent and Compensation Committee considered it appropriate to use ETR Tax Adjusted EPS, which adds back the net effect of significant tax strategy items that may have been excluded from ETR Adjusted EPS, as the earnings measure because of the significant financial benefits to Entergy Corporationthe Company resulting from such tax strategy items and the management effort required to achieve them.
The Personnel Committeecommittee also considered, both at the time it chose ETR Tax Adjusted EPS as the EAM financial measure and when it established the targets for this measure, the appropriateness of excluding the effect of each of the specific Pre-Determined Exclusions it had identified from each of the financial measures.measure. It viewed the exclusion of major storms as appropriate because although Entergy Corporationthe Company includes estimates for storm costs in its financial plan, it does not include estimates for a major storm event, such as a hurricane.hurricane, given management’s inability to control or predict acts of nature. The PersonnelTalent and Compensation Committee considered the exclusion of the effects of any unanticipated effects of thechanges in federal income tax reform legislation adopted at the end of 2017law to be appropriate because of the lingering uncertainty around those effects and the inability of management to impact those results. It approved the exclusion of elective adjustments to Company contributions to pension and post-
retirement benefit plan trusts because such elective adjustments are not reflective of the underlying performance of the business. The PersonnelTalent and Compensation Committee approved the other exclusionsPre-Determined Exclusions from reported results -— for the impact of certain legacy unresolved regulatory litigation and unanticipated unrealized gains and losses on securities held by Entergy Corporation’s nuclear decommissioning trusts -— primarily because of management’s inability to influence either of the related outcomes.
ESG Measures and Targets
To demonstrate Entergy’s strong commitment to creating long-term sustainable value for its key stakeholders - customers, communities, employees, and owners - and to link executive compensation to successful execution on those strategies to achieve those objectives, the Talent and Compensation Committee decided to use the measures described below beginning in 2021 to collectively determine 40% of the EAM, with each of the measures weighted at 10%. These measures were selected because the committee considered them to represent key measures of the Company’s success in advancing strategies to create sustainable value for its stakeholders that may not be fully captured in its quarterly and annual financial results.
Following is a summary description of each of these measures, including the metric or methodology used for determining the level of achievement and the rationale for each of the selected measures:
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| Measure | Metrics and Targets | Objective |
| Safety | Quantitative safety metric based on rate of serious injuries and fatalities per 100 employees or contractors (SIF rate). Minimum performance = second quartile, target = top quartile, and maximum performance = top decile of published EEI member SIF rate data as published in 2022, with no payout if any fatalities during the reporting year. | Ensures Entergy maintains a safe and incident-free workplace for all of its employees and contractors. |
| Customer Net Promoter Score (NPS) | Quantitative customer NPS metric is determined through a blind survey of residential customers who are asked how likely they are to recommend Entergy, on a scale of 1 to 10.The NPS is the percentage of promoters (scores 9-10) less the percentage of detractors (scores less than 6). Minimum performance = 5, target = 12, and maximum performance = 19. | • | Incentivizes actions that drive positive customer outcomes (as measured through customer feedback) including impacts on reliability improvements, responsiveness, continuous improvement, and innovation. |
| • | Signals overall health and loyalty of our customer relationship. |
| Diversity, Inclusion & Belonging (DIB) | Overall qualitative assessment of DIB key performance indicators assessed in the workforce, workplace, and marketplace, informed by quantitative measures in the areas of increases in female, racially, and ethnically diverse representation, female, racially, and ethnically diverse director and above placements, inclusive climate survey scores, and diverse supplier managed spend; progress on DIB initiatives; and responsiveness to emergent issues. | • | Reinforces Entergy’s commitment to be a fair and equitable work environment that is welcoming to all and allows us to attract and retain superb talent, allowing the Company to execute on its strategy. |
| • | Rewards progress toward meeting Entergy’s commitment to develop and retain a workforce that reflects the rich diversity of the communities the Company serves. |
| • | Drives an engaged workforce; customer-centric service and solutions; enhancement of owner value; and community partnerships. |
| Environmental Stewardship | Assessment of progress toward environmental commitments through performance on publicly announced goals and other key initiatives. Goals set for 2022 included CO2 emission rate and other air pollutant emission targets, overall progress towards interim climate goals and net zero by 2050 climate commitments, execution of renewables projects in various stages of development, publication of a TCFD-aligned climate report, developing an accelerated resilience plan, identifying and implementing customer decarbonization solutions, and progress on other planned environmental initiatives. | • | Reinforces Entergy’s commitment to long-term sustainability and a reduced impact on the environment, in particular by advancing Entergy’s climate goals and commitments. |
| • | Provides accountability for accelerating completion of Entergy’s resilience investments and advancing Entergy’s customer electrification initiatives. |
In determining the targets to set for 2019,2022, the PersonnelTalent and Compensation Committee reviewed anticipated drivers and risks to the Company’s expectations for consolidated operationalits adjusted earnings per share and consolidated operational operating cash flow for 20192022 as set forth in Entergy Corporation’sthe Company’s financial plan, as well as factors driving the strong financial performance achieved in 2018.2021. The PersonnelTalent and Compensation Committee confirmed that the proposed plan targets for ETR Tax Adjusted EPS and ETR Adjusted Operating Cash Flow reflected substantialsignificant growth in the
core weather-adjusted utility earnings and consolidated operating cash flow measuresmeasure underlying the annual incentive plan targets.target. The PersonnelTalent and Compensation Committee also considered the potential impact of a wide range of identified risks and opportunities and confirmed that there appeared to be more downside risk than upside opportunity embedded inboth the financial plan targets and as a result, the Personnel Committee believed that the relatednon-financial annual incentive plan targets reflected a reasonable balancing of such risks and opportunities and an appropriate degree of challenge. The goals were designed to be achievable, but also to require the strong coordinated performance of the management team.
20192022 Performance Assessment
The following table shows the 2019 Incentive Plan targets established by the Personnel Committee and 2019 results:
Annual Incentive Plan Targets and Results
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| | Weight | Minimum | Target | Maximum | 2019 Results |
ETR Tax Adjusted EPS ($)(2) | 50% | $4.77 | $5.30 | $5.83 | $6.53 |
ETR Adjusted Operating Cash Flow ($ billions)(2) | 50% | $2.650 | $3.100 | $3.550 | $2.966 |
| EAM as % of Target | | 25% | 100% | 200% | 139% |
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(1) | Payouts for performance between minimum and target achievement levels and between target and maximum achievement levels are calculated using straight-line interpolation. There is no payout for performance below the minimum achievement level. |
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(2) | ETR Tax Adjusted Earnings Per Share is a different measure than the consolidated operational earnings per share, and ETR Adjusted Operating Cash Flow is a different measure than the consolidated operational operating cash flow used to determine the 2018 annual incentive awards. As a result, the goals and results are not comparable year over year. |
In January 2020,2023 the Finance and PersonnelTalent and Compensation Committees jointly reviewed Entergy Corporation’sthe Company’s financial and operational results and assessed management’s performance against the performance objectives reflectedand targets described above in order to determine the EAM. The following table above. Managementsummarizes the annual incentive targets and performance results for 2022, resulting in an EAM of 145%:
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| Performance Measure | Targets and Results |
| Weighting | Minimum | Target | Maximum | 2022 Results | Level of Achievement |
| ETR Tax Adjusted EPS ($) | 60% | 6.00 | 6.30 | 6.60 | 6.58 | 195% |
| Safety (SIF Rate) | 10% | 0.07 | 0.03 | 0.00 | 0.06(1) | 44% |
| Customer Net Promoter Score | 10% | 5.00 | 12.00 | 19.00 | 5.60 | 31% |
| Diversity, Inclusion, & Belonging | 10% | Qualitative assessment(2) | 90% |
| Environmental Stewardship | 10% | Qualitative assessment(2) | 119% |
| EAM | 100% | 25% | 100% | 200% | | 145% |
(1)2022 SIF results were 0.05 for employees and 0.07 for contractors. The employee and contractor targets and results were averaged to arrive at target and reported results. The 2022 target was top quartile employee SIF performance among electric utilities for 2022, as reported by the Edison Electric Institute (EEI), the maximum was top decile performance, and the minimum was 2nd quartile performance.
(2)This qualitative assessment is informed by quantitative measures and is discussed withbelow.
In assessing 2022 financial performance, the committees Entergy Corporation’sFinance and Talent and Compensation Committees reviewed various factors explaining how the 2022 ETR Tax Adjusted EPS and ETR Adjusted Operating Cash Flow results for 2019, including primary factors explaining how those resultsresult compared to the 20192022 business plan and Annual Incentive Plan targetsannual incentive target set in January 2019.2022. ETR Tax Adjusted EPS exceeded Entergy Corporation’sthe ETR Tax Adjusted EPS target of $5.30$6.30 per share by $1.23, but management fell short of achieving its$0.28. This outperformance resulted in part from the fact that ETR Adjusted Operating Cash Flow target of $3.1 billion by approximately $134 million, leading to a calculated EAM of 139%. NoneEPS exceeded the midpoint of the Pre-Determined Exclusions resulted in any adjustment toguidance set at the beginning of the year by $0.12 per share. The ETR Tax Adjusted EPS andresult also reflected a positive adjustment of $0.21 to ETR Adjusted Operating Cash Flow.EPS for 50% of the net benefit of tax strategy items impacting net income which had been excluded from ETR Adjusted EPS, as well as a negative adjustment of $0.05 to reflect the expense accrual that would be associated with funding the calculated EAM.
In assessing management’s 2022 performance on the non-financial measures, the committees focused particularly on the qualitative assessments required with respect to the Diversity, Inclusion, & Belonging and Environmental Stewardship measures. In each area, the committees reviewed a wide range of quantitative and qualitative key performance indicators and assessed progress on strategies and initiatives that had been identified at the beginning of the performance period as key to achieving the Company’s strategic objectives.
Following are selected performance milestones and highlights considered as part of the assessment:
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| Performance Measure | 2022 Developments |
| Diversity, Inclusion, & Belonging | • | Increased representation of women and underrepresented racial and ethnic groups in employee population and at director level and above in management from 2021 |
| Level of Achievement | • | Piloted “All In”, a 5-month/100-person cohort development experience to build inclusive leadership capabilities at all levels |
| • | 90% | • | Launched “Amplify”, a 6-month learning journey bringing together top female leaders with racially and ethnically diverse women to foster relationships, allyship, development, and skill building |
| | • | Entergy’s Employee Resource Groups (ERGs) placed 6th in the Enterprise-Wide ERG category of the Diversity Impact Awards during the 2022 Global ERG Summit |
| | • | Received for the 5th consecutive year the U.S. Department of Labor Platinum Vets Medallion Award for veteran talent pipeline development, recruitment, retention, and a veteran's ERG |
| | • | Diverse supplier managed spend fell from 2021 levels, driven by decreases in storm and non-recurring diverse spend |
| | • | Inclusive climate score remained flat |
| Environmental Stewardship | • | Utility equity CO2 emission rate fell short of our 2022 goal of 617 lbs/MWh with an estimated emission rate of 695 lbs/MWh, largely due to higher natural gas prices resulting in more dispatch of our coal generation by the Midcontinent Independence System Operator (MISO) as compared to 2021 in addition to supporting reliability during extreme weather events (e.g. Winter Storm Elliott in the fourth quarter 2022) |
| Level of Achievement | • | Developed and announced a new interim climate goal to achieve 50% carbon-free energy capacity by 2030 |
| • | 119% | • | Continued progress on advancing green tariff solutions for the benefit of customers |
| | • | Advanced renewable capacity requirements through the request for proposals (both owned and power purchase agreements), development, and construction processes, with just over 800 MW of renewables in service, 1,100 MW of active projects, and active solar and wind requests for proposals totaling 7,000 MW |
| | • | Progress on studies of and engagements with various low- and zero-carbon technologies including advanced nuclear, offshore wind, energy storage, and hydrogen |
| | • | Published second TCFD-aligned climate report providing updated information on our path to achieve net zero emissions by 2050 |
| | • | Developed and announced an accelerated resilience plan and began related regulatory filings |
| | • | Increased engagement with many of our industrial and commercial customers to identify opportunities to provide decarbonization solutions |
In addition to the foregoing financial and operational results, the PersonnelTalent and Compensation Committee considered management’s degree of success in achieving various strategic operational and regulatory goals set out at the beginning of the yearobjectives and in overcoming certain challenges that arose in the business during the course of the year. The Personnel Committee also considered (i)
Under the Entergy Corporation’s degree of success in achieving its published earnings guidance, which it exceeded by $0.10 per share at the midpointannual incentive program, NEOs could earn a payout ranging from 0% to 200% of the original guidance range for ETR Adjusted EPS provided at the beginning of the year and by $0.05 per share at the midpoint of the adjusted guidance range published in July 2019, and (ii) total shareholder return for 2019 in relationNEO’s target opportunity, subject to the Philadelphia Utility Index, which placed Entergy Corporation inoverall funding limitation determined by the top quartile of companies in the index with a total shareholder return of 44.3% for the year. Finally, the committee reviewed the impact on ETR Tax Adjusted EPS and ETR Adjusted Operating Cash Flow of significant tax items that were included in the results and additional pension contributions made during the year beyond those that were required or included in the initial 2019 financial plan. Following this review, the Personnel Committee decided to approve the EAM as calculated in accordance with the plan design.
EAM. To determine individual executive officerNEO annual incentive awards under the Annual Incentive Plan for the Named Executive Officers who are members of the Office ofOCE, the Chief Executive, the PersonnelTalent and Compensation Committee considered not only each executive’s roleindividual performance in executing on Entergy Corporation’sthe Company’s strategies and delivering the strong financial performance and operational successes achieved in 2018, but2022, as well as the executive’s success in achieving individual goals within the executive’s scope of responsibilities. The committee also considered certain challenges the individual’s accountability for certain operational and regulatory challenges itCompany experienced during the year. year, particularly in relation to regulatory and customer relationships and each officer’s accountabilities and accomplishments in addressing those external challenges. With respect to Mr. Marsh and Ms. Fontan, the committee approved awards that were prorated based on the period of time served in each of the two positions held
by the officer during 2022, the target opportunities for each such position, and the committee’s assessment of the officer’s performance in each such position.
With these considerations in mind, the committee exercised negative discretionTalent and Compensation Committee approved the following annual incentive payouts to determine individual awards that ranged from 135% to 137% of target for each of the Named Executive OfficersNEOs who are members of the OfficeOCE ranging from 125% to 144% of the Chief Executive, with the extent of the negative discretion applied varying based on the executive’s specific accountabilities and accomplishments. target.
After the EAM was established to determine overall funding for the Annual Incentive Plan, Entergy Corporation’sannual incentive awards, Entergy’s Chief Executive Officer allocated incentive award funding to individual business units based on business unit results.Individual awards were determined for the remaining Named Executive OfficersNEOs who are not members of the Office of the Chief ExecutiveOCE by their immediate supervisor based on the individual officer’s key accountabilities, accomplishments, and performance.This resulted in payouts that ranged from 127%from 125% of target to 208%140% of targettarget for the Named Executive OfficersNEOs who are not members of the Office of the Chief Executive.OCE.
Based on the foregoing evaluation of management performance, the Named Executive OfficersNEOs received the following Annual Incentive Plan payoutsannual incentive payouts:
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| Named Executive Officer | Year-End Base Salary | Target as Percentage of Year-End Base Salary | 2022 Target Award(1) | Payout as Percentage of Target | 2022 Annual
Incentive Award |
| A. Christopher Bakken, III | $714,728 | 75% | $536,046 | 130% | $696,860 |
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| Leo P. Denault | $1,300,000 | 140% | $1,820,000 | 130% | $2,366,000 |
| Haley R. Fisackerly | $414,840 | 55% | $228,162 | 140% | $319,427 |
| Kimberly A. Fontan | $625,000 | 75% | $263,050 | 144% | $379,688 |
| Laura R. Landreaux | $394,204 | 55% | $216,812 | 125% | $271,015 |
| Andrew S. Marsh | $1,100,000 | 120% | $739,000 | 130% | $960,700 |
| Phillip R. May, Jr. | $435,643 | 60% | $261,386 | 125% | $326,732 |
| Deanna D. Rodriguez | $347,172 | 50% | $173,586 | 125% | $217,320 |
| Eliecer Viamontes | $350,154 | 55% | $192,584 | 125% | $240,731 |
| Roderick K. West | $776,434 | 80% | $621,147 | 125% | $776,434 |
(1)Based on performance against the performance measures, the NEOs could earn a payout ranging from 0%-200% of their target opportunity. For Mr. Marsh and Ms. Fontan, the payout is stated as a percentage of the officer’s prorated incentive target, which was determined based on the period of time served in each of the positions held by such officer during the year and the base salary and target percentage for 2019:each such position.
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| Named Executive Officer | Base Salary | Target as Percentage of Base Salary | Payout as Percentage of Target | 2019 Annual Incentive Award |
| A. Christopher Bakken, III | $654,078 | 70% | 135% | $618,104 |
| Marcus V. Brown | $666,250 | 75% | 137% | $684,573 |
| Leo P. Denault | $1,260,000 | 140% | 137% | $2,416,680 |
| David D. Ellis | $313,388 | 40% | 127% | $159,804 |
| Haley R. Fisackerly | $376,023 | 40% | 183% | $274,570 |
| Laura R. Landreaux | $316,470 | 40% | 208% | $263,523 |
| Andrew S. Marsh | $650,000 | 80% | 137% | $712,400 |
| Phillip R. May, Jr. | $392,043 | 60% | 173% | $407,922 |
| Sallie T. Rainer | $347,422 | 40% | 158% | $219,069 |
| Roderick K. West | $714,013 | 70% | 135% | $674,742 |
Long-Term Incentive Compensation
Overview
Long-term incentive compensation consisting solelydelivered in shares of equity awards in 2019,Entergy common stock represents the largest portion of the Named Executive Officers’executive officer compensation. Entergy Corporation’sThe Company believes the combination of long-term incentives we employ acts init employs provides a compelling performance-based compensation opportunity, is effective at retaining thea strong senior management team, and aligns the interests of the executive officers
with the interests of Entergy Corporation’sEntergy’s customers and shareholders and customers by enhancing executives’ focus on the Company’s long-term goals. In general, Entergy Corporation seeks to allocate the total value of long-term incentive compensation 60% to performance units and 40% to a combination of stock options and restricted stock, equally divided in value, based on the value the compensation model seeks to deliver. Awards for individual Named Executive Officers may vary from this target as a result of individual performance, promotions, and internal pay equity.
2019 Long-Term Incentive Award Mix
Beginning in 2019,For each NEO, a dollar value wasis established for the targetto determine that NEO’s long-term incentive awards for each Named Executive Officer who is a member of the Office of the Chief Executive.awards. The targeted award value for these officers waseach NEO is determined based on market median compensation data for the officer’s role, adjusted to reflect individual performance and internal equity. Previously, the targets for these Named Executive Officers were the average of the market data for the officers within a specific management level, without regard to the officer’s specific job functions. In January 2019,2022 the PersonnelTalent and Compensation Committee approved the 20192022 long-term incentive award target valuesamounts for the Named Executive Officers who are memberseach NEO. This amount for each NEO was then
converted into the number of performance units, stock options, and shares of restricted stock granted using the allocation described aboveto each NEO based on the target grant date value.
In consultation with Entergy Corporation’s Chief Executive Officer, the Personnel Committee reviews eachan allocation of the other Named Executive Officer’s60% performance role and responsibilities, strengths, developmental opportunities and internal equity and allocates awards of restricted stock andunits, 20% stock options, to each of these officers based on these factors. Grants of long-term performance unitsand 20% restricted stock.
| | | | | |
| NEO | Long-Term Incentive
Grant Date Value
(As of January 27, 2022) |
| A. Christopher Bakken, III | $1,559,364 |
| |
| Leo P. Denault | $9,164,589 |
Haley R. Fisackerly(1) | $324,655 |
Kimberly A. Fontan(1) | $417,562 |
Laura R. Landreaux(1) | $324,655 |
Andrew S. Marsh(1) | $2,147,041 |
| Phillip R. May, Jr. | $628,377 |
Deanna D. Rodriguez(1) | $250,602 |
Eliecer Viamontes(1) | $277,544 |
| Roderick K. West | $2,084,696 |
(1)The amounts reported in the above table for these Named Executive Officers wasMr. Fisackerly, Ms. Fontan, Ms. Landreaux, Mr. Marsh, Ms. Rodriguez, and Mr. Viamontes were determined based on the averageand are reflective of the market datatheir pre-promotion positions. Mses. Fontan, Landreaux, and Rodriguez and Messrs. Fisackerly, Marsh, and Viamontes each experienced a change in officer status in 2022, and accordingly, their target PUP award opportunities were increased for the officers within a specific management level, without regard2022 – 2024 performance period as follows: from 1,483 to the officer’s specific job function.1,510 for Mr. Fisackerly; from 1,908 to 5,302 for Ms. Fontan; from 1,483 to 1,769 for Ms. Landreaux; from 9,810 to 23,118 for Mr. Marsh; from 1,145 to 1,254 for Ms. Rodriguez; and from 1,268 to 1,577 for Mr. Viamontes.
2022 Long-Term Incentive Award Mix
Long-Term Performance Unit ProgramUnits
The Named Executive OfficersNEOs are issued performance unit awards under the Long-Term Performance Unit Program.
Each performance unit represents one share of Entergy Corporation’s common stockPUP with payout opportunities established by the Talent and Compensation Committee at the endbeginning of theeach 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.
The Long-Term Performance Unit ProgramPUP specifies a minimum, target, and maximum achievementperformance level, the achievement of which will determinedetermines the number of performance units that may be earned by each participant. For the 2019 - 20212022 – 2024 PUP performance period, the PersonnelTalent and Compensation Committee chose the performance measures and targets set forth below.
Givenbelow, which were the economic and market conditions atsame measures as used in the time the targets were set, the target payout level for the Cumulative ETR Adjusted EPS goal was designed to be challenging, but achievable while payout at the maximum levels was designed to require stretch performance.
2021-2023 PUP performance period.
2019-2021 Long-Term
2022-2024 PUP Performance Unit Performance PeriodPeriod: Measures and Goals(1)
|
| | | | | | | |
Performance Measures(1) | Long-Term Performance PUP
Measure Weight | PayoutGoals(2) |
Relative Total Shareholder ReturnTSR | 80% | Minimum (25%) - Bottom of 3rd Quartile Target (100%) - Median Percentile Maximum (200%) - Top Quartile |
Cumulative ETR Adjusted EPS($)FFO/Debt Ratio(3) | 20% | Minimum (25%) - Minus 10% of Target 14.0%
Target (100%) - 100% of Target 15.0%
Maximum (200%) - Plus 10% of Target 16.5% |
| |
(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. |
(1)Payouts for performance between achievement levels are calculated using straight-line interpolation, between minimum and target and between target and maximum, with no payouts for performance below the minimum achievement level with respect to the applicable performance measure, and payouts are capped at the maximum achievement level with respect to the applicable performance measure.
(2)No payout if the relative TSR falls within the lowest quartile of the peer companies in the Philadelphia Utility Index and the Adjusted FFO/Debt Ratio is below the minimum performance goal.
(3)Results for the Adjusted FFO/Debt Ratio will exclude the Pre-Determined Exclusions.
Performance Measures
Total Shareholder ReturnRelative TSR:
•The PersonnelTalent and Compensation Committee chose relative total shareholder returnTSR as a performance measure because it reflects Entergy Corporation’sthe Company’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 returnEntergy’s TSR in relation to the TSR of the companies in the Philadelphia Utility Index. The PersonnelTalent and Compensation Committee identified the Philadelphia Utility Index as the appropriate industry peer group for determining relative total shareholder returnTSR because the companies included in this index, in the aggregate, are deemed to beviewed as comparable to the Company in terms of business and scale.
Cumulative ETR Adjusted EPSFFO/Debt Ratio:
Cumulative ETR•To emphasize the importance of strong credit for the long-term health of our business, for the 2022 – 2024 PUP performance period we used the credit measure – Adjusted EPS, which adjustsFFO/Debt Ratio.
•The Adjusted FFO/Debt Ratio is the ratio of: (i) adjusted funds from operations calculated as operating cash flow adjusted for allowance for funds used during construction, working capital and the effects of securitization revenue, and the Pre-Determined Exclusions; to (ii) total debt, excluding outstanding or pending securitization debt.
•The Talent and Compensation Committee decided to use this ratio because it emphasizes financial stability, noting that a financially healthy utility creates the capacity to make investments on behalf of customers, addresses the needs of our communities, provides low-cost access to capital markets, and promotes employee confidence.
•To further underscore the importance of this measure, for the 2022 – 2024 performance period, the calculated PUP result, determined as set forth above, will be adjusted by ±10 basis points for a change in Entergy Corporation’s as reported (GAAP) results to eliminatecorporate credit outlook and ±20 basis points for an upgrade or downgrade in the impact of earningscorporate credit rating for Entergy Corporation. The maximum increase or lossdecrease from Entergy Wholesale Commoditiesadjustments made under this modifier is 20 basis points, 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.may not be reduced below zero or increased beyond 200%.
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.
Stock Options and Restricted Stock
Entergy CorporationThe Company grants stock options and shares of restricted stock as part of its long-term incentive award mix because they alignit aligns the interests of the executive officers with long-term shareholder value, provideprovides competitive compensation, and increaseincreases the executives’ ownership in Entergy CorporationEntergy’s common stock. Generally, stock options are granted with a maximum term of ten years and vest one-third on each of the first three anniversaries of the date of grant. The exercise price for each option granted in 2019January 2022 was $89.19,$109.59, which was the closing price of Entergy’s common stock on the date of grant. Shares of restricted stock vest one-third on each of the first three anniversaries of the date of grant, are paid dividends which are
reinvested in shares of Entergy stock and have the ability to vote.full voting rights. The dividend reinvestment shares are subject to forfeiture similar to the terms of the original grant.
2022 Long-Term Incentive Awards
In January 2019,2022 the PersonnelTalent and Compensation Committee granted the following long-termPUP performance units, stock options and shares of restricted stock to each Named Executive Officer. NEO. In connection with their promotions during 2022 and as provided for by their initial grant letters and based on the competitive market data described above, Mr. Fisackerly, Ms. Fontan, Ms. Landreaux, Mr. Marsh, Ms. Rodriguez, and Mr. Viamontes each received a pro-rated upward adjustment in the number of target performance units awarded, for the performance periods that were open at the time of their promotion, including the 2022-2024 PUP performance period. For the 2022-2024 PUP performance period, the targeted PUP units were increased as follows: from 1,483 to 1,510 for Mr. Fisackerly; from 1,908 to 5,302 for Ms. Fontan; from 1,483 to 1,769 for Ms. Landreaux; 9,810 to 23,118 for Mr. Marsh; from 1,145 to 1,254 for Ms. Rodriguez; and from 1,268 to 1,577 for Mr. Viamontes. The number of long-term performance units, stock options and shares of restricted stock were determined as discussed above under “Long-Term Incentive Compensation - 2019 Long-Term Incentive Award Mix.– Overview.”
| | | | | | | | | | | |
| Named Executive Officer | 2022 – 2024 Target PUP Units | Stock Options | Shares of
Restricted Stock |
| A. Christopher Bakken, III | 7,125 | 18,505 | 2,831 |
| | | |
| Leo P. Denault | 41,874 | 108,762 | 16,638 |
| Haley R. Fisackerly | 1,483 | 3,852 | 590 |
| Kimberly A. Fontan | 1,908 | 4,955 | 758 |
| Laura R. Landreaux | 1,483 | 3,852 | 590 |
| Andrew S. Marsh | 9,810 | 25,480 | 3,898 |
| Phillip R. May, Jr. | 2,871 | 7,457 | 1,141 |
| Deanna D. Rodriguez | 1,145 | 2,974 | 455 |
| Eliecer Viamontes | 1,268 | 3,294 | 504 |
| Roderick K. West | 9,525 | 24,740 | 3,785 |
|
| | | |
| Named Executive Officer | 2019-2021 Target Long-Term Performance Units | Stock Options | Shares of Restricted Stock |
| A. Christopher Bakken, III | 9,568 | 36,421 | 3,604 |
| Marcus V. Brown | 9,383 | 35,719 | 3,535 |
| Leo P. Denault | 40,508 | 154,206 | 15,259 |
| David D. Ellis | 1,450 | 4,700 | 500 |
| Haley R. Fisackerly | 1,450 | 6,200 | 600 |
| Laura R. Landreaux | 1,450 | 5,100 | 500 |
| Andrew S. Marsh | 11,869 | 45,182 | 4,471 |
| Phillip R. May, Jr. | 2,150 | 9,300 | 900 |
| Sallie T. Rainer | 1,450 | 6,200 | 600 |
| Roderick K. West | 10,073 | 38,346 | 3,795 |
All of the outstanding performance units, and all of the shares of restricted stock, and stock options granted to the Named Executive Officersour NEOs in 20192022 were granted pursuant to the 2015 Equity Ownership Plan or 2015 Equity Plan.2019 OIP. The 2015 Equity Plan2019 OIP requires both a change in control and an involuntary job loss without cause or substantial diminution of dutiesa resignation by the NEO for good reason within 24 months following a change in control (a “double trigger”) for the acceleration of these awards upon a change in control.
2019 Long-Term Performance Unit Program Payouts
PayoutPayouts for the 2017-2019 Long-Term2020 – 2022 PUP Performance Unit Program Period
In December 2019 the Talent and Compensation Committee chose relative TSR and Cumulative ETR Adjusted EPS as the performance measures for the 2020 – 2022 PUP performance period, with relative TSR weighted 80% and Cumulative ETR Adjusted EPS weighted 20%. ForCumulative ETR Adjusted EPS, which adjusts Entergy’s as reported (GAAP) results to eliminate the 2017-2019impact of Entergy Wholesale Commodities and other non-routine items, was selected in 2019 as a performance measure because the committee wished to incentivize management to achieve steady, predictable earnings growth for the Company over the three-year performance period, and because it aligns with the Personnel Committee chose relative total shareholder return asearnings measure being used to communicate the Company’s earnings expectations externally to investors. Similar to the way targets are established for the annual incentive awards, targets for the Cumulative ETR Adjusted EPS performance measure withwere established by the Talent and Compensation Committee after the Board’s review of the Company’s strategic plan. These targets also exclude 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 payout subject towas determined based on the achievement of the following:following performance goals established for both performance measures by the committee at the beginning of the performance period:
2017-2019 Long-Term2020 – 2022 PUP Performance Unit Program Period MeasuresPeriod: Measure and Goals(1)
|
| | | | | | | |
Performance Measure(1) | PUP
Measure Weight | Minimum | Target | MaximumPayout |
Relative Total Shareholder ReturnTSR | 4th Quartile80% | Minimum (25%) - Bottom of 3rd3rd Quartile | Target (100%) - Median Percentile | Maximum (200%) - Top Quartile |
PayoutCumulative ETR Adjusted EPS ($)(2) | No Payout20% | Minimum Payout of 25% of (25%) - 16.07
Target | 100% of Target | 200% of Target (100%) - 17.85
Maximum (200%) - 19.63 |
| |
(1) | Payouts for performance between achievement levels are calculated using straight-line interpolation, with no payouts for performance below the minimum achievement level. |
(1)Payouts for performance between achievement levels are calculated using straight-line interpolation. There is no payout for performance below the minimum achievement level and payouts are capped for performance at or above the maximum performance level.
(2)EPS targets were established to drive multi-year key growth measures consistent with those that were externally communicated to investors at the time.
In January 2020,2023 the PersonnelTalent and Compensation Committee reviewed the Company’s total shareholder returnrelative TSR and the Cumulative ETR Adjusted EPS for the 2017 - 20192020 – 2022 PUP performance period in order to determine the payout to participants. The committee compared Entergy Corporation’s total shareholder return against the total shareholder return of the companies that comprise the Philadelphia Utility Index, withparticipants based upon the performance measures and range of potential payouts for the 2017 - 20192020 – 2022 PUP performance period as provided above. The committee compared the Company’s TSR against the TSR of the companies that were included in the Philadelphia Utility Index as of the last day of the year preceding the three-year performance period, which were:
| | | | | | | | | | | |
| AES Corporation | | Edison International |
| Ameren Corporation | | Eversource Energy |
| American Electric Power Co. Inc. | | Exelon Corporation |
| American Water Works Company, Inc. | | FirstEnergy Corporation |
| CenterPoint Energy Inc. | | NextEra Energy, Inc. |
| Consolidated Edison Inc. | | PG&E Corporation |
| Dominion Energy | | Public Service Enterprise Group, Inc. |
| DTE Energy Company | | Southern Company |
| Duke Energy Corporation | | Xcel Energy, Inc. |
As recommended by the Finance Committee, the PersonnelTalent and Compensation Committee
concluded that the Company’sEntergy Corporation’s relative total shareholder returnTSR for the 2017 - 20192020 – 2022 PUP performance period was in the topfourth quartile, and that Cumulative ETR Adjusted EPS was $18.46, yielding a payout of 200%27% of target for the Named Executive Officers.NEOs.
| | | | | | | | | | | | | | |
| Named Executive Officer | 2020 - 2022 Target PUP Performance Units | Number of Shares Issued(1) | Value of Shares Actually Issued(2) | Grant Date Fair Value(3) |
| A. Christopher Bakken, III | 7,758 | 2,312 | $248,748 | $1,257,851 |
| | | | |
| Leo P. Denault | 31,263 | 9,318 | $1,002,524 | $5,068,858 |
Haley R. Fisackerly(4) | 1,013 | 300 | $32,277 | $164,244 |
Kimberly A. Fontan(4) | 1,588 | 468 | $50,352 | $257,472 |
Laura R. Landreaux(4) | 1,013 | 300 | $32,277 | $164,244 |
Andrew S. Marsh(4) | 10,222 | 3,029 | $325,890 | $1,657,354 |
| Phillip R. May, Jr. | 1,400 | 417 | $44,865 | $226,990 |
Deanna D. Rodriguez(4) | 564 | 159 | $17,107 | $91,445 |
Eliecer Viamontes(4) | 986 | 291 | $31,309 | $159,866 |
| Roderick K. West | 8,401 | 2,503 | $269,298 | $1,362,105 |
(1)Includes accrued dividends.
(2)Value determined based on the closing price of Entergy Corporation common stock on January 18, 2023 ($107.59), the date the Talent and Compensation Committee certified the 2020 – 2022 performance period results.
(3)Represents the aggregate grant date fair value calculated in accordance with applicable accounting rules as reflected in the 2020 Summary Compensation Table in the Form 10-K filed for the year ended December 31, 2020, except for NEOs whose target award opportunities were increased in 2022, as discussed in footnote 4.
(4)Mses. Fontan, Landreaux, and Rodriguez and Messrs. Fisackerly, Marsh, and Viamontes each experienced a change in officer status in 2022, and accordingly, their target award opportunities were increased for the 2020 – 2022 performance period as follows: from 9,560 to 10,222 for Mr. Marsh; from 1,400 to 1,588 for Ms. Fontan; from 950 to 1,013 for Mr. Fisackerly; from 950 to 1,013 for Ms. Landreaux; from 501 to 564 for Ms. Rodriguez; and from 924 to 986 for Mr. Viamontes.
|
| | | | |
| Named Executive Officer | 2017-2019 Target | Number of Shares Issued(1) | Value of Shares Actually Issued(2) | Grant Date Fair Value(3) |
| A. Christopher Bakken, III | 8,300 | 18,088 | $2,284,695 | $592,620 |
| Marcus V. Brown | 8,300 | 18,088 | $2,284,695 | $592,620 |
| Leo P. Denault | 48,700 | 106,131 | $13,405,407 | $3,477,180 |
David D. Ellis(4) | 617 | 1,271 | $160,540 | $44,054 |
| Haley R. Fisackerly | 1,850 | 4,031 | $509,156 | $132,090 |
Laura R. Landreaux(5) | 925 | 1,934 | $244,284 | $66,045 |
| Andrew S. Marsh | 8,300 | 18,088 | $2,284,695 | $592,620 |
| Phillip R. May, Jr. | 3,150 | 6,864 | $866,992 | $224,910 |
| Sallie T. Rainer | 1,850 | 4,031 | $509,156 | $132,090 |
| Roderick K. West | 8,300 | 18,088 | $2,284,695 | $592,620 |
| |
(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. |
Benefits and Perquisites
Entergy Corporation’s Named Executive OfficersThe NEOs are eligible to participate in or receive the following benefits:
|
| | | | |
| Plan Type | Description |
| Retirement Plans | Entergy Corporation-sponsored:
Entergy Retirement Plan - a tax-qualified final average pay defined benefit pension plan that covers a broad group of employees hired before July 1, 2014. Cash Balance Plan - a tax-qualified cash balance defined benefit pension plan that covers a broad group of employees hired on or after July 1, 2014.2014 and before January 1, 2021. Pension Equalization Plan (PEP) - a non-qualified pension restoration plan for a select group of management orcertain highly compensated non-bargaining employees who participate in the Entergy Retirement Plan. Cash Balance Equalization Plan (CBEP) - a non-qualified restoration plan for a select group of management orcertain highly compensated non-bargaining employees who participate in the Cash Balance Plan. System Executive Retirement Plan (SERP) - a non-qualified supplemental retirement plan for a select group of individuals who became executive officers before July 1, 2014.
See “2019“2022 Pension Benefits” for additional information regarding the operation of the plans described above. |
| Savings Plan | Entergy Corporation-sponsored 401(k) Savings Plan that covers a broad group of employees.employees and provides for an employer matching contribution. |
| Health & Welfare Benefits | Medical, dental and vision coverage, health care and dependent care reimbursement plans, life and accidental death and dismemberment insurance, business travel accident insurance, and basic long-term disability insurance.
Eligibility, coverage levels, potential employee contributions, and other plan design features are the same for the Named Executive OfficersNEOs as for the broad employee population.
|
20192022 Perquisites | Corporate aircraft usage and annual mandatory physical exams, relocation assistance, and event tickets.exams. The Named Executive OfficesNEOs who are members of the Office of the Chief ExecutiveOCE do not receive tax gross ups on any benefits, except for relocation assistance.
Named Executive OfficersIn 2022, the NEOs who are not members of the Office of the Chief ExecutiveOCE also were provided in 2019 with club dues, relocation assistance, and tax gross up payments on somethese perquisites.
For additional information regarding perquisites, see the “All Other Compensation” column in the 20192022 Summary Compensation Table. |
| Deferred Compensation | The Named Executive OfficersNEOs are eligible to defer up to 100% of their base salary and Annual Incentive Planannual incentive awards into the Entergy Corporation sponsored Executive Deferred Compensation Plan. |
| Executive Disability Plan | EligibleThis plan pays eligible individuals who becomea supplemental long-term disability (LTD) benefit if they are disabled and receiving LTD benefits from the broad-based LTD Plan. The benefit payable under the terms of thethis plan are eligible foris equal to 65% of the difference between their annual base salary and $276,923 (i.e. the annual base salary that produces the maximum $15,000 monthly disability payment under the general long-term disability plan).our broad-based LTD plan, which is $15,000. |
Entergy Corporation provides these benefits to the Named Executive OfficersNEOs as part of its effort to provide a competitive executive compensation program and because it believes that these benefits are important retention and recruitment tools since many of the companies with which it competes for executive talent provide similar arrangements to their senior executive officers.
Severance and Other CompensationRetention Arrangements
System Executive Continuity Plan
The PersonnelTalent and Compensation Committee believes that retention and transitional compensation arrangements are an important part of overall compensation as they help to secure the continued employment and dedication of the Named Executive Officers,NEOs, notwithstanding any concern that they might have at the time of a change in control regarding their own continued employment. In addition, the PersonnelTalent and Compensation Committee believes that these arrangements are important as recruitment and retention devices, as many of the companies with which Entergy Corporation competes for executive talent have similar arrangements in place for their senior employees.
To achieve these objectives, Entergy Corporation has established a System Executive Continuity Plan (“Continuity Plan”) under which ML 1-4 Officers areeach of our NEOs, with the exception of Mr. Denault, is entitled to receive “change in control” payments and benefits if such officer’s employment is involuntarily terminated without cause or if the officer resigns for good reason, in each case, in connection with a change in control of the Company. Mr. Denault became ineligible to participate in or receive any benefits under the Continuity Plan, effective November 1, 2022, pursuant to his resignation as CEO of Entergy. Entergy Corporation and its subsidiaries. Entergy Corporation strives to ensure that the benefits and payment levels under the System Executive Continuity Plan are consistent with market practices. Entergy Corporation’sEntergy’s executive officers, including the Named Executive Officers,NEOs, are not entitled to any tax gross up payments on any severance benefits received under this plan. For more information regarding the System Executive Continuity Plan,our severance arrangements, see “2019 Potential“Potential Payments Upon Termination or Change in Control.”
In certain cases, the Personnel Committee may approve the execution of a retention agreement with an individual executive officer. These decisions are made on a case by case basis to reflect specific retention needs or other factors, including market practice. If a retention agreement is entered into with an individual officer, the committee considers the economic value associated with that agreement in making overall compensation decisions for that officer.
Mr. Ellis
In connection with the commencement of his employment as President, Entergy New Orleans, Mr. Ellis was eligible for certain relocation benefits pursuant to Entergy Corporation’s Relocation Assistance Policy, including assistance with moving expenses, transportation of household goods and assistance with the sale of his home. Mr. Ellis also received a sign-on bonus of $200,000 when he assumed this role. Mr. Ellis’s sign-on bonus and certain of his relocation benefits are subject to forfeiture under certain circumstances if Mr. Ellis’s employment is terminated within 24 months of the commencement of his employment. Also, in accordance with the terms of the Long-Term Performance Unit Program in January 2019, Mr. Ellis received pro-rated target award opportunities for the 2017-2019 and 2018-2020 performance periods.
Nuclear Retention Plan
Mr. Bakken participates in the Nuclear Retention Plan, a retention plan for officers and other leaders with expertise in the nuclear industry. The PersonnelTalent and Compensation Committee authorized this plan to attract and retain key management and employee talent in the nuclear power field, a field that requires unique technical and other expertise that is in great demand in the utility industry. Participation in the plan is limited to regular full-time employees of Entergy Nuclear Operations, Inc. recommended to, and approved for participation by, the CEO of Nuclear Operations and to employees of other Entergy System Companies approved for participation in the plan by the Talent and Compensation Committee or the CEO of Entergy. The plan provides for bonuses to be paid annually over a three-year service period with the bonus opportunity dependent on the participant’s management level and continued employment. Each annual payment is equal to an amount ranging from 15% to 30% of the employee’s base salary as of their date of enrollment in the plan. Mr. Bakken’s participation in theThis plan commenced in May 2016, and indoes not provide for accelerated or prorated payouts upon termination of employment.
In accordance with the terms and conditions of the plan, in May 2017, 2018 and 2019,2022, Mr. Bakken received a cash bonus equal to $181,500$196,223 or 30% of $654,078, his base salary as of May 1, 20162019. In recognition of the value the Company places on Mr. Bakken as a member of the Company’s senior management team and his extensive experience in the nuclear industry, and to keep his pay competitive, in May 2022, Mr. Bakken’s participation in the plan was renewed for another three-year period beginning on May 1, 2022. Subject to the terms and conditions of the Nuclear Retention Plan, in 2023, 2024 and 2025, Mr. Bakken is expected to be eligible to receive a cash bonus equal to $214,418, which is 30% of $714,728, his base salary. Thissalary as of May 1, 2022.The three-year period covered and percentage of base salary paid to Mr. Bakken under the plan doesare consistent with the terms of participation of other senior executive officers who participate in this plan.
Restricted Stock Units
Restricted stock units granted under our 2019 OIP represent shares of our common stock that have an economic value equivalent to one share of our common stock. Entergy Corporation occasionally grants restricted stock units for retention purposes, to offset forfeited compensation from a previous employer or for other limited purposes. If all conditions of the grant are satisfied, restrictions on the restricted stock units lift at the end of the restricted period and the restricted stock units are settled in shares of Entergy common stock. Restricted stock units
are generally time-based awards for which restrictions generally lift on the third anniversary of the grant date, subject to continued satisfactory employment.
In November 2022 the Talent and Compensation Committee granted Mr. West 18,012 restricted stock units. Mr. West’s award was made in recognition of his senior leadership role and direction as the Company’s Group President, Utility Operations and to retain his deep knowledge of the utility industry and the Company’s utilities gained through his experience as Group President and his other senior management positions with the Company through the Company’s management succession process. Mr. West’s restricted stock units are scheduled to vest in three equal installments on June 1, 2024, 2025 and 2026, provided he satisfies the vesting criteria through each such date, including remaining continuously employed as Group President, Utility Operations or in a higher position, performing his job duties in a satisfactory manner, and actively preparing for the successful transition of his role, determined in the sole discretion of the CEO of Entergy Corporation. All of Mr. West’s restricted stock units will vest immediately if the Company experiences a change in control (as defined in the 2019 OIP) and (x) the outstanding restricted stock units are not provideassumed or substituted in accordance with the 2019 OIP, or (y) the outstanding restricted stock units are so assumed or substituted and Mr. West’s employment is terminated by his Entergy System Company employer without cause or by Mr. West for acceleratedgood reason within 24 months after the change in control.
Additionally, in November 2022 the Talent and Compensation Committee granted to each of Messrs. Fisackerly and May 4,053 restricted stock units, all of which will vest on October 1, 2025, provided they satisfy the vesting criteria through such date, including remaining continuously employed in their current positions or prorated payout upon terminationhigher positions, performing their job duties in a satisfactory manner, and actively preparing for the successful transition of any kind.their roles, determined in the sole discretion of the CEO of Entergy Corporation. These awards were made to Messrs. Fisackerly and May in recognition of their senior leadership roles as President and Chief Executive Officer of Entergy Mississippi, LLC and of Entergy Louisiana, LLC, respectively, and to retain their deep industry knowledge of the utility industry and the Mississippi and Louisiana service territories. All of the restricted stock units awarded to Messrs. Fisackerly and May will vest immediately if the Company experiences a change in control (as defined in the 2019 OIP) and (x) the outstanding restricted stock units are not assumed or substituted in accordance with the 2019 OIP, or (y) the outstanding restricted stock units are so assumed or substituted and their employment is terminated by their respective Entergy System Company employers without cause or by them for good reason within 24 months after the change in control.
Compensation PoliciesRisk Mitigation and Other Pay Practices
Entergy Corporation strives to ensure that its compensation philosophy and practices are in line with the best practices of companies in its industry as well as other companies in the S&P 500. Some of these practices include the following:
Policy for Recoupment of Compensation (Clawback Provisions)
Clawback Provisions
Entergy Corporation has adopted aUnder the Company’s policy regarding recoupment of certain compensation or, its clawback policy, that covers all individualsthe Company will seek reimbursement of certain compensation from current or former executive officers subject to Section 16, including all of the Exchange Act, including the members of the Office of the Chief Executive. Under the policy, which goes beyond the requirements of Sarbanes-Oxley Act of 2002 (Sarbanes-Oxley), the Personnel Committee will require reimbursement of incentives paid to these executive officersNEOs, where:
(i) a.the payment was predicated upon the achievement of certainCompany is required to restate its financial results with respect to the applicable performance period that were subsequently determined to be the subject of a material restatement other than a restatementstatements due to changes in accounting policy;noncompliance with any financial reporting requirement under securities laws; or (ii)
b.there is a material miscalculation of a performance award occurs,measure related to incentive compensation, regardless of whether or not the Company’s financial statements were restated and, in either such case, a lower payment would have been madeare restated.
In addition, the Company may seek reimbursement of certain compensation from current or former executive officers subject to Section 16, including all of the executive officer based upon the restated financial results or correct calculation; or
inNEOs, if the Board of Directors’ view, thedetermines that an executive officer engaged in fraud that caused or partially caused the need forresulted in either a restatement of the Company’s financial statements or caused a material miscalculation of a performance award, in each case, whether or not the financial statements were restated.measure relative to incentive compensation.
The Company’s clawback policy applies to incentive compensation, including cash or equity-based bonus or incentive or profit sharing awards paid during the three year period leading up to the date the Company is required to prepare such restatement or during the three-year period preceding the material miscalculation. The amount the Personnel Committee requiresrequired to be reimbursed is equal to the excess of the gross incentive payment actually made over the gross payment that would have been made if the original payment had been determined based on the restated financial results or correct calculation. Further, following a material restatementThe Company may enforce all or part of Entergy Corporation’s financial statements, Entergy Corporationany executive officer’s repayment obligation under the policy by reducing any amounts that may be owing from time-to-time by the Company or any of its subsidiaries to such individual, whether as wages, severance, vacation pay or in the form of any other benefit or for any other reason. In addition, we will seek to recover any compensation received by Entergy Corporation’s Chief Executive Officer and Chief Financial Officer that is required to be reimbursed under Sarbanes-Oxley.the Sarbanes-Oxley Act of 2002 following a material restatement of our financial statements.
The Company is reviewing its clawback policy in light of the rules recently adopted by the SEC and effective in January 2023 directing the NYSE to adopt certain requirements for listed companies relating to clawback policies and will make any changes that it determines to be necessary or appropriate to comply with the updated NYSE listing standards.
Stock Ownership Guidelines and Share Retention Requirements
For many years, Entergy Corporation has hadrequires their NEOs to own Entergy stock ownership guidelines for executives, including the Named Executive Officers. These guidelines are designed to further align the executives’ long-term financialtheir interests with the interests of Entergy Corporation’s shareholders.Entergy’s shareholders’ interests. Annually, the PersonnelTalent and Compensation Committee monitors the executive officers’ compliance with these guidelines.
guidelines with all of the NEOs satisfying the applicable ownership guidelines at the time of the annual review. The ownership guidelines are as follows:
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| | | | |
| Role | Value of Common Stock to be Owned |
| Chief Executive Officer | 6 timesx base salary |
| Executive Vice Presidents | 3 timesx base salary |
| Senior Vice Presidents | 2 timesx base salary |
| Vice Presidents | 1 timex base salary |
Further, to facilitate compliance with the guidelines, until an executive officer satisfies the stock ownership guidelines, the officer must retain:
•all net after-tax shares paid out under the Long-Term Performance Unit Program;PUP;
•all net after-tax shares of theour restricted stock and all net after-tax shares received upon the vesting of restricted stock units received upon vesting;units; and
•at least 75% of the after-tax net shares received upon the exercise of Entergy Corporation stock options.
Trading Controls
Executive officers, including the Named Executive Officers,NEOs, are required to receive permission from Entergy Corporation’sthe Company’s General Counsel or his designee prior to entering into any transaction involving Entergy CorporationCompany securities, including gifts, other than thean exercise of employee stock options.options that is not funded through a sale in the market. Trading is generally permitted only during specified open trading windows beginning shortly after the release of earnings. Employees who are subject to trading restrictions, including the Named Executive Officers,NEOs, may enter into trading plans under Rule 10b5-1 of the Exchange Act, but these trading plans or any amendment to an existing plan may be entered into only during an open trading window and must be approved by Entergy Corporation. The Named Executive Officer bears full responsibility if he or she violates Entergy Corporation’s policy by buying or selling sharesthe Company.
No Hedging/Pledging
Entergy Corporation also prohibits directors and executive officers, including the Named Executive Officers,NEOs, from pledging any Entergy Corporation securities or entering into margin accounts involving Entergy Corporation securities. Entergy Corporation prohibits these transactions because of the potential that sales of Entergy Corporation securities could occur outside trading periods and without the required approval of the General Counsel.
In addition, Entergy Corporation also has adopted an anti-hedging policy that prohibits officers, directors and employeesexecutive officers, including the NEOs, from entering intoengaging in any hedging or monetization transactions involving Entergy Corporation’s common stock. Prohibited transactions include, without limitation, zero-cost collars, forward sale contracts, purchase or sale of options, puts, calls, straddles or equity swaps or other derivatives that are directly linkedwith respect to Entergy Corporation’s stock or transactions involving “short-sales” of its common stock. The Board adopted this policy to require officers, directors, and employees to continue to own Entergy Corporation stock with the full risks and rewards of ownership, thereby ensuring continued alignment of their objectives with those of Entergy Corporation’s other shareholders.securities.
How Entergy Corporation Makes Compensation Decisions
The Personnel Committee oversees Entergy Corporation’s executive compensation programs and policies with the advice of its independent compensation consultant and support from its management team.
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| | | |
Personnel Committee | Ÿ | The Personnel Committee is responsible for the review and approval of all aspects of Entergy Corporation’s executive compensation programs. |
Ÿ | Among its duties, the Personnel Committee is responsible for approving the compensation for all members of the Office of Chief Executive, including: |
| Ÿ | Annual review of the compensation elements and mix of elements for the following year; |
| Ÿ | Annual review and approval of incentive program design, goals and objectives for alignment with Entergy Corporation’s compensation and business strategies; |
| Ÿ | Evaluation of Entergy Corporation and individual performance results in light of these goals and objectives; |
| Ÿ | Evaluation of the competitiveness of each executive officer’s total compensation package; |
| Ÿ | Approval of any changes to the officers’ compensation, including but not limited to, base salary, annual and long-term incentive award opportunities, and retention programs; |
| Ÿ | Evaluation of the performance of Entergy Corporation’s Chairman and Chief Executive Officer; and |
| Ÿ | Reporting, at least annually, to the Board on succession planning. |
Ÿ | The Personnel Committee has the sole authority to hire its compensation consultant, approve its compensation, determine the nature and scope of its services, evaluate its performance and terminate its engagement. |
Management | Ÿ | The CEO and Chief Human Resources Officer work closely with the Personnel Committee in managing the executive compensation programs and attend meetings of the Personnel Committee. During 2019, Mr. Denault attended 8 meetings of the Personnel Committee. |
Ÿ | The CEO makes recommendations to the Committee regarding compensation for executive officers other than himself. |
Independent Compensation Consultant | Ÿ | During 2019, Pay Governance assisted the Personnel Committee with its responsibilities related to Entergy Corporation’s executive compensation programs. |
Ÿ | Pay Governance: |
| Ÿ | Regularly attended meetings of the committee; |
| Ÿ | Conducted studies of competitive compensation practices; |
| Ÿ | Identified Entergy Corporation’s market surveys and proxy peer group; |
| Ÿ | Provided updates on executive compensation trends and regulatory developments; |
| Ÿ | Reviewed base salary, annual incentives and long-term incentive compensation opportunities relative to competitive practices; and |
| Ÿ | Developed conclusions and recommendations related to Entergy Corporation’s executive compensation programs for consideration by the committee. |
Compensation Consultant Independence
To maintain the independence of the Personnel Committee’s compensation consultant, the Board has adopted a policy that any consultant (including its affiliates) retained by the Board of Directors or any committee of the Board of Directors to provide advice or recommendations on the amount or form of executive or director compensation should not be retained by Entergy Corporation or any of its affiliates to provide other services in an aggregate amount that exceeds $120,000 in any year. Pay Governance, which serves as the Personnel Committee’s compensation consultant, did not provide any services to management in 2019.
Annually, the PersonnelTalent and Compensation Committee reviews the relationship with its compensation consultant including services provided, qualityto determine whether any conflicts of those services,interest exist that would prevent Pay Governance from independently advising the Talent and fees associatedCompensation Committee. When assessing the independence of its compensation consultant in 2022, the committee considered the following factors, among others:
•Pay Governance has policies in place to prevent conflicts of interest;
•No member of Pay Governance’s consulting team serving the committee has a business relationship with services in its evaluationany member of the compensation consultant’s independence. committee or any of Entergy Corporation’s executive officers;
•Neither Pay Governance nor any of its principals own any shares of Entergy Corporation’s common stock; and
•The committee also assessesamount of fees paid to Pay Governance is less than 1% of Pay Governance’s independence undertotal consulting income.
Based on these factors, the Talent and Compensation Committee concluded that Pay Governance is independent in accordance with SEC and NYSE rules and has concluded that no conflicts of interest exist that would prevent Pay Governance from independently advising the Personnel Committee.committee.
In addition, Pay Governance has agreed that it will not accept any engagement with management without prior approval from the Talent and Compensation Committee, and Entergy Corporation’s Board has adopted a policy that prohibits a compensation consultant from providing other services to it if the aggregate amount for those services would exceed $120,000 in any year. During 2022, Pay Governance did not provide any services to Entergy Corporation other than the services it performed on behalf of the Talent and Compensation and Corporate Governance Committees, and it worked with Entergy Corporation’s management only as directed by those committees. PERSONNEL
TALENT AND COMPENSATION COMMITTEE REPORT
The PersonnelTalent and Compensation Committee Report included in the 2023 Entergy Corporation Proxy Statement is incorporated by reference, but will not be deemed to be “filed” in this Annual Report on Form 10-K. None of the Registrant Subsidiaries has a compensation committee or other board committee performing equivalent functions. The board of directors of each of the Registrant Subsidiaries is comprised of individuals who are officers or employees of Entergy Corporation or one of the Registrant Subsidiaries. These boards do not make determinations regarding the compensation paid to executive officers of the Registrant Subsidiaries.
EXECUTIVE COMPENSATION TABLES
20192022 Summary Compensation TablesTable
The following table summarizes the total compensation paid or earned by each of the Named Executive OfficersNEOs for the fiscal year ended December 31, 2019,2022, and to the extent required by SEC executive compensation disclosure rules, the fiscal years ended December 31, 20182021 and 2017.2020. For information on the principal positions held by each of the Named Executive Officers,NEOs, see Item 10, “Directors, Executive Officers, and Corporate Governance of the Registrants.”
The compensation set forth in the table represents the aggregate compensation paid by all Entergy System companies. For additional information regarding the material terms of the awards reported in the following tables,table, including a general description of the formula or criteria to be applied in determining the amounts payable, see “Compensation Discussion and Analysis.”
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (a) | (b) | (c) | (d) | (e) | (f) | (g) | (h) | (i) | (j) | (k) |
Name and Principal Position (1) | Year | Salary (2) | Bonus (3) | Stock Awards (4) | Option Awards (5) | Non-Equity Incentive Plan Compen-sation (6) | Change in Pension Value and Non-qualified Deferred Compen-sation Earnings (7) | All Other Compen-sation (8) | Total | Total Without Change in Pension Value (9) |
| A. Christopher Bakken, III | 2022 | $709,123 | | $196,223 | | $1,258,658 | | $300,706 | | $696,860 | | $88,200 | | $119,704 | | $3,369,474 | | $3,281,274 | |
| Executive Vice President, Entergy | 2021 | $688,635 | | $196,223 | | $1,375,489 | | $298,517 | | $702,585 | | $89,300 | | $91,589 | | $3,442,338 | | $3,353,038 | |
| Infrastructure - | 2020 | $693,819 | | $196,223 | | $1,666,710 | | $335,245 | | $581,066 | | $115,100 | | $85,846 | | $3,674,009 | | $3,558,909 | |
| Entergy Corp. | | | | | | | | | | |
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| Leo P. Denault | 2022 | $1,300,000 | | $— | | $7,397,206 | | $1,767,383 | | $2,366,000 | | $— | | $376,766 | | $13,207,355 | | $13,207,355 | |
| Former Chairman of | 2021 | $1,289,538 | | $— | | $7,383,591 | | $1,602,462 | | $2,457,000 | | $4,178,300 | | $134,853 | | $17,045,744 | | $12,867,444 | |
| the Board and CEO - | 2020 | $1,308,462 | | $— | | $6,716,017 | | $1,350,986 | | $2,116,800 | | $4,416,700 | | $289,632 | | $16,198,597 | | $11,781,897 | |
| Entergy Corp. | | | | | | | | | | |
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| Haley R. Fisackerly | 2022 | $410,557 | | $— | | $752,209 | | $62,595 | | $319,427 | | $— | | $46,281 | | $1,591,069 | | $1,591,069 | |
| CEO - Entergy | 2021 | $396,604 | | $— | | $231,921 | | $50,319 | | $216,186 | | $190,000 | | $41,723 | | $1,126,753 | | $936,753 | |
| Mississippi | 2020 | $384,848 | | $— | | $252,819 | | $49,235 | | $232,737 | | $836,200 | | $48,101 | | $1,803,940 | | $967,740 | |
| | | | | | | | | | |
| Kimberly A. Fontan | 2022 | $404,809 | | $— | | $1,034,293 | | $80,519 | | $379,688 | | $— | | $29,720 | | $1,929,029 | | $1,929,029 | |
| Executive Vice | | | | | | | | | | |
| President and CFO - | | | | | | | | | | |
| Entergy Corp., | | | | | | | | | | |
| Entergy Arkansas, | | | | | | | | | | |
| Entergy Louisiana, | | | | | | | | | | |
| Entergy Mississippi, | | | | | | | | | | |
| Entergy New | | | | | | | | | | |
| Orleans, | | | | | | | | | | |
| Entergy Texas | | | | | | | | | | |
| | | | | | | | | | |
| Laura R. Landreaux | 2022 | $390,161 | | $— | | $341,381 | | $62,595 | | $271,015 | | $— | | $25,313 | | $1,090,465 | | $1,090,465 | |
| CEO - Entergy | 2021 | $350,660 | | $— | | $219,035 | | $47,522 | | $220,093 | | $125,000 | | $20,683 | | $982,993 | | $857,993 | |
| Arkansas | 2020 | $323,907 | | $— | | $252,819 | | $49,235 | | $167,153 | | $330,700 | | $26,698 | | $1,150,512 | | $819,812 | |
| | | | | | | | | | |
| Andrew S. Marsh | 2022 | $781,560 | | $— | | $4,598,890 | | $414,050 | | $960,700 | | $— | | $106,560 | | $6,861,760 | | $6,861,760 | |
| Chairman of the | 2021 | $705,286 | | $— | | $1,650,645 | | $358,235 | | $906,143 | | $213,000 | | $56,018 | | $3,889,327 | | $3,676,327 | |
| Board and CEO - | 2020 | $704,692 | | $— | | $2,053,717 | | $413,105 | | $703,800 | | $2,054,000 | | $77,741 | | $6,007,055 | | $3,953,055 | |
| Entergy Corp. | | | | | | | | | | |
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| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
Name and Principal Position (1) | | Year | | Salary (2) | | Bonus (3) | | Stock Awards (4) | | Option Awards (5) | | Non-Equity Incentive Plan Compen-sation (6) | | Change in Pension Value and Non-qualified Deferred Compen-sation Earnings (7) | |
All
Other
Compens-ation (8) | | Total |
| A. Christopher Bakken, III | | 2019 | |
| $649,507 |
| |
| $181,500 |
| |
| $1,273,399 |
| |
| $303,023 |
| |
| $618,104 |
| |
| $98,500 |
| |
| $62,407 |
| |
| $3,186,440 |
|
| Executive Vice President and | | 2018 | |
| $632,967 |
| |
| $181,500 |
| |
| $1,041,479 |
| |
| $283,095 |
| |
| $544,959 |
| |
| $108,700 |
| |
| $452,012 |
| |
| $3,244,712 |
|
| Chief Nuclear Officer of Entergy Corp. | | 2017 | |
| $615,791 |
| |
| $181,500 |
| |
| $959,376 |
| |
| $245,904 |
| |
| $559,973 |
| |
| $33,000 |
| |
| $114,494 |
| |
| $2,710,038 |
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| Marcus V. Brown | | 2019 | |
| $661,563 |
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| $— |
| |
| $1,248,839 |
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| $297,182 |
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| $684,573 |
| |
| $1,455,300 |
| |
| $69,955 |
| |
| $4,417,412 |
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| Executive Vice President and | | 2018 | |
| $644,231 |
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| $— |
| |
| $1,041,479 |
| |
| $283,095 |
| |
| $546,000 |
| |
| $371,800 |
| |
| $61,885 |
| |
| $2,948,490 |
|
| General Counsel of Entergy Corp. | | 2017 | |
| $622,788 |
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| $— |
| |
| $1,022,853 |
| |
| $287,760 |
| |
| $568,890 |
| |
| $1,217,200 |
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| $43,269 |
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| $3,762,760 |
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| Leo P. Denault | | 2019 | |
| $1,260,000 |
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| $— |
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| $5,391,253 |
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| $1,282,994 |
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| $2,416,680 |
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| $3,704,500 |
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| $208,822 |
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| $14,264,249 |
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| Chairman of the | | 2018 | |
| $1,251,346 |
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| $— |
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| $4,744,977 |
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| $1,168,029 |
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| $2,041,200 |
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| $982,800 |
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| $138,104 |
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| $10,326,456 |
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| Board and CEO - | | 2017 | |
| $1,221,346 |
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| $— |
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| $4,676,190 |
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| $1,173,276 |
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| $2,142,045 |
| |
| $3,819,500 |
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| $125,863 |
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| $13,158,220 |
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| Entergy Corp. | | | | | | | | | | | | | | | | | | |
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| David D. Ellis | | 2019 | |
| $311,004 |
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| $— |
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| $188,861 |
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| $39,104 |
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| $159,804 |
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| $18,000 |
| |
| $15,267 |
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| $732,040 |
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| CEO - Entergy | | 2018 | |
| $7,258 |
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| $200,000 |
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| $— |
| |
| $— |
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| $— |
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| $600 |
| |
| $35,308 |
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| $243,166 |
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| New Orleans | | | | | | | | | | | | | | | | | | |
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| Haley R. Fisackerly | | 2019 | |
| $373,313 |
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| $— |
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| $197,780 |
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| $51,584 |
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| $274,570 |
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| $644,700 |
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| $37,897 |
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| $1,579,844 |
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| CEO - Entergy | | 2018 | |
| $363,089 |
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| $— |
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| $198,449 |
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| $46,134 |
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| $172,000 |
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| $— |
| |
| $35,982 |
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| $815,654 |
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| Mississippi | | 2017 | |
| $354,451 |
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| $— |
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| $192,041 |
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| $49,704 |
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| $169,123 |
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| $406,300 |
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| $35,724 |
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| $1,207,343 |
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| Laura R. Landreaux | | 2019 | |
| $314,407 |
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| $— |
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| $188,861 |
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| $42,432 |
| |
| $263,523 |
| |
| $228,700 |
| |
| $26,536 |
| |
| $1,064,459 |
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| CEO - Entergy | | 2018 | |
| $246,136 |
| |
| $— |
| |
| $273,062 |
| |
| $— |
| |
| $124,000 |
| |
| $21,500 |
| |
| $10,741 |
| |
| $675,439 |
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| Arkansas | | | | | | | | | | | | | | | | | | |
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| (a) | (b) | (c) | (d) | (e) | (f) | (g) | (h) | (i) | (j) | (k) |
Name and Principal Position (1) | Year | Salary (2) | Bonus (3) | Stock Awards (4) | Option Awards (5) | Non-Equity Incentive Plan Compen-sation (6) | Change in Pension Value and Non-qualified Deferred Compen-sation Earnings (7) | All Other Compen-sation (8) | Total | Total Without Change in Pension Value (9) |
| Phillip R. May, Jr. | 2022 | $430,676 | | $— | | $957,246 | | $121,176 | | $326,732 | | $— | | $39,225 | | $1,875,055 | | $1,875,055 | |
| CEO - Entergy | 2021 | $413,752 | | $— | | $304,893 | | $66,160 | | $333,205 | | $2,000 | | $25,261 | | $1,145,271 | | $1,143,271 | |
| Louisiana | 2020 | $416,677 | | $— | | $371,882 | | $83,585 | | $284,881 | | $1,072,100 | | $28,836 | | $2,257,961 | | $1,185,861 | |
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| Deanna D. Rodriguez | 2022 | $342,565 | | $— | | $260,189 | | $48,328 | | $217,320 | | $— | | $27,087 | | $895,489 | | $895,489 | |
| CEO - Entergy | 2021 | $314,450 | | $— | | $339,833 | | $— | | $144,662 | | $144,900 | | $59,161 | | $1,003,006 | | $858,106 | |
| New Orleans | | | | | | | | | | |
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| Eliecer Viamontes | 2022 | $347,459 | | $— | | $296,861 | | $53,528 | | $240,731 | | $11,800 | | $168,309 | | $1,118,688 | | $1,106,888 | |
| CEO - Entergy | 2021 | $324,120 | | $— | | $245,000 | | $53,154 | | $134,793 | | $22,300 | | $102,190 | | $881,557 | | $859,257 | |
| Texas | | | | | | | | | | |
| | | | | | | | | | |
| Roderick K. West | 2022 | $770,432 | | $— | | $3,682,723 | | $402,025 | | $776,434 | | $— | | $101,107 | | $5,732,721 | | $5,732,721 | |
| Group President | 2021 | $748,087 | | $— | | $1,512,547 | | $328,247 | | $844,277 | | $77,500 | | $75,540 | | $3,586,198 | | $3,508,698 | |
| Utility Operations - | 2020 | $754,742 | | $— | | $1,804,816 | | $363,022 | | $673,314 | | $1,976,400 | | $59,730 | | $5,632,024 | | $3,655,624 | |
| Entergy Corp. | | | | | | | | | | |
(1)Mr. Marsh was named Chief Executive Officer, effective November 1, 2022, and Mr. Denault was elected Executive Chair on such date. Ms. Fontan was named Executive Vice President and Chief Financial Officer, effective November 1, 2022. Effective January 31, 2023, Mr. Denault resigned from the position of Executive Chair and from the Board and Mr. Marsh was elected Chairman of the Board. Ms. Rodriguez was named Chief Executive Officer, Entergy New Orleans in May 2021, and Mr. Viamontes was named Chief Executive Officer, Entergy Texas in November 2021. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
Name and Principal Position (1) | | Year | | Salary (2) | | Bonus (3) | | Stock Awards (4) | | Option Awards (5) | | Non-Equity Incentive Plan Compen-sation (6) | | Change in Pension Value and Non-qualified Deferred Compen-sation Earnings (7) | |
All
Other
Compens-ation
(8) | | Total |
| Andrew S. Marsh | | 2019 | |
| $641,923 |
| |
| $— |
| |
| $1,579,663 |
| |
| $375,914 |
| |
| $712,400 |
| |
| $1,554,300 |
| |
| $69,863 |
| |
| $4,934,063 |
|
| Executive Vice | | 2018 | |
| $615,654 |
| |
| $— |
| |
| $1,057,095 |
| |
| $342,510 |
| |
| $531,188 |
| |
| $— |
| |
| $57,638 |
| |
| $2,604,085 |
|
| President and CFO - | | 2017 | |
| $588,291 |
| |
| $— |
| |
| $1,022,853 |
| |
| $287,760 |
| |
| $541,800 |
| |
| $801,900 |
| |
| $51,647 |
| |
| $3,294,251 |
|
| Entergy Corp., | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas, | | | | | | | | | | | | | | | | | | |
| Entergy Louisiana, | | | | | | | | | | | | | | | | | | |
| Entergy Mississippi, | | | | | | | | | | | | | | | | | | |
| Entergy New | | | | | | | | | | | | | | | | | | |
| Orleans, | | | | | | | | | | | | | | | | | | |
| Entergy Texas | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Phillip R. May, Jr. | | 2019 | |
| $389,016 |
| |
| $— |
| |
| $294,183 |
| |
| $77,376 |
| |
| $407,922 |
| |
| $877,100 |
| |
| $28,297 |
| |
| $2,073,894 |
|
| CEO - Entergy | | 2018 | |
| $377,108 |
| |
| $— |
| |
| $288,238 |
| |
| $69,201 |
| |
| $270,000 |
| |
| $— |
| |
| $26,874 |
| |
| $1,031,421 |
|
| Louisiana | | 2017 | |
| $363,410 |
| |
| $— |
| |
| $302,493 |
| |
| $68,670 |
| |
| $300,000 |
| |
| $503,400 |
| |
| $26,981 |
| |
| $1,564,954 |
|
| | | | | | | | | | | | | | | | | | | |
| Sallie T. Rainer | | 2019 | |
| $344,722 |
| |
| $— |
| |
| $197,780 |
| |
| $51,584 |
| |
| $219,069 |
| |
| $617,200 |
| |
| $37,361 |
| |
| $1,467,716 |
|
| CEO - Entergy | | 2018 | |
| $335,263 |
| |
| $— |
| |
| $198,449 |
| |
| $46,134 |
| |
| $159,000 |
| |
| $— |
| |
| $35,379 |
| |
| $774,225 |
|
| Texas | | 2017 | |
| $325,737 |
| |
| $— |
| |
| $195,567 |
| |
| $51,012 |
| |
| $156,259 |
| |
| $435,900 |
| |
| $35,785 |
| |
| $1,200,260 |
|
| | | | | | | | | | | | | | | | | | | |
| Roderick K. West | | 2019 | |
| $709,023 |
| |
| $— |
| |
| $1,340,679 |
| |
| $319,039 |
| |
| $674,742 |
| |
| $1,604,100 |
| |
| $67,191 |
| |
| $4,714,774 |
|
| Group President | | 2018 | |
| $690,581 |
| |
| $— |
| |
| $1,057,095 |
| |
| $297,075 |
| |
| $560,762 |
| |
| $— |
| |
| $67,234 |
| |
| $2,672,747 |
|
| Utility Operations of | | 2017 | |
| $670,876 |
| |
| $— |
| |
| $818,316 |
| |
| $190,968 |
| |
| $610,065 |
| |
| $867,200 |
| |
| $52,220 |
| |
| $3,209,645 |
|
| Entergy Corp. | | | | | | | | | | | | | | | | | | |
| |
(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. |
(3)The amount in column (d) represents the cash bonus paid to Mr. Bakken pursuant to the Nuclear Retention Plan. Additional information about this plan can be found under the heading ‘‘Nuclear Retention Plan’’ in the CD&A.
(4)The amounts in column (e) represent the aggregate grant date fair value of restricted stock and performance units granted under the 2019 OIP, each calculated in accordance with FASB ASC Topic 718, without taking into account estimated forfeitures. The grant date fair value of the restricted stock, restricted stock units, and the portion of the performance units with vesting based on the Adjusted FFO/Debt Ratio 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 attributable to relative TSR 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 would be received if the highest achievement level is attained with respect to both the relative TSR and Adjusted FFO/Debt Ratio, for performance units granted in 2022 are as follows: Mr. Bakken, $1,561,658; Mr. Denault, $9,177,943; Mr. Fisackerly, $296,003;$394,343; Ms. Fontan, $1,594,140; Ms. Landreaux, $296,003;$459,547; Mr. Marsh, $2,422,938;$6,997,739; Mr. May, $438,901;$629,266; Ms. Rainer, $296,003;Rodriguez, $350,504; Mr. Viamontes, $400,520; and Mr. West, $2,056,302.
| |
(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: |
|
| | | | | | | | | | | | | | | | | | |
| Named Executive Officer | Company Contribution – Savings Plan | Dividends Paid on Restricted Stock | Life Insurance Premium | Tax Gross Up Payments | Perquisites and Other Compensation | Total |
| A. Christopher Bakken, III |
| $16,800 |
|
| $20,114 |
|
| $12,277 |
|
| $— |
|
| $13,216 |
|
| $62,407 |
|
| Marcus V. Brown |
| $11,760 |
|
| $48,749 |
|
| $7,482 |
|
| $— |
|
| $1,964 |
|
| $69,955 |
|
| Leo P. Denault |
| $11,760 |
|
| $129,470 |
|
| $11,484 |
|
| $— |
|
| $56,108 |
|
| $208,822 |
|
| David D. Ellis |
| $14,436 |
|
| $— |
|
| $722 |
|
| $— |
|
| $109 |
|
| $15,267 |
|
| Haley R. Fisackerly |
| $11,760 |
|
| $7,793 |
|
| $2,959 |
|
| $4,729 |
|
| $10,656 |
|
| $37,897 |
|
| Laura R. Landreaux |
| $— |
|
| $11,257 |
|
| $477 |
|
| $4,510 |
|
| $10,292 |
|
| $26,536 |
|
| Andrew S. Marsh |
| $11,760 |
|
| $49,010 |
|
| $6,275 |
|
| $— |
|
| $2,818 |
|
| $69,863 |
|
| Phillip R. May, Jr. |
| $11,760 |
|
| $9,958 |
|
| $5,779 |
|
| $— |
|
| $800 |
|
| $28,297 |
|
| Sallie T. Rainer |
| $11,760 |
|
| $7,879 |
|
| $6,872 |
|
| $2,728 |
|
| $8,122 |
|
| $37,361 |
|
| Roderick K. West |
| $11,760 |
|
| $39,754 |
|
| $4,002 |
|
| $— |
|
| $11,675 |
|
| $67,191 |
|
(6)The amounts in column (g) represent annual incentive award cash payments made under the 2019 OIP.
(7)The amounts in column (h) include the annual actuarial change in the present value of these NEOs’ 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 NEOs may not currently be entitled to receive because such amounts are not vested. For 2022, the aggregate change in the actuarial present value was a decrease of $1,209,800 for Mr. Denault, a decrease of $465,800 for Mr. Fisackerly, a decrease of $544,900 for Ms. Fontan, a decrease of $238,000 for Ms. Landreaux, a decrease of $1,741,300 for Mr. Marsh, a decrease of $945,100 for Mr. May, a decrease of $415,000 for Ms. Rodriguez, and a decrease of $2,293,500 for Mr. West. The increases for Mr. Bakken and Mr. Viamontes were not attributable to above-market or preferential earnings on non-qualified deferred compensation. See “2022 Pension Benefits.”
(8)The amounts in column (i) for 2022 include (a) matching contributions by Entergy Corporation under the Savings Plan to each of the NEOs; (b) dividends paid on restricted stock and performance units when vested; (c) life insurance premiums; (d) tax gross up payments on club dues and relocation assistance; and (e) perquisites and other compensation as described further below. The 2021 amounts for Mr. Denault have been updated as compared to the amount of All Other Compensation reported in our Form 10-K for the year ended December 31, 2021 to reflect the reimbursement by Mr. Denault of the incremental cost associated with the personal use of the corporate aircraft in 2021. Following 2021, Mr. Denault reimbursed the Company for the incremental cost associated with his personal usage of the corporate aircraft during 2021. Based on such reimbursement, his 2021 All Other Compensation excludes any cost associated with his personal usage of the corporate aircraft. The 2022 amounts are listed in the following table:
| | | | | | | | | | | | | | | | | | | | |
| Named Executive Officer | Company Contribution – Savings Plan | Dividends Paid on Restricted Stock and PUP Awards | Life Insurance Premium | Tax Gross Up Payments | Perquisites and Other Compensation | Total |
| A. Christopher Bakken, III | $18,300 | | $67,645 | | $19,547 | | $— | | $14,212 | | $119,704 | |
| | | | | | |
| Leo P. Denault | $12,810 | | $290,828 | | $11,484 | | $— | | $61,644 | | $376,766 | |
| Haley R. Fisackerly | $12,810 | | $11,147 | | $6,100 | | $4,989 | | $11,235 | | $46,281 | |
| Kimberly A. Fontan | $12,810 | | $16,263 | | $647 | | $— | | $— | | $29,720 | |
| Laura R. Landreaux | $— | | $10,589 | | $1,316 | | $4,187 | | $9,221 | | $25,313 | |
| Andrew S. Marsh | $12,810 | | $83,712 | | $10,038 | | $— | | $— | | $106,560 | |
| Phillip R. May, Jr. | $12,810 | | $16,564 | | $9,851 | | $— | | $— | | $39,225 | |
| Deanna D. Rodriguez | $12,810 | | $8,248 | | $1,514 | | $— | | $4,515 | | $27,087 | |
| Eliecer Viamontes | $18,300 | | $3,325 | | $776 | | $8,415 | | $137,493 | | $168,309 | |
| Roderick K. West | $12,810 | | $71,708 | | $4,002 | | $— | | $12,587 | | $101,107 | |
(9)In order to show the effect that the year-over-year change in pension value had on total compensation, as determined under applicable SEC rules, we have included an additional column to show total compensation minus the change in pension value. The amounts reported in the Total Without Change in Pension Value column may differ substantially from the amounts reported in the Total column required under SEC rules and are not a substitute for total compensation. Total Without Change in Pension Value represents total compensation, as determined under applicable SEC rules, minus the change in pension value reported in the Change in Pension Value and Nonqualified Deferred Compensation Earnings column. The change in pension value is subject to many external variables, such as interest rates, assumptions about life expectancy, and changes in the discount rate determined at each year end, which are functions of economic factors and actuarial calculations that are not related to Entergy Corporation’s performance and are outside of the control of the Talent and Compensation Committee.
Perquisites and Other Compensation
The amounts set forth in column (i) also include perquisites and other personal benefits that Entergy Corporation provides to its Named Executive OfficersNEOs as part of providing a competitive executive compensation programsprogram and for employee retention. The following perquisites were provided to the Named Executive OfficersNEOs in 2019.2022.
|
| | | | | | | | | | | | | |
| Named Executive Officer | Relocation | Personal Use of Corporate Aircraft | Club Dues | Executive Physical Exams | Event Tickets |
| A. Christopher Bakken, III | | X | | X | |
Marcus V. Brown | | | | X | |
| Leo P. Denault | | X | | X | |
David D. Ellis | X | | | | |
| Haley R. Fisackerly | | | X | | |
| Kimberly A. Fontan | | | | X |
| Laura R. Landreaux | | | X | | X |
| Andrew S. Marsh | | X | | X | |
| Phillip R. May, Jr. | | | | | X |
Sallie T. RainerDeanna D. Rodriguez | | | X | | X |
| Eliecer Viamontes | X | | | X |
| Roderick K. West | | X | | X | |
For security and business reasons, Entergy Corporation’s Chief Executive Officer is permitted to use its corporate aircraft for personal use at the expense of Entergy Corporation. The other Named Executive OfficersNEOs may use the corporate aircraft for personal travel subject to the approval of Entergy Corporation’s Chief Executive Officer. The PersonnelAnnually, the Talent and Compensation Committee reviews the level of usage throughout the year.usage. Entergy Corporation believes that its officers’ ability to use its plane for limited personal use saves time and provides additionalhelps to ensure their safety and security for them,while traveling, thereby benefiting Entergy Corporation.the Company. The amounts included in column (i) for the personal use of corporate aircraft, reflect the incremental cost to Entergy Corporation for use of the corporate aircraft, determined on the basis of the variable operational costs of each flight, including fuel, maintenance, flight crew travel expense, catering, communications, and fees, including flight planning, ground handling, and landing permits. The aggregate incremental aircraft usage cost associated with Mr. Denault’s personal use of the corporate aircraft was $56,108$61,644 for fiscal year 2019.2022. In addition, Entergy Corporation offers its executives comprehensive annual physical exams at Entergy Corporation’s expense. Tickets
Entergy Corporation also provides relocation benefits to culturala broad base of employees, which include assistance with moving expenses, transportation of household goods, and, sporting events are purchasedin certain circumstances, assistance with the sale of the employee’s home. In connection with employment, and in accordance with its relocation policies, Entergy Corporation paid $132,830 in relocation expense for business purposes, and if not utilized for business purposes,Mr. Viamontes in 2022. The relocation assistance amounts reported above represent the tickets are made availableamount paid to Entergy’s relocation service provider or Mr. Viamontes, as applicable. If Mr. Viamontes separates from the Company prior to the employees, including the Named Executive Officers, for personal use. two year anniversary of his promotion, certain of Mr. Viamontes relocation benefits are subject to forfeiture.
None of the other perquisites referenced above exceeded $25,000 for any of the other Named Executive Officers.NEOs.
20192022 Grants of Plan-Based Awards
The following table summarizes award grants during 20192022 to the Named Executive Officers.NEOs.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1) | | Estimated Future Payouts under Equity Incentive Plan Awards (2) | | | | | | | | |
| (a) | | (b) | | (c) | (d) | (e) | | (f) | (g) | (h) | | (i) | | (j) | | (k) | | (l) |
| Name | | Grant Date | | Thresh-old | Target | Maximum | | Thresh-old | Target | Maximum | | All Other Stock Awards: Number of Shares of Stock or Units | | All Other Option Awards: Number of Securities Under-lying Options | | Exercise or Base Price of Option Awards | | Grant Date Fair Value of Stock and Option Awards |
| | | | ($) | ($) | ($) | | (#) | (#) | (#) | | (#) (3) | | (#) (4) | | ($/Sh) | | ($) (5) |
| A. Christopher | | 1/27/22 | | $- | $536,046 | $1,072,092 | | | | | | | | | | | | |
| Bakken, III | | 1/27/22 | | | | | | 1,781 | | 7,125 | | 14,250 | | | | | | | | | $948,409 |
| | 1/27/22 | | | | | | | | | | 2,831 | | | | | | | $310,249 |
| | 1/27/22 | | | | | | | | | | | | 18,505 | | | $109.59 | | | $300,706 |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| Leo P. | | 1/27/22 | | $- | $1,820,000 | $3,640,000 | | | | | | | | | | | | |
| Denault | | 1/27/22 | | | | | | 10,469 | | 41,874 | | 83,748 | | | | | | | | | $5,573,848 |
| | 1/27/22 | | | | | | | | | | 16,638 | | | | | | | $1,823,358 |
| | 1/27/22 | | | | | | | | | | | | 108,762 | | | $109.59 | | $1,767,383 |
| | | | | | | | | | | | | | | | | | |
| Haley R. | | 1/27/22 | | $- | $228,162 | $456,324 | | | | | | | | | | | | |
Fisackerly(7) | | 1/27/22 | | | | | | 371 | | 1,483 | | 2,966 | | | | | | | | | $197,402 |
| | 7/24/22 | | | | | | 7 | | 27 | | 54 | | | | | | | | | $3,594 |
| | 7/24/22 | | | | | | 61 | | 244 | | 488 | | | | | | | | | $26,295 |
| | 7/24/22 | | | | | | 16 | | 63 | | 126 | | | | | | | | | $10,215 |
| | | 1/27/22 | | | | | | | | | | 590 | | | | | | | $64,658 |
| | 11/10/22 | | | | | | | | | | 4,053(6) | | | | | | $450,045 |
| | | 1/27/22 | | | | | | | | | | | | 3,852 | | | $109.59 | | $62,595 |
| | | | | | | | | | | | | | | | | | |
| Kimberly A. | | 1/27/22 | | $- | $468,750 | $937,500 | | | | | | | | | | | | |
Fontan(7) | | 1/27/22 | | | | | | 477 | | 1,908 | | 3,816 | | | | | | | | | $253,974 |
| | 11/1/22 | | | | | | 849 | | 3,394 | | 6,788 | | | | | | | | | $451,775 |
| | 11/1/22 | | | | | | 499 | | 1,995 | | 3,990 | | | | | | | | | $214,993 |
| | 11/1/22 | | | | | | 47 | | 188 | | 376 | | | | | | | | | $30,482 |
| | 1/27/22 | | | | | | | | | | 758 | | | | | | $83,069 |
| | 1/27/22 | | | | | | | | | | | | 4,955 | | | $109.59 | | $80,519 |
| | | | | | | | | | | | | | | | | | |
| Laura R. | | 1/27/22 | | $- | $216,812 | $433,624 | | | | | | | | | | | | |
Landreaux(7) | | 1/27/22 | | | | | | 371 | | 1,483 | | 2,966 | | | | | | | | | $197,402 |
| | 7/24/22 | | | | | | 72 | | 286 | | 572 | | | | | | | | | $38,069 |
| | 7/24/22 | | | | | | 72 | | 288 | | 576 | | | | | | | | | $31,037 |
| | 7/24/22 | | | | | | 16 | | 63 | | 126 | | | | | | | | | $10,215 |
| | 1/27/22 | | | | | | | | | | 590 | | | | | | | $64,658 |
| | 1/27/22 | | | | | | | | | | | | 3,852 | | | $109.59 | | $62,595 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1) | | Estimated Future Payouts under Equity Incentive Plan Awards (2) | | | | | | | | |
| (a) | | (b) | | (c) | (d) | (e) | | (f) | (g) | (h) | | (i) | | (j) | | (k) | | (l) |
| Name | | Grant Date | | Thresh-old | Target | Maximum | | Thresh-old | Target | Maximum | | All Other Stock Awards: Number of Shares of Stock or Units | | All Other Option Awards: Number of Securities Under-lying Options | | Exercise or Base Price of Option Awards | | Grant Date Fair Value of Stock and Option Awards |
| | | | | ($) | ($) | ($) | | (#) | (#) | (#) | | (#) (3) | | (#) (4) | | ($/Sh) | | ($) (5) |
| A. Christopher | | 1/31/19 | | $- | $457,855 | $915,710 | | | | | | | | | | | | |
| Bakken, III | | 1/31/19 | | | | | | 2,392 |
| 9,568 |
| 19,136 |
| | | | | | | | $951,959 |
| | | 1/31/19 | | | | | |
|
| |
|
| | 3,604 |
| | | | | | $321,441 |
| | | 1/31/19 | | | | | | | | | | | | 36,421 |
| | $89.19 | | $303,023 |
| | | | | | | | | | | | | | | | | | | |
| Marcus V. | | 1/31/19 | | $- | $499,688 | $999,376 | | | | | | | | | | | | |
| Brown | | 1/31/19 | | | | | | 2,346 |
| 9,383 |
| 18,766 |
| | | | | | | | $933,552 |
| | | 1/31/19 | | | | | | | | | | 3,535 |
| | | | | | $315,287 |
| | | 1/31/19 | | | | | | | | | | | | 35,719 |
| | $89.19 | | $297,182 |
| | | | | | | | | | | | | | | | | | | |
| Leo P. | | 1/31/19 | | $- | $1,764,000 | $3,528,000 | | | | | | | | | | | | |
| Denault | | 1/31/19 | | | | | | 10,127 |
| 40,508 |
| 81,016 |
| | | | | | | | $4,030,303 |
| | | 1/31/19 | | | | | | | | | | 15,259 |
| | | | | | $1,360,950 |
| | | 1/31/19 | | | | | | | | | | | | 154,206 |
| | $89.19 | | $1,282,994 |
| | | | | | | | | | | | | | | | | | | |
| David D. | | 1/31/19 | | $- | $125,355 | $250,710 | | | | | | | | | | | | |
| Ellis | | 1/31/19 | | | | | | 363 |
| 1,450 |
| 2,900 |
| | | | | | | | $144,266 |
| | | | | | | | | | | | | 500 |
| | | | | | $44,595 |
| | | | | | | | | | | | | | | 4,700 |
| | $89.19 | | $39,104 |
| | | | | | | | | | | | | | | | | | | |
| Haley R. | | 1/31/19 | | $- | $150,409 | $300,818 | | | | | | | | |
| | | | |
| Fisackerly | | 1/31/19 | | | | | | 363 |
| 1,450 |
| 2,900 |
| | | | | | | | $144,266 |
| | | 1/31/19 | | | | | | | | | | 600 |
| | | | | | $53,514 |
| | | 1/31/19 | | | | | | | | | | | | 6,200 |
| | $89.19 | | $51,584 |
| | | | | | | | | | | | | | | | | | | |
| Laura R. | | 1/31/19 | | $- | $126,588 | $253,176 | |
| | | | | | | | | | |
| Landreaux | | 1/31/19 | | | | | | 363 |
| 1,450 |
| 2,900 |
| | | | | | | | $144,266 |
| | | 1/31/19 | | | | | | | | | | 500 |
| | | |
| | $44,595 |
| | | | | | | | | | | | | | | 5,100 |
| | $89.19 | | $42,432 |
| | | | | | | | | | | | | | | | | | | |
| Andrew S. | | 1/31/19 | | $- | $520,000 | $1,040,000 | | | | | | | | | | | | |
| Marsh | | 1/31/19 | | | | | | 2,967 |
| 11,869 |
| 23,738 |
| | | | | | | | $1,180,894 |
| | | 1/31/19 | | | | | | | | | | 4,471 |
| | | | | | $398,768 |
| | | 1/31/19 | | | | | | | | | | | | 45,182 |
| | $89.19 | | $375,914 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1) | | Estimated Future Payouts under Equity Incentive Plan Awards (2) | | | | | | | | |
| (a) | | (b) | | (c) | (d) | (e) | | (f) | (g) | (h) | | (i) | | (j) | | (k) | | (l) |
| Name | | Grant Date | | Thresh-old | Target | Maximum | | Thresh-old | Target | Maximum | | All Other Stock Awards: Number of Shares of Stock or Units | | All Other Option Awards: Number of Securities Under-lying Options | | Exercise or Base Price of Option Awards | | Grant Date Fair Value of Stock and Option Awards |
| | | | ($) | ($) | ($) | | (#) | (#) | (#) | | (#) (3) | | (#) (4) | | ($/Sh) | | ($) (5) |
| Andrew S. | | 1/27/22 | | $- | $1,320,000 | $2,640,000 | | | | | | | | | | | | |
Marsh(7) | | 1/27/22 | | | | | | 2,453 | | 9,810 | | 19,620 | | | | | | | | | $1,305,809 |
| | 11/1/22 | | | | | | 3,327 | | 13,308 | | 26,616 | | | | | | | | | $1,771,428 |
| | 11/1/22 | | | | | | 2,290 | | 9,160 | | 18,320 | | | | | | | | | $987,137 |
| | 11/1/22 | | | | | | 166 | | 662 | | 1,324 | | | | | | | | | $107,334 |
| | 1/27/22 | | | | | | | | | | 3,898 | | | | | | | $427,182 |
| | 1/27/22 | | | | | | | | | | | | 25,480 | | | $109.59 | | $414,050 |
| | | | | | | | | | | | | | | | | | |
| Phillip R. | | 1/27/22 | | $- | $261,386 | $522,772 | | | | | | | | | | | | |
| May, Jr. | | 1/27/22 | | | | | | 718 | | 2,871 | | 5,742 | | | | | | | | | $382,159 |
| | 1/27/22 | | | | | | | | | | 1,141 | | | | | | | $125,042 |
| | 11/10/22 | | | | | | | | | | 4,053(6) | | | | | | $450,045 |
| | 1/27/22 | | | | | | | | | | | | 7,457 | | | $109.59 | | $121,176 |
| | | | | | | | | | | | | | | | | | |
| Deanna D. | | 1/27/22 | | $- | $173,586 | $347,172 | | | | | | | | | | | | |
Rodriguez(7) | | 1/27/22 | | | | | | 286 | | 1,145 | | 2,290 | | | | | | | | | $152,411 |
| | 7/24/22 | | | | | | 27 | | 109 | | 218 | | | | | | | | | $14,509 |
| | 7/24/22 | | | | | | 77 | | 308 | | 616 | | | | | | | | | $33,192 |
| | 7/24/22 | | | | | | 16 | | 63 | | 126 | | | | | | | | | $10,214 |
| | 1/27/22 | | | | | | | | | | 455 | | | | | | | $49,863 |
| | 1/27/22 | | | | | | | | | | | | 2,974 | | | $109.59 | | $48,328 | |
| | | | | | | | | | | | | | | | | | |
| Eliecer | | 1/27/22 | | $- | $192,584 | $385,168 | | | | | | | | | | | | |
Viamontes(7) | | 1/27/22 | | | | | | 317 | | 1,268 | | 2,536 | | | | | | | | | $168,783 |
| | 7/24/22 | | | | | | 77 | | 309 | | 618 | | | | | | | | | $41,131 |
| | 7/24/22 | | | | | | 50 | | 201 | | 402 | | | | | | | | | $21,661 |
| | 7/24/22 | | | | | | 16 | | 62 | | 124 | | | | | | | | | $10,053 |
| | 1/27/22 | | | | | | | | | | 504 | | | | | | | $55,233 |
| | 1/27/22 | | | | | | | | | | | | 3,294 | | | $109.59 | | $53,528 |
| | | | | | | | | | | | | | | | | | |
| Roderick K. | | 1/27/22 | | $- | $621,147 | $1,242,294 | | | | | | | | | | | | |
| West | | 1/27/22 | | | | | | 2,381 | | 9,525 | | 19,050 | | | | | | | | | $1,267,873 |
| | | 1/27/22 | | | | | | | | | | 3,785 | | | | | | | $414,798 |
| | 11/10/22 | | | | | | | | | | 18,012(6) | | | | | | $2,000,052 |
| | 1/27/22 | | | | | | | | | | | | 24,740 | | | $109.59 | | $402,025 |
(1)The amounts in columns (c), (d), and (e) represent minimum, target, and maximum payment levels under the annual incentive program. The actual amounts awarded are reported in column (g) of the 2022 Summary Compensation Table.
(2)The amounts in columns (f), (g), and (h) represent the minimum, target, and maximum payment levels under the PUP. Performance under the program is measured by Entergy Corporation’s TSR relative to the TSR of
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1) | | Estimated Future Payouts under Equity Incentive Plan Awards (2) | | | | | | | | |
| (a) | | (b) | | (c) | (d) | (e) | | (f) | (g) | (h) | | (i) | | (j) | | (k) | | (l) |
| Name | | Grant Date | | Thresh-old | Target | Maximum | | Thresh-old | Target | Maximum | | All Other Stock Awards: Number of Shares of Stock or Units | | All Other Option Awards: Number of Securities Under-lying Options | | Exercise or Base Price of Option Awards | | Grant Date Fair Value of Stock and Option Awards |
| | | | | ($) | ($) | ($) | | (#) | (#) | (#) | | (#) (3) | | (#) (4) | | ($/Sh) | | ($) (5) |
| Phillip R. | | 1/31/19 | | $- | $235,226 | $470,452 | | | | | | | | | | | | |
| May, Jr. | | 1/31/19 | | | | | | 538 |
| 2,150 |
| 4,300 |
| | | | | | | | $213,912 |
| | | 1/31/19 | | | | | | | | | | 900 |
| | | | | | $80,271 |
| | | 1/31/19 | | | | | | | | | | | | 9,300 |
| | $89.19 | | $77,376 |
| | | | | | | | | | | | | | | | | | | |
| Sallie T. | | 1/31/19 | | $- | $138,969 | $277,938 | | | | | | |
| | |
| | | | |
| Rainer | | 1/31/19 | | | | | | 363 |
| 1,450 |
| 2,900 |
| | | | | | | | $144,266 |
| | | 1/31/19 | | | | | | | | | | 600 |
| | | | | | $53,514 |
| | | 1/31/19 | | | | | | | | | | | | 6,200 |
| | $89.19 | | $51,584 |
| | | | | | | | | | | | | | | | | | | |
| Roderick K. | | 1/31/19 | | $- | $499,809 | $999,618 | | | | | | | | | | | | |
| West | | 1/31/19 | | | | | | 2,518 |
| 10,073 |
| 20,146 |
| | | | | | | | $1,002,203 |
| | | 1/31/19 | | | | | | | | | | 3,795 |
| | | | | | $338,476 |
| | | 1/31/19 | | | | | | | | | | | | 38,346 |
| | $89.19 | | $319,039 |
| |
(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. |
(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 footnotes 4 and 5 to the 2022 Summary Compensation Table for a discussion of the relevant assumptions used in calculating the grant date fair value.
(6)In November 2022, Messrs. Fisackerly, May, and West were awarded 4,053, 4,053, and 18,012 restricted stock units, respectively, under the 2019 OIP. The restricted units will vest in one installment on October 1, 2025 for Messrs. Fisackerly and May and in three equal installments on June 1, 2024, June 1, 2025, and June 1, 2026, for Mr. West, provided Messrs. Fisackerly, May, and West each satisfies the vesting criteria of his restricted stock unit agreement described in the CD&A under the heading “Restricted Stock Units.”
(7)Mses. Fontan, Landreaux, and Rodriguez and Messrs. Fisackerly, Marsh, and Viamontes’s awards were modified in connection with their promotions in 2022.
2022 Outstanding Equity Awards at Fiscal Year-End
The following table summarizes, for each Named Executive Officer,NEO, unexercised options, restricted stock that has not vested, and equity incentive plan awards outstanding as of December 31, 2019.2022.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexer-cised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| A. Christopher | | — | | | 18,505(1) | | | | $109.59 | | 1/27/2032 | | | | | | | | |
| Bakken, III | | 8,109 | | | 16,220(2) | | | | $95.87 | | 1/28/2031 | | | | | | | | |
| | 19,519 | | | 9,760(3) | | | | $131.72 | | 1/30/2030 | | | | | | | | |
| | 24,281 | | | — | | | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | 13,500 | | | — | | | | | $78.08 | | 1/25/2028 | | | | | | | | |
| | | | | | | | | | | | | | | | 14,250(4) | | $1,603,125 |
| | | | | | | | | | | | | | | | 19,510(5) | | $2,194,875 |
| | | | | | | | | | | | 2,831(6) | | $318,488 | | | | |
| | | | | | | | | | | | 2,255(7) | | $253,688 | | | | |
| | | | | | | | | | | | 1,035(8) | | $116,438 | | | | |
| | | | | | | | | | | | 10,000(9) | | $1,125,000 | | | | |
| | | | | | | | | | | | | | | | | | |
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| Leo P. Denault | | — | | | 108,762(1) | | | | $109.59 | | 1/27/2032 | | | | | | | | |
| | 43,533 | | | 87,067(2) | | | | $95.87 | | 1/28/2031 | | | | | | | | |
| | 78,660 | | | 39,330(3) | | | | $131.72 | | 1/30/2030 | | | | | | | | |
| | 154,206 | | | — | | | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | 167,100 | | | — | | | | | $78.08 | | 1/25/2028 | | | | | | | | |
| | 179,400 | | | — | | | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | 167,000 | | | — | | | | | $70.56 | | 1/28/2026 | | | | | | | | |
| | 88,000 | | | — | | | | | $89.90 | | 1/29/2025 | | | | | | | | |
| | | | | | | | | | | | | | | | 83,748(4) | | $9,421,650 |
| | | | | | | | | | | | | | | | 104,730(5) | | $11,782,125 |
| | | | | | | | | | | | 16,638(6) | | $1,871,775 | | | | |
| | | | | | | | | | | | 12,103(7) | | $1,361,588 | | | | |
| | | | | | | | | | | | 4,169(8) | | $469,013 | | | | |
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| | | | | | | | | | | | | | | | | | | | | | Option Awards | | Stock Awards |
| | Option Awards | | Stock Awards | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) | |
| Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested | Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexer-cised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) | | | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| A. Christopher Bakken, III | | — |
| | 36,421(1) |
| | $89.19 | | 1/31/2029 | | |
| Haley R. | | Haley R. | | — | | | 3,852(1) | | $109.59 | | 1/27/2032 | |
| Fisackerly | | Fisackerly | | 1,367 | | | 2,734(2) | | $95.87 | | 1/28/2031 | |
| | | — |
| | 27,000(2) |
| | $78.08 | | 1/25/2028 | | | 2,866 | | | 1,434(3) | | $131.72 | | 1/30/2030 | |
| | | — |
| | 12,534(3) |
| | $70.53 | | 1/26/2027 | | | 4,134 | | | — | | | $89.19 | | 1/31/2029 | |
| | | | | | | 19,136(4) | | $2,292,493 | | 2,200 | | | — | | | $78.08 | | 1/25/2028 | |
| | | | | | | 15,800(5) | | $1,892,840 | | 3,020(4) | | $339,750 |
| | | | | | | 3,604(6) | | $431,759 | | | 3,778(5) | | $425,025 |
| | | | | | | 3,334(7) | | $399,413 | | | 590(6) | | $66,375 | |
| | | | | | | 1,734(8) | | $207,733 | | | 380(7) | | $42,750 | |
| | | | | | | 20,000(10) | | $2,396,000 | | | 250(8) | | $28,125 | |
| | | | | | | | 4,053(10) | | $455,963 | |
| Marcus V. Brown | | — |
| | 35,719(1) |
| | $89.19 | | 1/31/2029 | | |
| | Kimberly A. | | Kimberly A. | | — | | | 4,955(1) | | $109.59 | | 1/27/2032 | |
| Fontan | | Fontan | | 1,815 | | | 3,630(2) | | $95.87 | | 1/28/2031 | |
| | | — |
| | 27,000(2) |
| | $78.08 | | 1/25/2028 | | | 4,266 | | | 2,134(3) | | $131.72 | | 1/30/2030 | |
| | | 1 |
| | 14,667(3) |
| | $70.53 | | 1/26/2027 | | | 6,000 | | | — | | | $89.19 | | 1/31/2029 | |
| | | 1 |
| | — |
| | $70.56 | | 1/28/2026 | | | 2,500 | | | — | | | $78.08 | | 1/25/2028 | |
| | | | | | | 18,766(4) | | $2,248,167 | | 10,604 (4) | | $1,192,950 |
| | | | | | | 15,800(5) | | $1,892,840 | | 8,358(5) | | $940,275 |
| | | | | | | 3,535(6) | | $423,493 | | | 758(6) | | $85,275 | |
| | | | | | | 3,334(7) | | $399,413 | | | 505(7) | | $56,813 | |
| | | | | | | 2,034(8) | | $243,673 | | | 334(8) | | $37,575 | |
| | Laura R. | | Laura R. | | — | | | 3,852(1) | | $109.59 | | 1/27/2032 | |
| Landreaux | | Landreaux | | 1,291 | | | 2,582(2) | | $95.87 | | 1/28/2031 | |
| | | 2,866 | | | 1,434(3) | | $131.72 | | 1/30/2030 | |
| | | 5,100 | | | — | | | $89.19 | | 1/31/2029 | |
| | | 3,538(4) | | $398,025 |
| | | 3,682(5) | | $414,225 |
| | | 590(6) | | $66,375 | |
| | | 360(7) | | $40,500 | |
| | | 250(8) | | $28,125 | |
| |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| Leo P. Denault | | — |
| | 154,206(1) |
| | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | | 55,700 |
| | 111,400(2) |
| | | | $78.08 | | 1/25/2028 | | | | | | | | |
| | | 119,600 |
| | 59,800(3) |
| | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | | 167,000 |
| | — |
| | | | $70.56 | | 1/28/2026 | | | | | | | | |
| | | 88,000 |
| | — |
| | | | $89.90 | | 1/29/2025 | | | | | | | | |
| | | 106,000 |
| | — |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| | | 50,000 |
| | — |
| | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | | | | | | | | | | | | | | | 81,016(4) | | $9,705,717 |
| | | | | | | | | | | | | | | | | 85,400(5) | | $10,230,920 |
| | | | | | | | | | | | | 15,259(6) | | $1,828,028 | | | | |
| | | | | | | | | | | | | 10,467(7) | | $1,253,947 | | | | |
| | | | | | | | | | | | | 5,667(8) | | $678,907 | | | | |
| | | | | | | | | | | | | | | | | | | |
| David D. Ellis | | — |
| | 4,700(1) |
| | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | | | | | | | | | | | | | | | | 2,900(4) | | $347,420 |
| | | | | | | | | | | | | | | | | 2,200(5) | | $263,560 |
| | | | | | | | | | | | | 500(6) | | $59,900 | | | | |
| | | | | | | | | | | | | | | | | | | |
| Haley R. Fisackerly | | — |
| | 6,200(1) |
| | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | | — |
| | 4,400(2) |
| | | | $78.08 | | 1/25/2028 | | | | | | | | |
| | | — |
| | 2,534(3) |
| | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | | | | | | | | | | | | | | | | 2,900(4) | | $347,420 |
| | | | | | | | | | | | | | | | | 3,300(5) | | $395,340 |
| | | | | | | | | | | | | 600(6) | | $71,880 | | | | |
| | | | | | | | | | | | | 534(7) | | $63,973 | | | | |
| | | | | | | | | | | | | 284(8) | | $34,023 | | | | |
| | | | | | | | | | | | | | | | | | | |
| Laura R. Landreaux | | — |
| | 5,100(1) |
| | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | | | | | | | | | | | | | | | | 2,900(4) | | $347,420 |
| | | | | | | | | | | | | | | | | 2,750(5) | | $329,450 |
| | | | | | | | | | | | | 500(6) | | $59,900 | | | | |
| | | | | | | | | | | | | 800(7) | | $95,840 | | | | |
| | | | | | | | | | | | | 500(8) | | $59,900 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexer-cised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| Andrew S. | | — | | | 25,480(1) | | | | $109.59 | | 1/27/2032 | | | | | | | | |
| Marsh | | 9,732 | | | 19,464(2) | | | | $95.87 | | 1/28/2031 | | | | | | | | |
| | 24,052 | | | 12,027(3) | | | | $131.72 | | 1/30/2030 | | | | | | | | |
| | 45,182 | | | — | | | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | 49,000 | | | — | | | | | $78.08 | | 1/25/2028 | | | | | | | | |
| | 44,000 | | | — | | | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | 45,000 | | | — | | | | | $70.56 | | 1/28/2026 | | | | | | | | |
| | 24,000 | | | — | | | | | $89.90 | | 1/29/2025 | | | | | | | | |
| | | | | | | | | | | | | | | | 46,236(4) | | $5,201,550 |
| | | | | | | | | | | | | | | | 41,732(5) | | $4,694,850 |
| | | | | | | | | | | | 3,898(6) | | $438,525 | | | | |
| | | | | | | | | | | | 2,706(7) | | $304,425 | | | | |
| | | | | | | | | | | | 1,275(8) | | $143,438 | | | | |
| | | | | | | | | | | | | | | | | | |
| Phillip R. | | — | | | 7,457(1) | | | | $109.59 | | 1/27/2032 | | | | | | | | |
| May, Jr. | | 1,797 | | | 3,595(2) | | | | $95.87 | | 1/28/2031 | | | | | | | | |
| | 4,866 | | | 2,434(3) | | | | $131.72 | | 1/30/2030 | | | | | | | | |
| | 6,200 | | | — | | | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | | | | | | | | | | | | | | | 5,742(4) | | $645,975 |
| | | | | | | | | | | | | | | | 4,324(5) | | $486,450 |
| | | | | | | | | | | | 1,141(6) | | $128,363 | | | | |
| | | | | | | | | | | | 500(7) | | $56,250 | | | | |
| | | | | | | | | | | | 367(8) | | $41,288 | | | | |
| | | | | | | | | | | | 4,053(10) | | $455,963 | | | | |
| | | | | | | | | | | | | | | | | | |
| Deanna D. | | — | | | 2,974(1) | | | | $109.59 | | 1/27/2032 | | | | | | | | |
| Rodriguez | | | | | | | | | | | | | | | | 2,508(4) | | $282,150 |
| | | | | | | | | | | | | | | | 3,216(5) | | $361,800 |
| | | | | | | | | | | | 455(6) | | $51,188 | | | | |
| | | | | | | | | | | | 824(7) | | $92,700 | | | | |
| | | | | | | | | | | | 284(8) | | $31,950 | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| Andrew S. Marsh | | — |
| | 45,182(1) |
| | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | | 16,333 |
| | 32,667(2) |
| | | | $78.08 | | 1/25/2028 | | | | | | | | |
| | | 29,333 |
| | 14,667(3) |
| | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | | 45,000 |
| | — |
| | | | $70.56 | | 1/28/2026 | | | | | | | | |
| | | 24,000 |
| | — |
| | | | $89.90 | | 1/29/2025 | | | | | | | | |
| | | 35,000 |
| | — |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| | | 32,000 |
| | — |
| | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | 10,000 |
| | — |
| | | | $71.30 | | 1/26/2022 | | | | | | | | |
| | | 4,000 |
| | — |
| | | | $72.79 | | 1/27/2021 | | | | | | | | |
| | | | | | | | | | | | | | | | | 23,738(4) | | $2,843,812 |
| | | | | | | | | | | | | | | | | 15,800(5) | | $1,892,840 |
| | | | | | | | | | | | | 4,471(6) | | $535,626 | | | | |
| | | | | | | | | | | | | 3,467(7) | | $415,347 | | | | |
| | | | | | | | | | | | | 2,034(8) | | $243,673 | | | | |
| | | | | | | | | | | | | 21,100(9) | | $2,527,780 | | | | |
| | | | | | | | | | | | | | | | | | | |
| Phillip R. May, Jr. | | — |
| | 9,300(1) |
| | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | | — |
| | 6,600(2) |
| | | | $78.08 | | 1/25/2028 | | | | | | | | |
| | | — |
| | 3,500(3) |
| | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | | 2,000 |
| | — |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| | | 2,000 |
| | — |
| | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | | | | | | | | | | | | | | | 4,300(4) | | $515,140 |
| | | | | | | | | | | | | | | | | 5,100(5) | | $610,980 |
| | | | | | | | | | | | | 900(6) | | $107,820 | | | | |
| | | | | | | | | | | | | 667(7) | | $79,907 | | | | |
| | | | | | | | | | | | | 367(8) | | $43,967 | | | | |
| | | | | | | | | | | | | | | | | | | |
| Sallie T. Rainer | | — |
| | 6,200(1) |
| | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | | — |
| | 4,400(2) |
| | | | $78.08 | | 1/25/2028 | | | | | | | | |
| | | — |
| | 2,600(3) |
| | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | | | | | | | | | | | | | | | | 2,900(4) | | $347,420 |
| | | | | | | | | | | | | | | | | 3,300(5) | | $395,340 |
| | | | | | | | | | | | | 600(6) | | $71,880 | | | | |
| | | | | | | | | | | | | 534(7) | | $63,973 | | | | |
| | | | | | | | | | | | | 300(8) | | $35,940 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexer-cised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| Eliecer | | — | | | 3,294(1) | | | | $109.59 | | 1/27/2032 | | | | | | | | |
| Viamontes | | 1,444 | | | 2,888(2) | | | | $95.87 | | 1/28/2031 | | | | | | | | |
| | | | | | | | | | | | | | | | 3,154(4) | | $354,825 |
| | | | | | | | | | | | | | | | 3,876(5) | | $436,050 |
| | | | | | | | | | | | 504(6) | | $56,700 | | | | |
| | | | | | | | | | | | 402(7) | | $45,225 | | | | |
| | | | | | | | | | | | 334(11) | | $37,575 | | | | |
| | | | | | | | | | | | | | | | | | |
| Roderick K. | | — | | | 24,740(1) | | | | $109.59 | | 1/27/2032 | | | | | | | | |
| West | | 8,917 | | | 17,835(2) | | | | $95.87 | | 1/28/2031 | | | | | | | | |
| | 21,136 | | | 10,569(3) | | | | $131.72 | | 1/30/2030 | | | | | | | | |
| | 25,564 | | | — | | | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | 14,167 | | | — | | | | | $78.08 | | 1/25/2028 | | | | | | | | |
| | | | | | | | | | | | | | | | 19,050(4) | | $2,143,125 |
| | | | | | | | | | | | | | | | 21,454(5) | | $2,413,575 |
| | | | | | | | | | | | 3,785(6) | | $425,813 | | | | |
| | | | | | | | | | | | 2,480(7) | | $279,000 | | | | |
| | | | | | | | | | | | 1,121(8) | | $126,113 | | | | |
| | | | | | | | | | | | 18,012(12) | | $2,026,350 | | | | |
(1)Consists of options granted under the 2019 OIP; 1/3 of the options vested on January 27, 2023 and 1/3 of the remaining options will vest on each of January 27, 2024 and January 27, 2025.
(2)Consists of options granted under the 2019 OIP; 1/2 of the options vested on January 28, 2023 and the remaining options will vest on January 28, 2024.
(3)Consists of options granted under the 2019 OIP that vested on January 30, 2023.
(4)Consists of performance units granted under the 2019 OIP that will vest on December 31, 2024 based on two performance measures- Entergy Corporation’s relative TSR performance and Adjusted FFO/Debt Ratio over the 2022 - 2024 performance period with relative TSR weighted eighty percent and Adjusted FFO/Debt Ratio weighted twenty percent, as described under “What Entergy Corporation Pays and Why - Long-Term Incentive Compensation - 2022 Long-Term Incentive Award Mix - Long-Term Performance Unit Program” in the CD&A.
(5)Consists of performance units granted under the 2019 OIP that will vest on December 31, 2023 based on two performance measures - Entergy Corporation’s relative TSR performance and Adjusted FFO/Debt Ratio over the 2021 - 2023 performance period with relative TSR weighted eighty percent and Adjusted FFO/Debt Ratio weighted twenty percent.
(6)Consists of shares of restricted stock granted under the 2019 OIP; 1/3 of the shares of restricted stock vested on January 27, 2023 and 1/2 of the remaining shares will vest on each of January 27, 2024 and January 27, 2025.
|
| | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| Roderick K. West | | — |
| | 38,346(1) |
| | | | $89.19 | | 1/31/2029 | | | | | | | | |
| | | 14,166 |
| | 28,334(2) |
| | | | $78.08 | | 1/25/2028 | | | | | | | | |
| | | 9,733 |
| | 9,734(3) |
| | | | $70.53 | | 1/26/2027 | | | | | | | | |
| | | 13,667 |
| | — |
| | | | $70.56 | | 1/28/2026 | | | | | | | | |
| | | 23,000 |
| | — |
| | | | $89.90 | | 1/29/2025 | | | | | | | | |
| | | | | |
| | | | | | | | | | | | 20,146(4) | | $2,413,491 |
| | | |
| | |
| | | | | | | | | | | | 15,800(5) | | $1,892,840 |
| | | |
| | |
| | | | | | | | 3,795(6) | | $454,641 | | | | |
| | | |
| | |
| | | | | | | | 3,467(7) | | $415,347 | | | | |
| | | |
| | |
| | | | | | | | 1,067(8) | | $127,827 | | | | |
| |
(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. |
(12)Consists of restricted stock units granted under the 2019 OIP which will vest in three equal installments on June 1, 2024, June 1, 2025, and June 1, 2026.
2019
2022 Option Exercises and Stock Vested
The following table provides information concerning each exercise of stock options and each vesting of stock during 20192022 for the Named Executive Officers.NEOs.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Options Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) |
| Name | | Number of Shares Acquired on Exercise | | Value Realized on Exercise | | Number of Shares Acquired on Vesting | | Value Realized on Vesting (1) |
| | (#) | | ($) | | (#) | | ($) |
| A. Christopher Bakken, III | | — | | | $— | | | 15,933 | | | $1,888,165 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Leo P. Denault | | 156,000 | | | $8,570,377 | | | 25,752 | | | $2,832,876 | |
| | | | | | | | |
| Haley R. Fisackerly | | — | | | $— | | | 987 | | | $108,886 | |
| | | | | | | | |
| Kimberly A. Fontan | | — | | | $— | | | 1,495 | | | $164,847 | |
| | | | | | | | |
| Laura R. Landreaux | | — | | | $— | | | 938 | | | $103,416 | |
| | | | | | | | |
| Andrew S. Marsh | | 77,000 | | | $3,979,106 | | | 7,466 | | | $820,131 | |
| | | | | | | | |
| Phillip R. May, Jr. | | 3,300 | | | $138,336 | | | 1,404 | | | $154,817 | |
| | | | | | | | |
| Deanna D. Rodriguez | | — | | | $— | | | 1,261 | | | $139,896 | |
| | | | | | | | |
| Eliecer Viamontes | | — | | | $— | | | 833 | | | $91,685 | |
| | | | | | | | |
| Roderick K. West | | — | | | $— | | | 6,402 | | | $703,666 | |
(1)Represents the value of performance units for the 2020 – 2022 performance period (payable solely in shares based on the closing stock price of Entergy Corporation on the date of vesting) under the PUP and the vesting of restricted stock and restricted stock units in 2022.
|
| | | | | | | | | | | | | | |
| | | Options Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) |
| Name | | Number of Shares Acquired on Exercise | | Value Realized on Exercise | | Number of Shares Acquired on Vesting | | Value Realized on Vesting (1) |
| | | (#) | | ($) | | (#) | | ($) |
| A. Christopher Bakken, III | | 38,566 |
| |
| $1,377,860 |
| | 31,719 |
| |
| $3,543,240 |
|
| | | | | | | | | |
| Marcus V. Brown | | 145,031 |
| |
| $4,056,865 |
| | 24,484 |
| |
| $2,839,040 |
|
| | | | | | | | | |
| Leo P. Denault | | 105,000 |
| |
| $2,861,250 |
| | 123,760 |
| |
| $14,933,716 |
|
| | | | | | | | | |
| David D. Ellis | | — |
| |
| $— |
| | 1,271 |
| |
| $160,540 |
|
| | | | | | | | | |
| Haley R. Fisackerly | | 13,700 |
| |
| $280,882 |
| | 5,037 |
| |
| $596,349 |
|
| | | | | | | | | |
| Laura R. Landreaux | | — |
| |
| $— |
| | 3,431 |
| |
| $374,036 |
|
| | | | | | | | | |
| Andrew S. Marsh | | 17,100 |
| |
| $468,315 |
| | 24,554 |
| |
| $2,845,137 |
|
| | | | | | | | | |
| Phillip R. May, Jr. | | 18,900 |
| |
| $456,820 |
| | 8,146 |
| |
| $978,103 |
|
| | | | | | | | | |
| Sallie T. Rainer | | 15,667 |
| |
| $372,696 |
| | 5,055 |
| |
| $597,906 |
|
| | | | | | | | | |
| Roderick K. West | | — |
| |
| $— |
| | 23,347 |
| |
| $2,740,719 |
|
| |
(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. |
20192022 Pension Benefits
The following table shows the present value as of December 31, 2019,2022, of accumulated benefits payable to each of the Named Executive Officers,NEOs, including the number of years of service credited to each Named Executive Officer,NEO, under the retirement plans sponsored by Entergy Corporation, determined using interest rate and mortality rate assumptions set forth in Note 11 to the financial statements. Additional information regarding these retirement plans follows this table.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Name | | Plan Name | | Number of Years Credited Service | | Present Value of Accumulated Benefit | | Payments During 2022 |
| A. Christopher Bakken, III | | Cash Balance Equalization Plan | | 6.74 | | | $422,900 | | | $— | |
| | Cash Balance Plan | | 6.74 | | | $137,800 | | | $— | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Leo P. Denault (1)(2)(3) | | System Executive Retirement Plan | | 30.00 | | | $33,825,500 | | | $— | |
| | | Entergy Retirement Plan | | 23.83 | | | $1,121,300 | | | $— | |
| | | | | | | | |
Haley R. Fisackerly(1) | | System Executive Retirement Plan | | 27.08 | | | $2,320,200 | | | $— | |
| | | Entergy Retirement Plan | | 27.08 | | | $992,100 | | | $— | |
| | | | | | | | |
| Kimberly A. Fontan | | Pension Equalization Plan | | 26.56 | | | $727,700 | | | $— | |
| | Entergy Retirement Plan | | 26.56 | | | $691,100 | | | $— | |
| | | | | | | | |
| Laura R. Landreaux | | Pension Equalization Plan | | 15.48 | | | $326,300 | | | $— | |
| | Entergy Retirement Plan | | 15.48 | | | $396,400 | | | $— | |
| | | | | | | | |
| Andrew S. Marsh | | System Executive Retirement Plan | | 24.37 | | | $5,316,700 | | | $— | |
| | Entergy Retirement Plan | | 24.37 | | | $642,400 | | | $— | |
| | | | | | | | |
Phillip R. May, Jr. (1)(3) | | System Executive Retirement Plan | | 30.00 | | | $3,119,800 | | | $— | |
| | Entergy Retirement Plan | | 36.56 | | | $1,511,800 | | | $— | |
| | | | | | | | |
Deanna D. Rodriguez(1) | | Pension Equalization Plan | | 28.19 | | $643,900 | | | $— | |
| | Entergy Retirement Plan | | 28.19 | | $1,106,600 | | | $— | |
| | | | | | | | |
| Eliecer Viamontes | | Cash Balance Equalization Plan | | 2.95 | | $14,900 | | | $— | |
| | Cash Balance Plan | | 2.95 | | $31,300 | | | $— | |
| | | | | | | | |
| Roderick K. West | | System Executive Retirement Plan | | 23.75 | | | $5,711,400 | | | $— | |
| | | Entergy Retirement Plan | | 23.75 | | | $734,100 | | | $— | |
(1)As of December 31, 2022, Mr. Denault, Mr. Fisackerly, Mr. May, and Ms. Rodriguez were retirement eligible.
(2)In 2021, the Company entered into an agreement with Mr. Denault and amended the PEP and the SERP, pursuant to which agreement and amendments the benefit payable to Mr. Denault (or to his surviving spouse) under the SERP when he separates from employment with the Company is fixed and will be determined as if such separation from employment occurred as of November 30, 2021 (including the use of final average monthly compensation, service, and actuarial assumptions applicable to separations as of such date).The amendment to the PEP terminated Mr. Denault’s participation in this plan. Mr. Denault retired and separated from employment with the Company on January 31, 2023.
(3)Service under the SERP 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. The SERP amounts reflected in the table for Mr. Denault and Mr. May are calculated based on 30 years of service pursuant to the terms of the SERP.
|
| | | | | | | | | | | | | |
| Name | | Plan Name | | Number of Years Credited Service | | Present Value of Accumulated Benefit | | Payments During 2019 |
| A. Christopher Bakken, III | | Cash Balance Equalization Plan | | 3.74 |
| |
| $196,900 |
| |
| $— |
|
| | | Cash Balance Plan | | 3.74 |
| |
| $71,200 |
| |
| $— |
|
| | | | | | | | | |
Marcus V. Brown(1) | | System Executive Retirement Plan | | 24.74 |
| |
| $6,368,400 |
| |
| $— |
|
| | | Entergy Retirement Plan | | 24.74 |
| |
| $1,160,000 |
| |
| $— |
|
| | | | | | | | | |
Leo P. Denault (1)(2) | | System Executive Retirement Plan | | 35.83 |
| |
| $26,526,500 |
| |
| $— |
|
| | | Entergy Retirement Plan | | 20.83 |
| |
| $1,035,100 |
| |
| $— |
|
| | | | | | | | | |
| David D. Ellis | | Cash Balance Equalization Plan | | 1.06 |
| |
| $1,900 |
| |
| $— |
|
| | | Cash Balance Plan | | 1.06 |
| |
| $16,700 |
| |
| $— |
|
| | | | | | | | | |
| Haley R. Fisackerly | | System Executive Retirement Plan | | 24.08 |
| |
| $1,728,000 |
| |
| $— |
|
| | | Entergy Retirement Plan | | 24.08 |
| |
| $1,023,900 |
| |
| $— |
|
| | | | | | | | | |
| Laura R. Landreaux | | Pension Equalization Plan | | 12.48 |
| |
| $86,300 |
| |
| $— |
|
| | | Entergy Retirement Plan | | 12.48 |
| |
| $418,700 |
| |
| $— |
|
| | | | | | | | | |
| Andrew S. Marsh | | System Executive Retirement Plan | | 21.37 |
| |
| $4,694,700 |
| |
| $— |
|
| | | Entergy Retirement Plan | | 21.37 |
| |
| $738,700 |
| |
| $— |
|
| | | | | | | | | |
Phillip R. May, Jr. (1) | | System Executive Retirement Plan | | 33.56 |
| |
| $2,964,100 |
| |
| $— |
|
| | | Entergy Retirement Plan | | 33.56 |
| |
| $1,538,500 |
| |
| $— |
|
| | | | | | | | | |
Sallie T. Rainer (1)(3) | | System Executive Retirement Plan | | 35.38 |
| |
| $1,511,300 |
| |
| $— |
|
| | | Entergy Retirement Plan | | 35.00 |
| |
| $1,766,400 |
| |
| $— |
|
| | | | | | | | | |
| Roderick K. West | | System Executive Retirement Plan | | 20.75 |
| |
| $5,892,400 |
| |
| $— |
|
| | | Entergy Retirement Plan | | 20.75 |
| |
| $792,700 |
| |
| $— |
|
| |
(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. |
Retirement Benefits
The tables below contain summaries of the pension benefit plans sponsored by Entergy Corporation that the Named Executive OfficersNEOs participated in during 2019.2022. Benefits for the Named Executive OfficersNEOs who participate in these plans are determined using the same formulas as for other eligible employees.
Qualified Retirement Benefits
|
| | | | | | | | | | |
| Entergy Retirement Plan | Cash Balance Plan(1) |
| Eligible Named Executive Officers | Marcus V. Brown
Haley R. Fisackerly
Leo P. Denault
Andrew S. Marsh
Laura R. Landreaux
| Phillip R. May, Jr. Sallie T. Rainer
Kimberly A. Fontan
Deanna D. Rodriguez
Roderick K. West
| A. Christopher Bakken, III David D. Ellis
Eliecer Viamontes |
| Eligibility | Non-bargaining employees hired before July 1, 2014 | Non-bargaining employees hired on or after July 1, 2014 and before January 1, 2021. |
| Vesting | A participant becomes vested in the Entergy Retirement Plan upon attainment of at least 5 years of vesting service or upon attainment of age 65 while actively employed by an Entergy system company. | A participant becomes vested in the Cash Balance Plan upon attainment of at least 3 years of vesting service or upon attainment of age 65 while actively employed by an Entergy system company. |
| Form of Payment Upon Retirement | Benefits are payable as an annuity. For employees who separate from service on or after January 1, 2018, a single lump sum distribution may be elected by the participant if eligibility criteria are met. | Benefits are payable as an annuity or single lump sum distribution. |
| | | | | | | | | | | |
| Entergy Retirement Plan | Cash Balance Plan(1) |
| Retirement Benefit Formula | Benefits are calculated as a single life annuity payable at age 65 and generally are equal to 1.5% of a participant’s Final Average Monthly Earnings (FAME) multiplied by years of service (not to exceed 40).
“Earnings”
Earnings for the purpose of calculating FAME generally includes the employee’s base salary and eligible annual incentive awards subject to limitations imposed by the Internal Revenue Code limitations,of 1986, as amended (the Code), and excludes all other bonuses. Executive annual incentive awards are not eligible for inclusion in Earningsearnings under this plan.
FAME is calculated using the employee’s average monthly Earningsearnings for the 60 consecutive months in which the employee’s earnings were highest during the 120 month
period immediately preceding the employee’s retirement and includes up to 5 eligible annual incentive awards paid during the 60 month period.
| The normal retirement benefit at age 65 is determined by converting the sum of an employee’s annual pay credits and his or her annual interest credits into an actuarially equivalent annuity.
Pay credits ranging from 4-8% of an employee’s eligible Earningsearnings are allocated annually to a notional account for the employee based on an employee’s age and years of service. Earnings for purposes of calculating an employee’s pay credit include the employee’s base salary and annual incentive awards subject to Internal Revenue Code limitations and exclude all other bonuses. Executive annual incentive awards are eligible for inclusion in Earningsearnings under this plan.
Interest credits are calculated based upon the annual rate of interest on 30-year U.S. Treasury securities, as specified by the Internal Revenue Service, for the month of August preceding the first day of the applicable calendar year subject to a minimum rate of 2.6% and a maximum rate of 9%.
|
|
| | | |
Benefit Timing(2) | Normal retirement age under the plan is 65.
A reduced terminated vested benefit may be commenced as early as age 55. The amount of this benefit is determined by reducing the normal retirement benefit by 7% per year for the first 5 years commencement precedes age 65 and 6% per year for each additional year commencement precedes age 65.
A subsidized early retirement benefit may be commenced by employees who are at least age 55 with 10 years of service at the time they separate from service. The amount of this benefit is determined by reducing the normal retirement benefit by 2% per year for each year that early retirement precedes age 65.
| Normal retirement age under the plan is 65.
A vested cash balance benefit can be commenced as early as the first day of the month following separation from service. The amount of the benefit is determined in the same manner as the normal retirement benefit described above in the “Retirement Benefit Formula” section.
|
(1)Effective January 1, 2022, the Entergy Corporation Cash Balance Plan for Non-Bargaining Employees merged into and became Appendix J of the Entergy Corporation Retirement Plan for Non-Bargaining Employees, but retained its eligibility, benefit formula, and all benefits, rights and features.
(2)As of December 31, 2022, Messrs. Fisackerly, Denault, and May and Ms. Rodriguez were eligible for early retirement under the Entergy Retirement Plan.
Non-qualified Retirement Benefits
The Named Executive OfficersNEOs are eligible to participate in certain non-qualified retirement benefit plans that provide retirement income in addition to the benefit provided under the qualified retirement plans, including the Pension Equalization Plan,PEP, the CBEP, and the SERP. Upon separation from the Company, those NEOs who participate in both the PEP and the SERP will be paid only the greater of the benefit under the PEP or the SERP. Each of the SERP, PEP, and Cash Balance Equalization Plan and the System Executive Retirement Plan. Each of these plans is an unfunded non-qualified defined benefit pension plan that provides benefits to key management employees. In these plans, as described below, an executive may participate in one or more non-qualified plans, but is only paid the amount due under the plan that provides the highest benefit. In general, upon disability, participants in the Pension Equalization PlanPEP and the System Executive Retirement PlanSERP remain eligible for continued service credits until the earlier of recovery, separation from service due to disability, or retirement eligibility. Generally, spouses of
participants who die before commencement of benefits may be eligible for a portion of the participant’s accrued benefit.
|
| | | | | | | | | | | | | | | | |
| Pension Equalization Plan | Cash Balance Equalization Plan | System Executive Retirement Plan |
| Eligible Named Executive Officers | Marcus V. Brown
Haley R. Fisackerly Leo P. Denault
Laura R. Landreaux
Andrew S. Marsh
| Phillip R. May, Jr. Sallie T. Rainer
Kimberly A. Fontan
Deanna D. Rodriguez
Roderick K. West
| A. Christopher Bakken, III David D. EllisEliecer Viamontes
| Marcus V. Brown
Haley R. Fisackerly
Leo P. Denault
Denault*
Andrew S. Marsh
| Phillip R. May, Jr. Sallie T. Rainer
Roderick K. West
|
| Eligibility | Management or highly compensated employees who participate in the Entergy Retirement Plan | Management or highly compensated employees who participate in the Cash Balance Plan | Certain individuals who became executive officers before July 1, 2014 |
| Form of Payment Upon Retirement | Single lump sum distribution | Single lump sum distribution | Single lump sum distribution |
| Retirement Benefit Formula | Benefits generally are equal to the actuarial present value of the difference between (1) the amount that would have been payable as an annuity under the Entergy Retirement Plan, including executive annual incentive awards as eligible earnings and without applying limitations of the Internal Revenue Code of 1986, as amended (the “Code”) on pension benefits and earnings that may be considered in calculating tax-qualified pension benefits, and (2) the amount actually payable as an annuity under the Entergy Retirement Plan. Executive annual incentive awards are taken into account as eligible earnings under this plan. | Benefits generally are equal to the difference between the amount that would have been payable as a lump sum under the Cash Balance Plan, but for the Code limitations on pension benefits and earnings that may be considered in calculating tax-qualified cash balance plan benefits, and the amount actually payable as a lump sum under the Cash Balance Plan. | Benefits generally are equal to the actuarial present value of a specified percentage, based on the participant’s years of service (including supplemental service granted under the plan) and management level of the participant’s “Final Average Monthly Compensation” (which is generally 1/36th of the sum of the participant’s base salary and annual incentive plan award for the 3 highest years during the last 10 years preceding separation from service), after first being reduced by the value of the participant’s Entergy Retirement Plan benefit. |
| Benefit timing | Payable at age 65
Benefits payable prior to age 65 are subject to the same reduced terminated vested or early retirement reduction factors as benefits payable under the Entergy Retirement Plan as described above.
An employee with supplemental credited service who terminates employment prior to age 65 must receive prior written consent of the Entergy employer in order to receive the portion of their benefit attributable to their supplemental credited service agreement.
Benefits payable upon separation from service subject to the 6 month delay required under the Code Section 409A.
| Payable upon separation from service subject to 6six month delay required under the Code Section 409A. | Payable at age 65
Prior to age 65, vesting is conditioned on the prior written consent of the officer’s Entergy employer.
Benefits payable prior to age 65 are subject to the same reduced terminated vested or subsidized early retirement reduction factors as benefits payable under the Entergy Retirement Plan as described above.
Benefits payable upon separation from service subject to the 6six month delay required under Internal Revenuethe Code Section 409A.
|
Additional Information
| |
(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. |
2019(1)Effective July 1, 2014, (a) no new grants of supplemental service may be provided to participants in the PEP; (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 PEP and instead may be eligible to participate in the Cash Balance Equalization Plan.
(2)Benefits accrued under the SERP, PEP, and CBEP, 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 six months under Internal Revenue Code Section 409A.
(3)The SERP was closed to new executive officers effective July 1, 2014.
2022 Non-qualified Deferred Compensation
As of December 31, 2019,2022, Mr. May had a deferred account balance under a frozen Defined Contribution Restoration Plan. The amount is deemed invested, as chosen by Mr. May, in certain T. Rowe Price investment funds that are also available to the participantparticipants under the Savings Plan. Mr. May has elected to receive the deferred account balance after he retires. The Defined Contribution Restoration Plan, until it was frozen in 2005, credited eligible employees’ deferral accounts with employer contributions to the extent contributions under the qualified savings plan in which the employee participated were subject to limitations imposed by the Internal Revenue Code.
Defined Contribution Restoration Plan | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Name | | Executive Contributions in 2022 | | Registrant Contributions in 2022 | | Aggregate Earnings in 2022(1) | | Aggregate Withdrawals/Distributions | | Aggregate Balance at December 31, 2022 |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) |
| | | | | | | | | | | |
| Phillip R. May, Jr. | | $— | | | $— | | | ($423) | | | $— | | | $3,253 | |
|
| | | | | | | | | | | | | | | | | | | | |
| Name | | Executive Contributions in 2019 | | Registrant Contributions in 2019 | | Aggregate Earnings in 2019(1) | | Aggregate Withdrawals/Distributions | | Aggregate Balance at December 31, 2019 |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) |
| | | | | | | | | | | |
| Phillip R. May, Jr. | |
| $— |
| |
| $— |
| |
| $805 |
| |
| $— |
| |
| $2,987 |
|
| |
(1) | Amounts in this column are not included in the Summary Compensation Table. |
20192022 Potential Payments Upon Termination or Change in Control
Entergy CorporationThe Company has plans and other arrangements that provide compensation to a Named Executive OfficerNEO if his or her employment terminates under specified conditions, including following a change in control of Entergy Corporation or its subsidiaries.the Company.
Change in Control
Entergy Corporation does not have any plans or agreements that provide for payments or benefits to any of our NEOs solely upon a Change in Control (as defined below). Under Entergy Corporation’sthe System Executive Continuity Plan (the “Continuity Plan”), ML 1-4 Officersexecutive officers, including each of the NEOs, with the exception of Mr. Denault, are eligible to receive the cash severance payment and welfare plan benefits described below if their employment is terminated by their Entergy System employer other than for causeCause (as defined below) or if they terminate their employment for good reasonGood Reason during a period beginning with a potential change in control and ending 24 months following the effective date of a changeChange in controlControl (a “Qualifying Termination”). Mr. Denault became ineligible to participate in or receive any benefits under the Continuity Plan, effective November 1, 2022, pursuant to his resignation as CEO of Entergy Corporation, and retired and separated from employment with the Company on January 31, 2023. A participant will not be eligible for benefits under the Continuity Plan if such participant: accepts employment with Entergy Corporation or any of its subsidiaries; elects to receive the benefits of another severance or separation program; removes, copies, or fails to return any property belonging to Entergy Corporation or any of its subsidiaries or violates his or herthe non-compete
provision of the Continuity Plan (which generally runs for two years but extends to three years if permissible under applicable law). Entergy CorporationThe Continuity Plan does not haveinclude any plans or agreements that provideprovisions for payments or benefits tothe waiver of a breach of any of these restrictive covenants.
In addition, under the Named Executive Officers solely2019 OIP or an applicable equity award agreement issued under the 2019 OIP, upon a changeQualifying Termination, our executive officers, including the NEOs, are eligible for the payments and benefits described in control.the table below under “Performance Units” and “Equity Awards.” Further, in the event of a Qualifying Termination, our executive officers, including our NEOs, are eligible for the benefits described in the table below for “Retirement Benefits” under the terms of the SERP, PEP, and/or CBEP, as applicable.
In the event of a Qualifying Termination, the executive officers, including the Named Executive Officers, generally willNEOs, with the exception of Mr. Denault, would receive lump sum severance payments and welfare benefits described below. In the event of a Qualifying Termination, all of the NEOs, including Mr. Denault (prior to his separation from the Company on January 31, 2023), would receive the treatment described below for their retirement benefits set forth below:and their outstanding performance units and equity awards:
|
| | | | |
| Compensation Element | Payment and/or Benefit** |
| Severance* | A lump sum severance payment equal to a multiple of the sum of: (a) the participant’s annual base salary as in effect at any time within one year prior to the commencement of a change ofin control period or, if higher, immediately prior to a circumstance constituting good reason, plus (b) the participant’s annual incentive award, calculated using the average annual target opportunity derived under the Annual Incentive Planannual incentive program for the two calendar years immediately preceding the calendar year in which termination occurs. |
| Performance Units | Participants will forfeitFor outstanding performance units, andparticipants would receive a number of shares of Entergy common stock equal to the greater of (1) the target number of performance units subject to the performance unit agreement or (2) the number of units that would vest under the performance unit agreement calculated based on Company performance through the participant’s termination date, in lieueither case pro-rated based on the portion of any payment for any outstandingthe performance period will receive a single-lump sum payment calculated by multiplyingthat occurs through the target performance units for the most recent performance period preceding (but not including) the calendar year in which termination occurs by the closing price of Entergy’s common stock as of the later of the date of such termination or the date of the Change in Control.date. |
| Equity Awards | All unvested stock options shares of restricted stock and restricted stock units will vest immediately, and restrictions will lift on restricted shares, upon a “double trigger” Qualifying Termination pursuant to the terms of the Equity Ownership Plan.Entergy’s equity plans. |
| Retirement Benefits | Benefits already accrued under the System Executive Retirement Plan, Pension Equalization PlanSERP, PEP, and Cash Balance Equalization Plan,CBEP, if any, will become fully vested. |
| Welfare Benefits | Participants who are not retirement-eligible would be eligible to receive Entergy-subsidized COBRA benefits for a period ranging from 12 to 18 months. |
| |
* | 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. |
* Cash severance payments are capped at 2.99 times the sum of (a) an executive’s annual base salary in effect at any time within one year before commencement of the change in control period, or, if higher, immediately prior to a circumstance constituting Good Reason under the Continuity Plan in effect at any time within one year before commencement of the change in control period or, if higher, immediately prior to a circumstance constituting Good Reason under the Continuity Plan, plus (b) the higher of the executive’s actual annual incentive payment under the annual incentive program for the year immediately preceding the calendar year in which termination occurs or the average of the executive’s target annual incentive award for the two calendar years preceding the 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.
** Prior to his separation from the Company on January 31, 2023, in the event of a Qualifying Termination, Mr. Denault would have received the greater of the payments and benefits described in the table above for which he was eligible or those payments and benefits provided for by the retention agreement entered into between Mr. Denault and the Company. See “Mr. Denault’s 2006 Retention Agreement” for a description of the payments and benefits Mr. Denault would have received in the event of a Qualifying Termination in connection with a change in control.
To protect shareholders and Entergy Corporation’s business model, executives are required to comply with non-compete non-solicitation,provisions (which generally run for two years but extends to three years if permissible under applicable law) and confidentiality and non-denigration provisions.provisions, as discussed above. If an executive discloses non-public data or information concerning Entergy Corporation or any of its subsidiaries or violates his or her non-compete provision, he or she will be required to repay any benefits previously received under the Continuity Plan.
For purposes of the Continuity Plan, the following events are generally defined as:
| |
• | 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.
|
| |
• | 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.
|
•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.
| |
• |
•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.
•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 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 the participant’s 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.
•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.
|
| |
• | 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.
|
Other Termination Events
For termination events, other than in connection with a Change in Control, the executive officers, including the Named Executive Officers,NEOs, generally will receive the benefits set forth below:
|
| | | | | | | | | | | | | | | | |
| Termination Event | Compensation Element |
| Severance | Annual Incentive | Stock Options | Restricted Stock(2) | Performance Units |
| Voluntary Resignation | None | Forfeited*Forfeited(1) | Unvested options are forfeited. Vested options expire on the earlier of (i) 90 days from the last day of active employment and (ii) the option’s normal expiration date. | Forfeited | Forfeited**Forfeited(3) |
| Termination for Cause | None | Forfeited | Forfeited | Forfeited | Forfeited |
| Retirement | None | Pro-rated based on number of days employed during the performance period
| Unvested stock options granted in or after 2020 continue to vest onfollowing retirement, in accordance with the retirement dateoriginal vesting schedule and expire on the earlier of (i) five years from the Retirement retirement date and (ii) the option’s normal expiration date.
| Forfeited | Officers with a minimum of 12 months of participation are eligible for a pro-rated award based on actual performance and full months of service during the performance period |
| Death/Disability | None | Pro-rated based on number of days employed during the performance period
| Unvested stock options vest on the termination date and expire on the earlier of (i) five years from the termination date and (ii) the option’s normal expiration date
| Fully Vest | Officers are eligible for pro-rated award based on actual performance and full months of service during the performance period |
| |
* | 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. |
(1)If an officer resigns after the completion of an annual incentive plan, he or she may receive, at Entergy Corporation’s discretion, an annual incentive payment.
(2)This column refers solely to restricted stock awards. As discussed in the CD&A, certain officers are occasionally granted restricted stock units for retention purposes, to offset forfeited compensation from a previous employer or for other limited purposes. The treatment of restricted stock units depends on the terms of the individual restricted stock unit agreement, which terms can vary. The standard off-cycle restricted stock unit agreement approved by the Talent and Compensation Committee provides that the units are forfeited if employment is terminated for any reason before the vesting date, except in the case of a termination other than for cause or voluntary termination for Good Reason during a Change in Control period. However, individual restricted stock unit agreements may provide for accelerated vesting in certain events, such as death or disability. Messrs. Bakken, Fisackerly, May, and West each have outstanding restricted stock units, the treatment of which upon various events of termination is disclosed in connection with the table below.
(3)If an officer resigns after the completion of a PUP performance period, he or she will receive a payout under the PUP based on the outcome of the performance period.
Mr. Denault’s 2006 Retention Agreement
In 2006, Entergy Corporationthe Company entered into a retention agreement with Mr. Denault that providesprovided benefits to him in addition to, or in lieu of, the benefits described above. Specifically,As a result of Mr. Denault’s retirement on January 31, 2023, the retention agreement is no longer effective.
Prior to Mr. Denault’s retirement on January 31, 2023, his retention agreement provided that in the event of a Termination Event (as defined in his retention agreement): 1)(1) Mr. Denault iswas entitled to a Target LTIPPUP Award calculated by using the average annual number of performance units with respect to the two most recent performance periods preceding the calendar year in which his employment termination occurs,occurred, assuming all performance goals were achieved at target; and 2)(2) all of Mr. Denault’s unvested stock options would immediately vest and shares ofrestrictions would lift immediately on all restricted stock will immediately vest.stock.
InPrior to Mr. Denault’s retirement on January 31, 2023, his retention agreement provided that in the event of death or disability, Mr. Denault would receivehave received the greater of the Target LTIPPUP Award calculated as described above for a Termination Event under his retention agreement or the pro-rated number of performance units for alleach open performance periods,period, based on the actual achievement level for each such open performance period and number of months of his participation in each open performance period.period, as provided for by the applicable PUP Performance Unit Agreements for the open PUP Performance Periods.
Under the terms of his 2006 retention agreement, the Company was entitled to terminate Mr. Denault’s employment may be terminated for cause upon Mr. Denault’s: (a) continuing failure to substantially perform his duties (other than because of physical or mental illness or after he has given notice of termination for good reason) that remains uncured for 30 days after receiving a written notice from the PersonnelTalent and Compensation Committee; (b) willfully engaging in conduct that iswas demonstrably and materially injurious to Entergy; (c) conviction of or entrance of a plea of guilty or nolo contendere to a felony or other crime that hashad or may have had a material adverse effect on his ability to carry out his duties or upon Entergy’s reputation; (d) material violation of any agreement that he has entered into with Entergy; or (e) unauthorized disclosure of Entergy’s confidential information.
The retention agreement further provided that Mr. Denault maywas entitled to terminate his employment for good reason upon: (a) the substantial reduction in the nature or status of his duties or responsibilities from those in effect immediately prior to the date of the retention agreement, other than de minimis acts that arewere remedied after notice from Mr. Denault; (b) a reduction of 5% or more in his base salary as in effect on the date of the retention agreement; (c) the relocation of his principal place of employment to a location other than the corporate headquarters; (d) the failure to continue to allow him to participate in programs or plans providing opportunities for equity awards, incentive compensation, and other plans on a basis not materially less favorable than enjoyed at the time of the retention agreement (other than changes similarly affecting all senior executives); (e) the failure to continue to allow him to participate in programs or plans with opportunities for benefits not materially less favorable than those enjoyed by him under any of theour pension, savings, life insurance, medical, health and accident, disability, or vacation plans or policies at the time of the retention agreement (other than changes similarly affecting all senior executives); or (f)(d) any purported termination of his employment not taken in accordance with his retention agreement.
Aggregate Termination Payments
The tables below reflect the amount of compensation each of the Named Executive OfficersNEOs would have received if his or her employment had been terminated as of December 31, 20192022 under the various scenarios described above. For purposes of these tables, a stock price of $119.80$112.50 was used, which was the closing market price of Entergy Corporation stock on December 31, 2019,30, 2022, the last trading day of the year.
| | | | | | | | | | | | | | | | | | | | | | | |
| Benefits and Payments Upon Termination | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement | Disability | Death | Termination Related to a Change in Control |
A. Christopher Bakken III(2) | | | | | | | |
| Severance Payment | — | | — | | — | | — | | — | | — | | $3,752,322 | |
Performance Units(4) | — | | — | | — | | — | | $998,888 | | $998,888 | | $998,888 | |
| Stock Options | — | | — | | — | | — | | $323,589 | | $323,589 | | $323,589 | |
| Restricted Stock | — | | — | | — | | — | | $733,077 | | $733,077 | | $733,077 | |
Welfare Benefits(6) | — | | — | | — | | — | | — | | — | | $23,850 | |
Unvested Restricted Stock Units(7) | $276,075 | | — | | — | | — | | $1,125,000 | | $1,125,000 | | $1,125,000 | |
| | | | | | | |
Leo P. Denault(1) | | | | | | | |
| Severance Payment | — | | — | | | — | | — | | — | | — | |
Performance Units(3)(4) | — | | — | | $4,680,450 | | $5,497,650 | | $5,497,650 | | $5,497,650 | | 5,497,650 | |
| Stock Options | — | | — | | $1,764,421 | | | $1,764,421 | | $1,764,421 | | 1,764,421 | |
| Restricted Stock | — | | — | | $3,929,044 | | — | | $3,929,044 | | $3,929,044 | | 3,929,044 | |
Welfare Benefits(5) | — | | — | | — | | — | | — | | — | | — | |
| | | | | | | |
Haley R. Fisackerly(1) | | | | | | | |
| Severance Payment | — | | — | | — | | — | | — | | — | | $1,161,553 | |
Performance Units(4) | — | | — | | — | | $198,450 | | $198,450 | | $198,450 | | $198,450 | |
| Stock Options | — | | — | | — | | — | | $56,675 | | $56,675 | | $56,675 | |
| Restricted Stock | — | | — | | — | | — | | $146,181 | | $146,181 | | $146,181 | |
Welfare Benefits(5) | — | | — | | — | | — | | — | | — | | — | |
Unvested Restricted Stock Units(8) | — | | — | | — | | — | | — | | — | | $455,963 | |
| | | | | | | |
Kimberly A. Fontan(2) | | | | | | | |
| Severance Payment | — | | — | | — | | — | | — | | — | | $2,990,000 | |
Performance Units(4) | — | | — | | — | | — | | $512,325 | | $512,325 | | $512,325 | |
| Stock Options | — | | — | | — | | — | | $74,786 | | $74,786 | | $74,786 | |
| Restricted Stock | — | | — | | — | | — | | $191,448 | | $191,448 | | $191,448 | |
Welfare Benefits(6) | — | | — | | — | | — | | — | | — | | $32,022 | |
| | | | | | | |
Laura R. Landreaux(2) | | | | | | | |
| Severance Payment | — | | — | | — | | — | | — | | — | | $1,103,770 | |
Performance Units(4) | — | | — | | — | | — | | $204,525 | | $204,525 | | $204,525 | |
| Stock Options | — | | — | | — | | — | | $54,148 | | $54,148 | | $54,148 | |
| Restricted Stock | — | | — | | — | | — | | $143,759 | | $143,759 | | $143,759 | |
Welfare Benefits(6) | — | | — | | — | | — | | — | | — | | $32,022 | |
| | | Benefits and Payments Upon Termination | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement | Disability | Death | Termination Related to a Change in Control | Benefits and Payments Upon Termination | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement | Disability | Death | Termination Related to a Change in Control |
A. Christopher Bakken, III(1) | | | |
Andrew S. Marsh(2) | | Andrew S. Marsh(2) | |
| Severance Payment | | Severance Payment | — | | — | | — | | — | | — | | — | | $6,084,650 | |
Performance Units(4) | | Performance Units(4) | — | | — | | — | | — | | $2,431,913 | | $2,431,913 | | $2,431,913 | |
| Stock Options | | Stock Options | — | | — | | — | | — | | $397,833 | | $397,833 | | $397,833 | |
| Restricted Stock | | Restricted Stock | — | | — | | — | | — | | $942,225 | | $942,225 | | $942,225 | |
Welfare Benefits(6) | | Welfare Benefits(6) | — | | — | | — | | — | | — | | — | | $32,022 | |
| Phillip R. May, Jr.(1) | | Phillip R. May, Jr.(1) | |
| Severance Payment | — |
| — |
| — |
| — |
| — |
| — |
|
| $3,335,798 |
| Severance Payment | — | | — | | — | | — | | — | | — | | $1,394,057 | |
Performance Units(3) | — |
| — |
| — |
| — |
|
| $1,013,149 |
|
| $1,013,149 |
|
| $1,964,720 |
| Performance Units(3) | — | | — | | — | | $269,888 | | $269,888 | | $269,888 | | $269,888 | |
| Stock Options | — |
| — |
| — |
| — |
|
| $2,858,837 |
|
| $2,858,837 |
|
| $2,858,837 |
| Stock Options | — | | — | | — | | — | | $81,485 | | $81,485 | | $81,485 | |
| Restricted Stock | — |
| — |
| — |
| — |
|
| $1,113,669 |
|
| $1,113,669 |
|
| $1,113,669 |
| Restricted Stock | — | | — | | — | | — | | $239,640 | | $239,640 | | $239,640 | |
Welfare Benefits(5) | — |
| — |
| — |
| — |
| — |
| — |
|
| $22,248 |
| Welfare Benefits(5) | — | | — | | — | | — | | — | | — | | — | |
Unvested Restricted Stock Units(7) | — |
| — |
| — |
| — |
| — |
| — |
|
| $2,369,000 |
| |
Unvested Restricted Stock Units(9) | | Unvested Restricted Stock Units(9) | — | | — | | — | | — | | — | | — | | $455,963 | |
| | | | |
Marcus V. Brown(2) | | | |
Deanna D. Rodriguez(1) | | Deanna D. Rodriguez(1) | |
| Severance Payment | — |
| — |
| — |
| — |
| — |
| — |
|
| $3,397,875 |
| Severance Payment | — | | — | | — | | — | | — | | — | | $954,723 | |
Performance Units(3) | — |
| — |
| — |
|
| $1,005,721 |
|
| $1,005,721 |
|
| $1,005,721 |
|
| $1,964,720 |
| |
| Stock Options | — |
| — |
| — |
|
| $2,942,442 |
|
| $2,942,442 |
|
| $2,942,442 |
|
| $2,942,442 |
| |
| Restricted Stock | — |
| — |
| — |
| — |
|
| $1,145,708 |
|
| $1,145,708 |
|
| $1,145,708 |
| |
Welfare Benefits(6) | — |
| — |
| — |
| — |
| — |
| — |
| — |
| |
| | | | |
Leo P. Denault(2) | | | |
| Severance Payment | — |
| — |
| — |
| — |
| — |
| — |
|
| $9,870,588 |
| |
Performance Units(3)(4) | — |
| — |
|
| $4,480,520 |
|
| $5,028,006 |
|
| $5,028,006 |
|
| $5,028,006 |
|
| $9,991,320 |
| |
| Stock Options | — |
| — |
|
| $12,314,200 |
|
| $12,314,200 |
|
| $12,314,200 |
|
| $12,314,200 |
|
| $12,314,200 |
| |
| Restricted Stock | — |
| — |
|
| $4,015,803 |
| — |
|
| $4,015,803 |
|
| $4,015,803 |
|
| $4,015,803 |
| |
Welfare Benefits(6) | — |
| — |
| — |
| — |
| — |
| — |
| — |
| |
| | | | |
David D. Ellis(1) | | | |
| Severance Payment | — |
| — |
| — |
| — |
| — |
| — |
|
| $376,065 |
| |
Performance Units(3) | — |
| — |
| — |
| — |
|
| $145,916 |
|
| $145,916 |
|
| $431,280 |
| |
Performance Units(4) | | Performance Units(4) | — | | — | | — | | $167,625 | | $167,625 | | $167,625 | | $167,625 | |
| Stock Options | — |
| — |
| — |
| — |
|
| $143,867 |
|
| $143,867 |
|
| $143,867 |
| Stock Options | — | | — | | — | | — | | 8,654 | | 8,654 | | 8,654 | |
| Restricted Stock | — |
| — |
| — |
| — |
|
| $62,022 |
|
| $62,022 |
|
| $62,022 |
| Restricted Stock | — | | — | | — | | — | | $188,493 | | $188,493 | | $188,493 | |
Welfare Benefits(5) | — |
| — |
| — |
| — |
| — |
| — |
|
| $19,908 |
| Welfare Benefits(5) | — | | — | | — | | — | | — | | — | | — | |
| | | | |
Haley R. Fisackerly(1) | | | |
Eliecer Viamontes(2) | | Eliecer Viamontes(2) | |
| Severance Payment | — |
| — |
| — |
| — |
| — |
| — |
|
| $526,432 |
| Severance Payment | — | | — | | — | | — | | — | | — | | $980,430 | |
Performance Units(3) | — |
| — |
| — |
| — |
|
| $189,763 |
|
| $189,763 |
|
| $431,280 |
| |
Performance Units(4) | | Performance Units(4) | — | | — | | — | | — | | $204,525 | | $204,525 | | $204,525 | |
| Stock Options | — |
| — |
| — |
| — |
|
| $498,200 |
|
| $498,200 |
|
| $498,200 |
| Stock Options | — | | — | | — | | — | | $57,613 | | $57,613 | | $57,613 | |
| Restricted Stock | — |
| — |
| — |
| — |
|
| $182,045 |
|
| $182,045 |
|
| $182,045 |
| Restricted Stock | — | | — | | — | | — | | $107,467 | | $107,467 | | $107,467 | |
Welfare Benefits(5) | — |
| — |
| — |
| — |
| — |
| — |
|
| $19,908 |
| |
Welfare Benefits(6) | | Welfare Benefits(6) | — | | — | | — | | — | | — | | — | | $32,022 | |
Unvested Restricted Stock Units(10) | | Unvested Restricted Stock Units(10) | — | | — | | — | | — | | — | | — | | $37,575 | |
| | | | |
Laura R. Landreaux(1) | | | |
Roderick K. West(2) | | Roderick K. West(2) | |
| Severance Payment | — |
| — |
| — |
| — |
| — |
| — |
|
| $419,322 |
| Severance Payment | — | | — | | — | | — | | — | | — | | $4,192,744 | |
Performance Units(3)(4) | — |
| — |
| — |
| — |
|
| $167,840 |
|
| $167,840 |
|
| $431,280 |
| |
Performance Units(4) | | Performance Units(4) | — | | — | | — | | — | | $1,161,788 | | $1,161,788 | | $1,161,788 | |
| Stock Options | — |
| — |
| — |
| — |
|
| $156,111 |
|
| $156,111 |
|
| $156,111 |
| Stock Options | — | | — | | — | | — | | $368,589 | | $368,589 | | $368,589 | |
| Restricted Stock | — |
| — |
| — |
| — |
|
| $233,335 |
|
| $233,335 |
|
| $233,335 |
| Restricted Stock | — | | — | | — | | — | | $882,356 | | $882,356 | | $882,356 | |
Welfare Benefits(5) | — |
| — |
| — |
| — |
| — |
| — |
|
| $19,908 |
| |
Welfare Benefits(6) | | Welfare Benefits(6) | — | | — | | — | | — | | — | | — | | $23,850 | |
Unvested Restricted Stock Units(11) | | Unvested Restricted Stock Units(11) | — | | — | | — | | — | | — | | — | | $2,026,350 | |
(1)As of December 31, 2022, Mr. Denault, Mr. Fisackerly, Mr. May, and Ms. Rodriguez were retirement eligible and would retire rather than voluntarily resign, and in addition to the payments and benefits in the table, each also would be entitled to receive their vested pension benefits under the Entergy Retirement Plan and their benefit under the PEP or the SERP, to the extent applicable, the latter of which requires the prior written consent of the officer’s Entergy employer to separate prior to age 65. As previously discussed, Mr. Denault did not participate in the PEP as of December 31, 2022 and Ms. Rodriguez does not participate in the SERP. For a description of these benefits, see “2022 Pension Benefits.” Mr. Denault retired and separated from employment with the Company on January 31, 2023.
|
| | | | | | | | | | | | | | | | | | |
| Benefits and Payments Upon Termination | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement | Disability | Death | Termination Related to a Change in Control |
Andrew S. Marsh(1) | | | | | | | |
| Severance Payment | — |
| — |
| — |
| — |
| — |
| — |
|
| $3,315,000 |
|
Performance Units(3) | — |
| — |
| — |
| — |
|
| $1,105,035 |
|
| $1,105,035 |
|
| $1,964,720 |
|
| Stock Options | — |
| — |
| — |
| — |
|
| $3,468,531 |
|
| $3,468,531 |
|
| $3,468,531 |
|
| Restricted Stock | — |
| — |
| — |
| — |
|
| $1,279,045 |
|
| $1,279,045 |
|
| $1,279,045 |
|
Welfare Benefits(5) | — |
| — |
| — |
| — |
| — |
| — |
|
| $29,862 |
|
Unvested Restricted Stock Units(8) | — |
| — |
| — |
| — |
|
| $2,527,780 |
|
| $2,527,780 |
|
| $2,527,780 |
|
| | | | | | | | |
Phillip R. May, Jr.(2) | | | | | | | |
| Severance Payment | — |
| — |
| — |
| — |
| — |
| — |
|
| $1,254,536 |
|
Performance Units(3) | — |
| — |
| — |
|
| $289,557 |
|
| $289,557 |
|
| $289,557 |
|
| $646,920 |
|
| Stock Options | — |
| — |
| — |
|
| $732,470 |
|
| $732,470 |
|
| $732,470 |
|
| $732,470 |
|
| Restricted Stock | — |
| — |
| — |
| — |
|
| $247,721 |
|
| $247,721 |
|
| $247,721 |
|
Welfare Benefits(6) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| | | | | | | | |
Sallie T. Rainer(2) | | | | | | | |
| Severance Payment | — |
| — |
| — |
| — |
| — |
| — |
|
| $486,390 |
|
Performance Units(3) | — |
| — |
| — |
|
| $189,763 |
|
| $189,763 |
|
| $189,763 |
|
| $431,280 |
|
| Stock Options | — |
| — |
| — |
|
| $501,452 |
|
| $501,452 |
|
| $501,452 |
|
| $501,452 |
|
| Restricted Stock | — |
| — |
| — |
| — |
|
| $184,210 |
|
| $184,210 |
|
| $184,210 |
|
Welfare Benefits(6) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| | | | | | | | |
Roderick K. West(1) | | | | | | | |
| Severance Payment | — |
| — |
| — |
| — |
| — |
| — |
|
| $3,641,466 |
|
Performance Units(3) | — |
| — |
| — |
| — |
|
| $1,033,275 |
|
| $1,033,275 |
|
| $1,964,720 |
|
| Stock Options | — |
| — |
| — |
| — |
|
| $2,835,460 |
|
| $2,835,460 |
|
| $2,835,460 |
|
| Restricted Stock | — |
| — |
| — |
| — |
|
| $1,064,329 |
|
| $1,064,329 |
|
| $1,064,329 |
|
Welfare Benefits(5) | — |
| — |
| — |
| — |
| — |
| — |
|
| $29,862 |
|
| |
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(3)Pursuant to Mr. Denault’s retention agreement, if Mr. Denault’s employment were terminated by his Entergy employer without cause or by Mr. Denault for good reason (as those terms are defined in his retention agreement), he would receive a Target PUP Award equal to that number of PUP performance units calculated by taking an average of the target PUP performance units from the 2018 – 2020 PUP Performance Period (42,700) and from the 2019 – 2021 PUP Performance Period (40,508), which amounts to 41,604 performance units. For purposes of the table, the value of such PUP performance units is calculated by multiplying 41,604 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 |
the closing price of Entergy stock on December 31, 201930, 2022 ($119.80)112.50), which equals $4,680,450. In the event of death or disability, Mr. Denault would equalreceive the greater of the Target PUP Award calculated as described immediately above or the sum of the prorated amounts that would be payable under the provisions of each performance period, as described in footnote 4 below. Mr. Denault retired and separated from employment with the Company on January 31, 2023.
(4)For purposes of the table, in the event of a paymentqualifying termination related to a change in control, each NEO, other than Mr. Denault, would receive a number of $215,640 for the forfeited performance units for eachthe 2021 – 2023 performance period.period and a number of performance units for the 2022 – 2024 performance period, calculated as follows:
The greater of (1) the target number of performance units subject to the performance unit agreements or (2) the number of performance units that would vest under the performance unit agreements calculated based on Entergy Corporation’s actual performance through the NEO’s termination date, in either case pro-rated based on the portion of the performance periods that occurs through the termination date.
Mr. Denault would receive the greater of the number of performance units calculated as described in the paragraph above or the Target PUP Award calculated as described in footnote 3 immediately above.
For purposes of the table, the values of the performance unit awards payable infor the performance periods for each NEO were calculated as follows, based on the assumption that the target number of performance units was the greater number:
Mr. Bakken’s:
2021 – 2023 PUP Performance Period: 6,504 (24/36*9,755) performance units at target, assuming a stock price of $112.50 = $731,700
2022 – 2024 PUP Performance Period: 2,375 (12/36*7,125) performance units at target, assuming a stock price of $112.50 = $267,188
Total: $998,888
Mr. Denault’s:
2021 – 2023 PUP Performance Period: 34,910 (24/36*52,365) performance units at target, assuming a stock price of $112.50 = $3,927,375
2022 – 2024 PUP Performance Period: 13,958 (12/36*41,874) performance units at target, assuming a stock price of $112.50 = $1,570,275
Total: $5,497,650
Ms. Fontan’s:
2021 – 2023 PUP Performance Period: 2,786 (24/36*4,179) performance units at target, assuming a stock price of $112.50 = $313,425
2022 – 2024 PUP Performance Period: 1,768 (12/36*5,302) performance units at target, assuming a stock price of $112.50 = $198,900
Total: $512,325
Mr. Fisackerly’s:
2021 – 2023 PUP Performance Period: 1,260 (24/36*1,889) performance units at target, assuming a stock price of $112.50 = $141,750
2022 – 2024 PUP Performance Period: 504 (12/36*1,510) performance units at target, assuming a stock price of $112.50 = $56,700
Total: $198,450
Ms. Landreaux’s:
2021 – 2023 PUP Performance Period: 1,228 (24/36*1,841) performance units at target, assuming a stock price of $112.50 = $138,150
2022 – 2024 PUP Performance Period: 590 (12/36*1,769) performance units at target, assuming a stock price of $112.50 = $66,375
Total: $204,525
Mr. Marsh’s:
2021 – 2023 PUP Performance Period: 13,911 (24/36*20,866) performance units at target, assuming a stock price of $112.50 = $1,564,988
2022 – 2024 PUP Performance Period: 7,706 (12/36*23,118) performance units at target, assuming a stock price of $112.50 = $866,925
Total: $2,431,913
Mr. May’s:
2021 – 2023 PUP Performance Period: 1,442 (24/36*2,162) performance units at target, assuming a stock price of $112.50 = $162,225
2022 – 2024 PUP Performance Period: 957 (12/36*2,871) performance units at target, assuming a stock price of $112.50 = $107,663
Total: $269,888
Ms. Rodriguez’s:
2021 – 2023 PUP Performance Period: 1,072 (24/36*1,608) performance units at target, assuming a stock price of $112.50 = $120,600
2022 – 2024 PUP Performance Period: 418 (12/36*1,254) performance units at target, assuming a stock price of $112.50 = $47,025
Total: $167,625
Mr. Viamontes’:
2021 – 2023 PUP Performance Period: 1,292 (24/36*1,938) performance units at target, assuming a stock price of $112.50 = $145,350
2022 – 2024 PUP Performance Period: 526 (12/36*1,577) performance units at target, assuming a stock price of $112.50 = $59,175
Total: $204,525
Mr. West’s:
2021 – 2023 PUP Performance Period: 7,152 (24/36*10,727) performance units at target, assuming a stock price of $112.50 = $804,600
2022 – 2024 PUP Performance Period: 3,175 (12/36*9,525) performance units at target, assuming a stock price of $112.50 = $357,188
Total: $1,161,788
In the event of retirement, in the case of Mr. Brown,Denault, Mr. Denault,Fisackerly, Mr. May, or Ms. RainerRodriguez each would receive a prorated portion of the applicable Achievement Level of PUP Performance Units for each open PUP Performance Period, based on his or uponher full months of participation in such PUP Performance Period, provided he or she has completed a minimum of 12 months of full-time employment in the applicable PUP Performance Period. For purposes of calculating for the above table the number of performance units Mr. Denault, Mr. Fisackerly, Mr. May, and Ms. Rodriguez would receive in the event of retirement, it is assumed the achievement levels for the 2021 – 2023 PUP Performance Period and the 2022 – 2024 PUP Performance Period are at target. The resulting number of performance units and values are the same as calculated above for a qualifying termination related to a change in control.
In the event of death or disability of any NEO, other than Mr. Denault, the NEO or his or her estate would receive a prorated portion of the applicable Achievement Level of PUP Performance Units for each Namedopen PUP Performance Period, based on his or her full months of participation in such PUP Performance Period, with no required minimum amount of full-time employment in the applicable PUP Performance Period.
In the event of death or disability of Mr. Denault, he or his estate would receive the greater of (1) the Target PUP Award under his retention agreement, calculated by using the average annual number of PUP Performance Units with respect to the two most recent PUP Performance Periods preceding the calendar year in which his employment terminates due to death or disability, assuming all performance goals were achieved at target, or (2) the prorated portion of the applicable Achievement Level of PUP Performance Units for each open PUP Performance Period, based on his full months of participation in such PUP Performance Period.
(5)Upon retirement, Mr. Denault, Mr. Fisackerly, Mr. May, and Ms. Rodriguez would be eligible for retiree medical and dental benefits, the same as all other retirees.
(6)Pursuant to the Executive Continuity Plan, in the event of a termination related to a Change in Control, Mr. Bakken, Ms. Fontan, Ms. Landreaux, Mr. Marsh, Mr. Viamontes, and Mr. West would be eligible to receive Entergy-subsidized COBRA benefits for 18 months.
(7)Mr. Bakken’s 10,000 restricted stock units vest on April 6, 2025. Pursuant to his restricted stock unit agreement, if he resigns and terminates his employment after April 6, 2022 and prior to April 6, 2025, the Chief Executive Officer, were calculated as follows:subject to the approval of the Talent and Compensation Committee, may provide that Mr. Bakken shall vest upon his termination in a Pro Rata Portion of the restricted units. The Pro Rata Portion is determined by multiplying 10,000 restricted units by a fraction, the numerator of which is the number of days
after April 6, 2022 that precede the effective date of his termination of employment and the denominator of which is 1,096. In the event of a change in control, the unvested restricted stock units will fully vest upon Mr. Denault’s: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.
2018-2020 Performance Period: 28,467 (24/36 × 42,700) performance units at target, assuming a stock price of $119.80
2019-2021 Performance Period: 13,503 (12/36 × 40,508) performance units at target, assuming a stock price of $119.80
Mr. Bakken’s:
2018-2020 Performance Period: 5,267 (24/36 × 7,900) performance units at target, assuming a stock price of $119.80
2019-2021 Performance Period: 3,190 (12/36 × 9,568) performance units at target, assuming a stock price of $119.80
Mr. Brown’s:
2018-2020 Performance Period: 5,267 (24/36 × 7,900) performance units at target, assuming a stock price of $119.80
2019-2021 Performance Period: 3,128 (12/36 ×9,383) performance units at target, assuming a stock price of $119.80
Mr. Marsh’s:
2018-2020 Performance Period: 5,267 (24/36 × 7,900) performance units at target, assuming a stock price of $119.80
2019-2021 Performance Period: 3,957 (12/36 × 11,869) performance units at target, assuming a stock price of $119.80
Mr. West’s:
2018-2020 Performance Period: 5,267 (24/36 × 7,900) performance units at target, assuming a stock price of $119.80
2019-2021 Performance Period: 3,358 (12/36 × 10,073) performance units at target, assuming a stock price of $119.80
Mr. May’s:
2018-2020 Performance Period: 1,700 (24/36 × 2,550) performance units at target, assuming a stock price of $119.80
2019-2021 Performance Period: 717 (12/36 × 2,150) performance units at target, assuming a stock price of $119.80
(8)Mr. Fisackerly’s 4,053 restricted stock units are scheduled to vest 100% on October 1, 2025. In the event of a Change in Control, the unvested restricted stock units will fully vest upon Mr. Fisackerly’s Qualifying Termination during a change in control period. Pursuant to his restricted stock unit agreement, Mr. Fisackerly is subject to certain restrictions on his ability to compete with Entergy and Ms. Rainer’s: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. Fisackerly’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. Fisackerly 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.
2018-2020 Performance Period: 1,100 (24/36 × 1,650) performance
(9)Mr. May’s 4,053 restricted stock units at target, assumingare scheduled to vest 100% on October 1, 2025. In the event of a Change in Control, the unvested restricted stock priceunits will fully vest upon Mr. May’s Qualifying Termination during a change in control period. Pursuant to his restricted stock unit agreement, Mr. May 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. May’s ability to disparage Entergy and its affiliates. In the event of $119.80a breach of these restrictions, other than following certain constructive terminations of his employment, Mr. May 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.
2019-2021 Performance Period: 484 (12/36 × 1,450) performance
(10)333 of Mr. Viamontes’ restricted stock units at target, assumingvested on February 1, 2022; the remaining 334 restricted stock vested on February 1, 2023. In the event of a Change in Control, the unvested restricted stock priceunits will fully vest upon Mr. Viamontes’ Qualifying Termination during a change in control period. Pursuant to his restricted stock unit agreement, Mr. Viamontes 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 12 months after his employment with Entergy. In addition, the restricted stock unit agreement limits Mr. Viamontes’ ability to disparage Entergy and its affiliates. In the event of $119.80a breach of these restrictions, other than following certain constructive terminations of his employment, Mr. Viamontes 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.
Ms. Landreaux’s:
2018-2020 Performance Period: 917 (24/36 × 1,375) performance(11)Mr. West’s 18,012 restricted stock units at target, assumingare scheduled to vest in three equal installments on June 1, 2024, June 1, 2025, and June 1, 2026. In the event of a Change in Control, the unvested restricted stock priceunits will fully vest upon Mr. West’s Qualifying Termination during a change in control period. Pursuant to his restricted stock unit agreement, Mr. West 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. West’s ability to disparage Entergy and its affiliates. In the event of $119.80a breach of these restrictions, other than following certain constructive terminations of his employment, Mr. West 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.
2019-2021 Performance Period: 484 (12/36 × 1,450) performance units at target, assuming a stock price of $119.80
Mr. Ellis’s:
2018-2020 Performance Period: 734 (24/36 × 1,100) performance units at target, assuming a stock price of $119.80
2019-2021 Performance Period: 484 (12/36 × 1,450) performance units at target, assuming a stock price of $119.80
| |
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. |
Pay Ratio
As required by Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, the following disclosure is being provided about the relationship of the annual total compensation of the employees of each of the Utility operating companies to the annual total compensation of their respective Presidents and Chief Executive Officers. The pay ratio estimate for each of the Utility operating companies has been calculated in a manner consistent with Item 402(u) of Regulation S-K.
Identification of Median Employee
For each of the Utility operating companies, October 4, 201921, 2022 was selected as the date on which to determine the median employee. This date is different from the date used in the prior year; however, the methodology used to determine
the date is consistent with that used in the prior year. Both dates correspond to the first day of the three month period prior to fiscal year-end for which information can be obtained about employees and all subsidiaries have the same number of pay cycles. To identify the median employee from each of the Utility operating companies’ employee population base, all compensation included in Box 5 of Form W-2 was considered with all before-tax deductions added back to this compensation (“Box 5 Compensation”). For purposes of determining the median employee of each Utility operating company, Box 5 Compensation was selected as it is believed it isto be representative of the compensation received by the employees of each respective Utility operating company and is readily available. The calculation of annual total compensation of the median employee for each Utility operating company is the same calculation used to determine total compensation for purposes of the 20192022 Summary Compensation Table with respect to each of the Named Executive Officers.NEOs.
Entergy Arkansas Ratio
For 2019,2022,
| |
• | •The median of the annual total compensation of all of EntergyArkansas’semployees, other than Ms. Landreaux, was $124,306. •Arkansas’semployees, other than Ms. Landreaux, was $230,966. |
Ms. Landreaux’s annual total compensation, as reported in the Total column of the 20192022 Summary Compensation Table, was $1,064,459.$1,090,465.
•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 5:9:1.
Entergy Louisiana Ratio
For 2019,2022,
•The median of the annual total compensation of all of Entergy Louisiana’s employees, other than Mr. May, was $173,745.$132,014.
•Mr. May’s annual total compensation, as reported in the Total column of the 20192022 Summary Compensation Table, was $2,073,894.$1,875,055.
•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 12:14:1.
Entergy Mississippi Ratio
For 2019,2022,
•The median of the annual total compensation of all of Entergy Mississippi’s employees, other than Mr. Fisackerly, was $254,843.$122,637.
•Mr. Fisackerly’s annual total compensation, as reported in the Total column of the 20192022 Summary Compensation Table, was $1,579,844.$1,591,069.
•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 6:13:1.
Entergy New Orleans Ratio
For 2019,2022,
| |
• | The median of the annual total compensation of all of EntergyNew Orleans’semployees, other than Mr. Ellis, was $145,217.
|
Mr. Ellis’s•The median of the annual total compensation of all of EntergyNew Orleans’semployees, other than Ms. Rodriguez, was $109,847.
•Ms. Rodriguez’s annual total compensation, as reported in the Total column of the 20192022 Summary Compensation Table, was $732,040.$895,489.
•Based on this information, the ratio of the annual total compensation of Mr. EllisMs. Rodriguez to the median of the annual total compensation of all employees is estimated to be 5:8:1.
Entergy Texas Ratio
For 2019,2022,
•The median of the annual total compensation of all of Entergy Texas’s employees, other than Ms. Rainer,Mr. Viamontes, was $233,988.$121,845.
Ms. Rainer’s•Mr. Viamontes’ annual total compensation, as reported in the Total column of the 20192022 Summary Compensation Table, was $1,467,716.$1,118,688.
•Based on this information, the ratio of the annual total compensation of Ms. RainerMr. Viamontes to the median of the annual total compensation of all employees is estimated to be 6:9:1.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Entergy Corporation owns 100% of the outstanding common stock of registrant Entergy Texas and indirectly 100% of the outstanding common membership interests of registrants Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. The information with respect to (i) the beneficial ownership of Entergy Corporation’s directors and NEOs is included under the heading “Entergy Share Ownership - Directors and Executive Officers;” and (ii) persons known by Entergy Corporation to be beneficial owners of more than 5% of Entergy Corporation’s outstanding common stock is included under the heading “Entergy Share Ownership - Beneficial Owners of More Than Five Percent of Entergy Common Stock” in the 2023 Entergy Corporation Proxy Statement, which information is incorporated herein by reference. The registrants know of no contractual arrangements that may, at a subsequent date, result in a change in control of any of the registrants.
The following table sets forth the beneficial ownership of common stock of Entergy Corporation and stock-based units as of January 31, 20202023 for allthe directors and Named Executive Officers.NEOs of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas. Unless otherwise noted, each person had sole voting and investment power over the number of shares of common stock and stock-based units of Entergy Corporation set forth across from his or her name.
| | | | | | | | | | | | | | | | | | | | |
| Name | | Shares (1) | | Options Exercisable Within 60 Days | | Stock Units (2) |
| Entergy Arkansas | | | | | | |
| A. Christopher Bakken, III** | | 34,586 | | | 89,447 | | | — | |
| Leo P. Denault** | | 403,849 | | | 997,016 | | | — | |
| Kimberly A. Fontan*** | | 10,027 | | | 20,181 | | | — | |
| Laura R. Landreaux*** | | 6,480 | | | 13,266 | | | — | |
| Andrew S. Marsh** | | 120,777 | | | 271,218 | | | — | |
| Peter S. Norgeot, Jr. * | | 28,988 | | | 50,303 | | | — | |
| Roderick K. West*** | | 48,367 | | | 97,516 | | | — | |
| All directors and executive officers as a group (10 persons) | | 694,470 | | | 1,647,617 | | | — | |
| | | | | | |
| Entergy Louisiana | | | | | | |
| A. Christopher Bakken, III** | | 34,586 | | | 89,447 | | | — | |
| Leo P. Denault** | | 403,849 | | | 997,016 | | | — | |
| Kimberly A. Fontan*** | | 10,027 | | | 20,181 | | | — | |
| Andrew S. Marsh** | | 120,777 | | | 271,218 | | | — | |
| Phillip R. May, Jr.*** | | 21,221 | | | 19,579 | | | 14 | |
| Peter S. Norgeot, Jr. * | | 28,988 | | | 50,303 | | | — | |
| Roderick K. West*** | | 48,367 | | | 97,516 | | | — | |
| All directors and executive officers as a group (10 persons) | | 709,211 | | | 1,653,930 | | | 14 | |
| | | | | | |
| Entergy Mississippi | | | | | | |
| A. Christopher Bakken, III** | | 34,586 | | | 89,447 | | | — | |
| Leo P. Denault** | | 403,849 | | | 997,016 | | | — | |
| Haley R. Fisackerly*** | | 7,859 | | | 14,652 | | | — | |
| Kimberly A. Fontan*** | | 10,027 | | | 20,181 | | | — | |
| Andrew S. Marsh** | | 120,777 | | | 271,218 | | | — | |
| Peter S. Norgeot, Jr. * | | 28,988 | | | 50,303 | | | — | |
| Roderick K. West*** | | 48,367 | | | 97,516 | | | — | |
| All directors and executive officers as a group (9 persons) | | 683,240 | | | 1,630,090 | | | — | |
|
| | | | | | | | | |
| Name | | Shares (1)(2) | | Options Exercisable Within 60 Days | | Stock Units (3) |
| Entergy Corporation | | | | | | |
| A. Christopher Bakken, III** | | 38,397 |
| | 38,174 |
| | — |
|
| Marcus V. Brown** | | 44,758 |
| | 40,075 |
| | — |
|
| John R. Burbank* | | 2,417 |
| | — |
| | — |
|
| Patrick J. Condon* | | 7,834 |
| | — |
| | — |
|
| Leo P. Denault*** | | 265,416 |
| | 753,202 |
| | — |
|
| Kirkland H. Donald* | | 7,721 |
| | — |
| | 2,949 |
|
| Philip L. Frederickson* | | 6,284 |
| | — |
| | 805 |
|
| Alexis M. Herman* | | 14,506 |
| | — |
| | — |
|
| M. Elise Hyland* | | 727 |
| | | | |
| Stuart L. Levenick* | | 21,421 |
| | — |
| | — |
|
| Blanche L. Lincoln* | | 14,879 |
| | — |
| | — |
|
| Andrew S. Marsh** | | 86,740 |
| | 241,726 |
| | — |
|
| Karen A. Puckett* | | 7,834 |
| | — |
| | — |
|
| Roderick K. West** | | 64,999 |
| | 97,249 |
| | — |
|
| All directors and executive officers as a group (19 persons) | | 656,574 |
| | 1,273,794 |
| | 3,754 |
|
| | | | | | | |
| Entergy Arkansas | | |
| | |
| | |
|
| A. Christopher Bakken, III** | | 38,397 |
| | 38,174 |
| | — |
|
| Marcus V. Brown** | | 44,758 |
| | 40,075 |
| | — |
|
| Leo P. Denault** | | 265,416 |
| | 753,202 |
| | — |
|
| Andrew S. Marsh*** | | 86,740 |
| | 241,726 |
| | — |
|
| Laura R. Landreaux*** | | 5,866 |
| | 1,700 |
| | — |
|
| Roderick K. West*** | | 64,999 |
| | 97,249 |
| | — |
|
| All directors and executive officers as a group (8 persons) | | 555,420 |
| | 1,242,596 |
| | — |
|
| | | | | | | |
| Entergy Louisiana | | | | | | |
| A. Christopher Bakken, III** | | 38,397 |
| | 38,174 |
| | — |
|
| Marcus V. Brown** | | 44,758 |
| | 40,075 |
| | — |
|
| Leo P. Denault** | | 265,416 |
| | 753,202 |
| | — |
|
| Andrew S. Marsh*** | | 86,740 |
| | 241,726 |
| | — |
|
| Phillip R. May, Jr.*** | | 25,880 |
| | 13,900 |
| | 13 |
|
| Roderick K. West*** | | 64,999 |
| | 97,249 |
| | — |
|
| All directors and executive officers as a group (8 persons) | | 575,434 |
| | 1,254,796 |
| | 13 |
|
|
| | | | | | | | | |
| Name | | Shares (1)(2) | | Options Exercisable Within 60 Days | | Stock Units (3) |
| Entergy Mississippi | | | | | | |
| Marcus V. Brown** | | 44,758 |
| | 40,075 |
| | — |
|
| Leo P. Denault** | | 265,416 |
| | 753,202 |
| | — |
|
| Haley R. Fisackerly*** | | 9,847 |
| | 6,800 |
| | — |
|
| Andrew S. Marsh*** | | 86,740 |
| | 241,726 |
| | — |
|
| Roderick K. West*** | | 64,999 |
| | 97,249 |
| | — |
|
| All directors and executive officers as a group (7 persons) | | 521,004 |
| | 1,209,522 |
| | — |
|
| | | | | | | |
| Entergy New Orleans | | | | | | |
| Marcus V. Brown** | | 44,758 |
| | 40,075 |
| | — |
|
| Leo P. Denault** | | 265,416 |
| | 753,202 |
| | — |
|
| David D. Ellis*** | | 1,812 |
| | 1,566 |
| | — |
|
| Andrew S. Marsh*** | | 86,740 |
| | 241,726 |
| | — |
|
| Roderick K. West*** | | 64,999 |
| | 97,249 |
| | — |
|
| All directors and executive officers as a group (7 persons) | | 512,969 |
| | 1,204,288 |
| | — |
|
| | | | | | | |
| Entergy Texas | | | | | | |
| Marcus V. Brown** | | 44,758 |
| | 40,075 |
| | — |
|
| Leo P. Denault** | | 265,416 |
| | 753,202 |
| | — |
|
| Andrew S. Marsh*** | | 86,740 |
| | 241,726 |
| | — |
|
| Sallie T. Rainer*** | | 10,799 |
| | 6,866 |
| | — |
|
| Roderick K. West*** | | 64,999 |
| | 97,249 |
| | — |
|
| All directors and executive officers as a group (7 persons) | | 521,956 |
| | 1,209,588 |
| | — |
|
| | | | | | | | | | | | | | | | | | | | |
| Name | | Shares (1) | | Options Exercisable Within 60 Days | | Stock Units (2) |
| Entergy New Orleans | | | | | | |
| A. Christopher Bakken, III** | | 34,586 | | | 89,447 | | | — | |
| Leo P. Denault** | | 403,849 | | | 997,016 | | | — | |
| Kimberly A. Fontan** | | 10,027 | | | 20,181 | | | — | |
| Andrew S. Marsh** | | 120,777 | | | 271,218 | | | — | |
| Peter S. Norgeot, Jr. * | | 28,988 | | | 50,303 | | | — | |
| Deanna D. Rodriguez*** | | 7,515 | | | 991 | | | — | |
| Roderick K. West*** | | 48,367 | | | 97,516 | | | — | |
| All directors and executive officers as a group (9 persons) | | 682,896 | | | 1,616,429 | | | — | |
| | | | | | |
| Entergy Texas | | | | | | |
| A. Christopher Bakken, III** | | 34,586 | | | 89,447 | | | — | |
| Leo P. Denault** | | 403,849 | | | 997,016 | | | — | |
| Kimberly A. Fontan*** | | 10,027 | | | 20,181 | | | — | |
| Andrew S. Marsh** | | 120,777 | | | 271,218 | | | — | |
| Peter S. Norgeot, Jr. * | | 28,988 | | | 50,303 | | | — | |
| Eliecer Viamontes*** | | 4,805 | | | 3,986 | | | — | |
| Roderick K. West*** | | 48,367 | | | 97,516 | | | — | |
| All directors and executive officers as a group (9 persons) | | 680,186 | | | 1,619,424 | | | — | |
|
| | | | |
| * | Director of the respective Companycompany |
| ** | Named Executive OfficerNEO of the respective Companycompany |
| *** | Director and Named Executive OfficerNEO of the respective Companycompany |
| |
(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. |
(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)Represents the balances of phantom units each director or 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.
Equity Compensation Plan Information
The following table summarizes the equity compensation plan information as of December 31, 2019.2022. Information is included for equity compensation plans approved by the shareholders. There are no shares authorized for issuance under equity compensation plans not approved by the shareholders.
| | | Plan | | Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (a) | | Weighted Average Exercise Price (b)(2) | | Number of Securities Remaining Available for Future Issuance (excluding securities reflected in column (a))(c) | |
| Plan Category | | Plan Category | | Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants, and Rights (a) | | Weighted Average Exercise Price of Outstanding Options, Warrants, and Rights (b)(2) | | Number of Securities Remaining Available for Future Issuance under Equity Compensation Plans (excluding securities reflected in column (a))
(c) |
Equity compensation plans approved by security holders (1) | | 2,448,913 |
| | $78.48 | | 7,266,822 |
| Equity compensation plans approved by security holders (1) | | 2,776,355 | | | $96.30 | | 3,572,261 | |
| Equity compensation plans not approved by security holders | | — |
| | — |
| | — |
| Equity compensation plans not approved by security holders | | — | | | — | | | — | |
| Total | | 2,448,913 |
| | $78.48 | | 7,266,822 |
| Total | | 2,776,355 | | | $96.30 | | 3,572,261 | |
| |
(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. |
(1)Includes the 2011 Equity Ownership Plan, the 2015 EOP, and the 2019 OIP (collectively, the “Plans”). The 2011 Equity Ownership Plan was approved by Entergy Corporation shareholders on May 6, 2011 and only applies to awards granted between May 6, 2011 and May 7, 2015. The 2015 EOP was approved by Entergy Corporation shareholders on May 8, 2015 and only applies to awards granted between May 8, 2015 and May 3, 2019. The Entergy Corporation shareholders approved the 2019 OIP on May 3, 2019 and approved the issuance of 7,300,000 shares of Entergy Corporation common stock from the 2019 OIP for equity-based incentive awards. The Plans are administered by the Talent and Compensation Committee of the Entergy Corporation 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.
Item 13. Certain Relationships and Related Party Transactions and Director Independence
ForThe additional information regarding certain relationship, related transactionsrequired by this item will be set forth under Director Independence and director independence of Entergy Corporation, see the Entergy Corporation Proxy Statement under the headings “Corporate Governance at Entergy - Director Independence” and “Corporate Governance - Corporate Governance Policies - Review and Approval of Related Party Transactions.”
Entergy Corporation’s Board of Directors has adopted a written Related Party Transaction Approval Policy that applies:
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).
The policy is administered by Entergy Corporation’s Corporate Governance Committee. The committee will consider relevant facts and circumstance in determining whether or not to approve or ratify such a transaction, and will approve or ratify only those transactions that are,Transactions in the Corporate Governance Committee’s judgment, appropriate or desirable under2023 Entergy Proxy Statement, to be filed in connection with the circumstances. The Corporate Governance Committee has determined that certain typesAnnual Meeting of transactions do not create or involve a direct or indirect material interest, including (i) compensation and related party transactions involving a director or an executive officer solely resulting from service as a director or employment with Entergy Corporation so long as the compensationShareholders to be held May 5, 2023, which is approvedincorporated herein by the Entergy Corporation Boardreference.
Item 14. Principal Accountant Fees and Services (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Aggregate fees billed to Entergy Corporation (consolidated), Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy for the years ended December 31, 20192022 and 20182021 by Deloitte & Touche LLP (PCAOB ID No. 34) were as follows:
| | | | | | | | | | | |
| | 2022 | | 2021 |
| Entergy Corporation (consolidated) | | | |
| Audit Fees | $9,335,000 | | | $9,030,000 | |
| Audit-Related Fees (a) | 3,018,228 | | | 1,634,175 | |
| Total audit and audit-related fees | 12,353,228 | | | 10,664,175 | |
| Tax Fees | — | | | — | |
| All Other Fees (b) | 1,895 | | | 392,895 | |
| Total Fees (c) | $12,355,123 | | | $11,057,070 | |
| Entergy Arkansas | | | |
| Audit Fees | $1,215,943 | | | $1,086,857 | |
| Audit-Related Fees (a) | — | | | — | |
| Total audit and audit-related fees | 1,215,943 | | | 1,086,857 | |
| Tax Fees | — | | | — | |
| All Other Fees | — | | | — | |
| Total Fees (c) | $1,215,943 | | | $1,086,857 | |
| Entergy Louisiana | | | |
| Audit Fees | $2,136,886 | | | $2,163,714 | |
| Audit-Related Fees (a) | 1,472,751 | | | 783,092 | |
| Total audit and audit-related fees | 3,609,637 | | | 2,946,806 | |
| Tax Fees | — | | | — | |
| All Other Fees | — | | | — | |
| Total Fees (c) | $3,609,637 | | | $2,946,806 | |
| Entergy Mississippi | | | |
| Audit Fees | $1,025,943 | | | $1,121,857 | |
| Audit-Related Fees (a) | — | | | — | |
| Total audit and audit-related fees | 1,025,943 | | | 1,121,857 | |
| Tax Fees | — | | | — | |
| All Other Fees | — | | | — | |
| Total Fees (c) | $1,025,943 | | | $1,121,857 | |
| Entergy New Orleans | | | |
| Audit Fees | $1,110,943 | | | $1,096,857 | |
| Audit-Related Fees (a) | 785,477 | | | 212,896 | |
| Total audit and audit-related fees | 1,896,420 | | | 1,309,753 | |
| Tax Fees | — | | | — | |
| All Other Fees | — | | | — | |
| Total Fees (c) | $1,896,420 | | | $1,309,753 | |
| | | | | | | | 2022 | | 2021 |
| | 2019 | | 2018 | |
| Entergy Corporation (consolidated) | | | | |
| Entergy Texas | | Entergy Texas | | | |
| Audit Fees |
| $8,710,000 |
| |
| $8,801,895 |
| Audit Fees | $1,410,943 | | | $1,131,857 | |
| Audit-Related Fees (a) | 775,000 |
| | 1,067,119 |
| Audit-Related Fees (a) | 300,000 | | | 252,187 | |
| Total audit and audit-related fees | 9,485,000 |
| | 9,869,014 |
| Total audit and audit-related fees | 1,710,943 | | | 1,384,044 | |
| Tax Fees | — |
| | — |
| Tax Fees | — | | | — | |
| All Other Fees | 31,835 |
| | — |
| All Other Fees | — | | | — | |
| Total Fees (b) |
| $9,516,835 |
| |
| $9,869,014 |
| |
| Entergy Arkansas | | | | |
| Total Fees (c) | | Total Fees (c) | $1,710,943 | | | $1,384,044 | |
| System Energy | | System Energy | | | |
| Audit Fees |
| $1,015,125 |
| |
| $1,030,758 |
| Audit Fees | $1,025,943 | | | $1,046,857 | |
| Audit-Related Fees (a) | — |
| | — |
| Audit-Related Fees (a) | — | | | — | |
| Total audit and audit-related fees | 1,015,125 |
| | 1,030,758 |
| Total audit and audit-related fees | 1,025,943 | | | 1,046,857 | |
| Tax Fees | — |
| | — |
| Tax Fees | — | | | — | |
| All Other Fees | — |
| | — |
| All Other Fees | — | | | — | |
| Total Fees (b) |
| $1,015,125 |
| |
| $1,030,758 |
| |
| Entergy Louisiana | | | | |
| Audit Fees |
| $1,871,918 |
| |
| $1,916,517 |
| |
| Audit-Related Fees (a) | 360,000 |
| | 500,000 |
| |
| Total audit and audit-related fees | 2,231,918 |
| | 2,416,517 |
| |
| Tax Fees | — |
| | — |
| |
| All Other Fees | — |
| | — |
| |
| Total Fees (b) |
| $2,231,918 |
| |
| $2,416,517 |
| |
| Entergy Mississippi | | | | |
| Audit Fees |
| $1,005,125 |
| |
| $910,758 |
| |
| Audit-Related Fees (a) | — |
| | — |
| |
| Total audit and audit-related fees | 1,005,125 |
| | 910,758 |
| |
| Tax Fees | — |
| | — |
| |
| All Other Fees | — |
| | — |
| |
| Total Fees (b) |
| $1,005,125 |
| |
| $910,758 |
| |
| Total Fees (c) | | Total Fees (c) | $1,025,943 | | | $1,046,857 | |
(a)Includes fees for employee benefit plan audits, consultation on financial accounting and reporting, storm examination services in 2022 and 2021, agreed upon procedures for storm securitizations in 2022, and other attestation services. |
| | | | | | | |
| | 2019 | | 2018 |
| Entergy New Orleans | | | |
| Audit Fees |
| $950,125 |
| |
| $965,758 |
|
| Audit-Related Fees (a) | — |
| | — |
|
| Total audit and audit-related fees | 950,125 |
| | 965,758 |
|
| Tax Fees | — |
| | — |
|
| All Other Fees | — |
| | — |
|
| Total Fees (b) |
| $950,125 |
| |
| $965,758 |
|
| Entergy Texas | | | |
| Audit Fees |
| $1,165,125 |
| |
| $1,200,758 |
|
| Audit-Related Fees (a) | — |
| | — |
|
| Total audit and audit-related fees | 1,165,125 |
| | 1,200,758 |
|
| Tax Fees | — |
| | — |
|
| All Other Fees | — |
| | — |
|
| Total Fees (b) |
| $1,165,125 |
| |
| $1,200,758 |
|
| System Energy | | | |
| Audit Fees |
| $930,125 |
| |
| $850,758 |
|
| Audit-Related Fees (a) | — |
| | — |
|
| Total audit and audit-related fees | 930,125 |
| | 850,758 |
|
| Tax Fees | — |
| | — |
|
| All Other Fees | — |
| | — |
|
| Total Fees (b) |
| $930,125 |
| |
| $850,758 |
|
(c)100% of fees in 2022 and 2021 were pre-approved by the Entergy Corporation Audit Committee.
| |
(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. |
Entergy Audit Committee Guidelines for Pre-approval of Independent Auditor Services
The Audit Committee has adopted the following guidelines regarding the engagement of Entergy’s independent auditor to perform services for Entergy:
| |
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: |
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:
aAggregate non-audit service fees are targeted at fifty percent or less of the approved audit service fee.
bAll 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. |
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.
PART IV
Item 15. Exhibits and Financial Statement Schedules
|
| | | | |
| (a)1. | Financial Statements and Independent Auditors’ Reports for Entergy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are listed in the Table of Contents. |
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| (a)2. | Financial Statement Schedules |
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| Reports of Independent Registered Public Accounting Firm (see page 517)572) |
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| Financial Statement Schedules are listed in the Index to Financial Statement Schedules (see page S-1) |
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| (a)3. | Exhibits |
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| Exhibits for Entergy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are listed in the Exhibit Index (see page 494548 and are incorporated by reference herein). Each management contract or compensatory plan or arrangement required to be filed as an exhibit hereto is identified as such by footnote in the Exhibit Index. |
Item 16. Form 10-K Summary (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
None.
EXHIBIT INDEX
The following exhibits indicated by an asterisk preceding the exhibit number are filed herewith. The balance of the exhibits have previously been filed with the SEC as the exhibits and in the file numbers indicated and are incorporated herein by reference. The exhibits marked with a (+) are management contracts or compensatory plans or arrangements required to be filed herewith and required to be identified as such by Item 15 of Form 10-K.
Some of the agreements included or incorporated by reference as exhibits to this Form 10-K contain representations and warranties by each of the parties to the applicable agreement. These representations and warranties were made solely for the benefit of the other parties to the applicable agreement and (i) were not intended to be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate; (ii) may have been qualified in such agreement by disclosures that were made to the other party in connection with the negotiation of the applicable agreement; (iii) may apply contract standards of “materiality” that are different from the standard of “materiality” under the applicable securities laws; and (iv) were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement.
Entergy acknowledges that, notwithstanding the inclusion of the foregoing cautionary statements, it is responsible for considering whether additional specific disclosures of material information regarding material contractual provisions are required to make the statements in this Form 10-K not misleading.
(2) Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession
Entergy Arkansas
Entergy Louisiana
Entergy Mississippi
Entergy New Orleans
(3) Articles of Incorporation and Bylaws
Entergy Corporation
System Energy
Entergy Arkansas
Entergy Louisiana
Entergy Mississippi
Entergy New Orleans
Entergy Texas
(4)Instruments Defining Rights of Security Holders, Including Indentures
Entergy Corporation
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| (a) 1 -- | See (4)(b) through (4)(g) below for instruments defining the rights of security holders of System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas. |
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| (a) 2 -- | |
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| (a) 3 -- | |
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(a) 4 -- | |
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(a) 5 -- | |
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(a) 64 -- | |
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| (a) 5 -- | |
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| (a) 6 -- | |
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| (a) 7 -- | |
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Second(a) 8 -- | |
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| (a) 9 -- | |
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| (a) 10 -- | Third Amended and Restated Credit Agreement dated as of September 14, 2018,June 3, 2021, among Entergy Corporation, as Borrower, the banks and other financial institutions listed on the signatures pages thereof, as Lenders, Citibank, N.A., as Administrative Agent and LC Issuing Bank, MUFG Bank, Ltd., as LC Issuing Bank, and the other LC Issuing Banks from time to time parties thereto (4(g)(4.1 to Form 10-Q for the quarter ended September 30, 20188-K filed June 3, 2021 in 1-11299). |
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(a) 811 -- | First Extension and Amendment Agreement, dated September 13, 2019, to Secondas of June 3, 2022, amending the Third Amended and Restated Credit Agreement, dated as of September 14, 2018,June 3, 2021, among Entergy Corporation, as Borrower, the banksLenders and other financial institutions listed on the signature pages thereof, as Lenders,LC Issuing Banks parties thereto and Citibank, N.A., as Administrative Agent, as set forth in Exhibit A to the First Extension and LC Issuing Bank, MUFG Bank, Ltd., as LC Issuing Bank, and the other LC Issuing Banks from time to time parties thereto (4(a)Amendment Agreement(4(c) to Form 10-Q10-Q for the quarter ended SeptemberJune 30, 20192022 in 1-11299)1-11299). |
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*(a) 912 -- | |
System Energy
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| (b) 1 -- | |
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| (b) 2 -- | |
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| (b) 3 -- | |
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| (b) 4 -- | |
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| (b) 5 -- | |
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Entergy Arkansas
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| (b) 8 -- | |
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| (b) 9 -- | |
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| (b) 10 -- | |
Entergy Arkansas | | | | | |
| (c) 1 -- | Mortgage and Deed of Trust, dated as of October 1, 1944, as amended by the following Supplemental Indentures: (7(d) in 2-5463 (Mortgage); 7(b) in 2-7121 (First); 4(a)-7 in 2-10261 (Seventh); 2(b)-10 in 2-15767 (Tenth); 2(c) in 2-28869 (Sixteenth); 2(c) in 2-35107 (Eighteenth); 2(d) in 2-36646 (Nineteenth); 2(c) in 2-39253 (Twentieth); 4(c)1 to Form 10-K for the year ended December 31, 2017 in 1-10764 (Thirtieth); 4(c)1 to Form 10-K for the year ended December 31, 2017 in 1-10764 (Thirty-first); 4(c)1 to Form 10-K for the year ended December 31, 2017 in 1-10764 (Thirty-ninth); 4(c)1 to Form 10-K for the year ended December 31, 2017 in 1-10764 (Forty-first); 4(d)(2) in 33-54298 (Forty-sixth); C-2 to Form U5S for the year ended December 31,1995 (Fifty-third); 4(c)1 to Form 10-K for the year ended December 31, 2008 in 1-10764 (Sixty-eighth); 4.06 to Form 8-K filed October 8, 2010 in 1-10764 (Sixty-ninth); 4.06 to Form 8-K filed November 12, 2010 in 1-10764 (Seventieth); 4.06 to Form 8-K filed December 13, 2012 in 1-10764 (Seventy-first); 4(e) to Form 8-K filed January 9, 2013 in 1-10764 (Seventy-second); 4.06 to Form 8-K filed May 30, 2013 in 1-10764 (Seventy-third); 4.06 to Form 8-K filed June 4, 2013 in 1-10764 (Seventy-fourth); 4.05 to Form 8-K filed March 14, 2014 in 1-10764 (Seventy-sixth); 4.05 to Form 8-K filed December 9, 2014 in 1-10764 (Seventy-seventh); 4.05 to Form 8-K filed January 8, 2016 in 1-10764 (Seventy-eighth); 4.05 to Form 8-K filed August 16, 2016 in 1-10764 (Seventy-ninth); 4(a) to Form 10-Q for the quarter ended September 30, 2018 (Eightieth); 4.1 to Form 8-K12B filed December 3, 2018 in 1-10764 (Eighty-first); and 4.39 to Form 8-K filed March 19, 2019 in 1-10764 (Eighty-second);4.49 to Form 8-K filed September 11, 2020 in 1-10764 (Eighty-third); 4.49 to Form 8-K filed March 30, 2021 in 1-10764 (Eighty-fourth); and 4.66 to Form 8-K filed January 6, 2023 in 1-1-764 (Eighty-fifth)). |
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| (c) 2 -- | SecondThird Amended and Restated Credit Agreement dated as of September 14, 2018, among Entergy Arkansas, as Borrower, the banks and other financial institutions listed on the signature pages thereof, as Lenders, Citibank, N.A., as Administrative Agent, JPMorgan Chase Bank, N.A., as LC Issuing Bank, and the other LC Issuing Banks from time to time parties thereto (4(h) to Form 10-Q for the quarter ended September 30, 2018 in 1-10764). |
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(c)June 3, -- | Borrower Assumption Agreement dated as of November 30, 2018 of Entergy Arkansas Power, LLC under the Second Amended and Restated Credit Agreement dated as of September 14, 2018,2021, among Entergy Arkansas, as Borrower, the banks and other financial institutions listed on the signature pages thereof, as Lenders, Citibank, N.A., as Administrative Agent, JPMorgan Chase Bank, N.A., as LC Issuing Bank, and the other LC Issuing Banks from time to time parties thereto (4.2 to Form 8-K12B8-K filed DecemberJune 3, 20182021 in 1-10764). |
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(c) 43 -- | First Extension and Amendment Agreement, dated September 13, 2019, to Secondas of June 3, 2022, amending the Third Amended and Restated Credit Agreement, dated as of September 14, 2018, as supplemented by the Borrower Assumption Agreement of Entergy Arkansas Power, LLC dated as of November 30, 2018,June 3, 2021, among Entergy Arkansas, as Borrower, the banksLenders and other financial institutions listed on the signature pages thereof, as Lenders,LC Issuing Banks parties thereto and Citibank, N.A., as Administrative Agent, JPMorgan Chase Bank, N.A., as LC Issuing Bank,set forth in Exhibit A to the First Extension and the other LC Issuing Banks from time to time parties thereto (4(b)Amendment Agreement (4(d) to Form 10-Q10-Q for the quarter ended SeptemberJune 30, 20192022 in 1-10764)1-10764). |
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(c) 54 -- | |
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*(c) 65 -- | |
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*(c) 7 -- | |
Entergy Louisiana
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| (d) 1 -- | Mortgage and Deed of Trust, dated as of April 1, 1944, as amended by the following Supplemental Indentures: (7(d) in 2-5317 (Mortgage); 7(b) in 2-7408 (First); 4(d)1 to Form 10-K for the year ended December 31, 2017 in 1-32718 (Sixth); 2(c) in 2-34659 (Twelfth); 4(d)1 to Form 10-K for the year ended December 31, 2017 in 1-32718 (Thirteenth); 2(b)-2 in 2-38378 (Fourteenth); 4(d)1 to Form 10-K for the year ended December 31, 2017 in 1-32718 (Twenty-first); 4(d)1 to Form 10-K for the year ended December 31, 2017 in 1-32718 (Twenty-fifth); 4(d)1 to Form 10-K for the year ended December 31, 2017 in 1-32718 (Twenty-ninth); 4(d)1 to Form 10-K for the year ended December 31, 2017 in 1-32718 (Forty-second); A-2(a) to Rule 24 Certificate filed April 4, 1996 in 70-8487 (Fifty-first); B-4(i) to Rule 24 Certificate filed January 10, 2006 in 70-10324 (Sixty-third); B-4(ii) to Rule 24 Certificate filed January 10, 2006 in 70-10324 (Sixty-fourth); 4(a) to Form 10-Q for the quarter ended September 30, 2008 in 1-32718 (Sixty-fifth); 4(e)1 to Form 10-K for the year ended December 31, 2009 in 1-132718 (Sixty-sixth); 4.08 to Form 8-K filed September 24, 2010 in 1-32718 (Sixty-eighth); 4.08 to Form 8-K filed March 24, 2011 in 1-32718 (Seventy-first); 4(a) to Form 10-Q for the quarter ended June 30, 2011 in 1-32718 (Seventy-second); 4.08 to Form 8-K filed July 3, 2012 in 1-32718 (Seventy-fifth); 4.08 to Form 8-K filed December 4, 2012 in 1-32718 (Seventy-sixth); 4.08 to Form 8-K filed May 21, 2013 in 1-32718 (Seventy-seventh); 4.08 to Form 8-K filed August 23, 2013 in 1-32718 (Seventy-eighth); 4.08 to Form 8-K filed June 24, 2014 in 1-32718 (Seventy-ninth); 4.08 to Form 8-K filed July 1, 2014 in 1-32718 (Eightieth); 4.08 to Form 8-K filed November 21, 2014 (Eighty-first); 4.1 to Form 8-K12B filed October 1, 2015 (Eighty-second); 4(g) to Form 8-K filed March 18, 2016 in 1-32718 (Eighty-third); 4.33 to Form 8-K filed March 24, 2016 in 1-32718 (Eighty-fourth); 4.33 to Form 8-K filed August 17, 2016 in 1-32718 (Eighty-sixth); 4.43 to Form 8-K filed October 4, 2016 in 1-32718 (Eighty-seventh); 4.43 to Form 8-K filed May 23, 2017 in 1-32718 (Eighty-eighth); 4.43 to Form 8‑K filed March 23, 2018 in 1-32718 (Eighty-ninth); 4.43 to Form 8-K filed August 14, 2018 in 1-32718 (Ninetieth); and 4.43 to Form 8-K filed March 12, 2019 in 1-32718 (Ninety-first); 4.53 to Form 8-K filed March 6, 2020 in 1-32718 (Ninety-second); 4.53(b) to Form 8-K filed November 13, 2020 in 1-32718 (Ninety-third); 4.53 to Form 8-K filed November 24, 2020 in 1-32718 (Ninety-fourth); 4.53 to Form 8-K filed March 10, 2021 in 1-32718 (Ninety-fifth); 4.53 to Form 8-K filed October 1, 2021 in 1-32718 (Ninety-sixth); and 4.70 to Form 8-K filed August 24, 2022 in 1-32718 (Ninety-seventh)). |
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| (d) 2 -- | SecondThird Amended and Restated Credit Agreement dated as of September 14, 2018,June 3, 2021, among Entergy Louisiana, as Borrower, the banks and other financial institutions listed on the signature pages thereof, as Lenders, Citibank, N.A., as Administrative Agent, Wells Fargo Bank, National Association and BNP Paribas, as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4(i)(4.3 to Form 10-Q for the quarter ended September 30, 20188-K filed June 3, 2021 in 1-32718). |
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| (d) 3 -- | First Extension and Amendment Agreement, dated September 13, 2019, to Secondas of June 3, 2022, amending the Third Amended and Restated Credit Agreement, dated as of September 14, 2018,June 3, 2021, among Entergy Louisiana, as Borrower, the banksLenders and other financial institutions listed on the signature pages thereof, as Lenders,LC Issuing Banks parties thereto and Citibank, N.A., as Administrative Agent, Wells Fargo Bank, National Associationas set forth in Exhibit A to the First Extension and BNP Paribas, as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4(c)Amendment Agreement(4(e) to Form 10-Q for the quarter ended SeptemberJune 30, 20192022 in 1-32718)1-32718). |
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| (d) 4 -- | |
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| (d) 5 -- | |
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| (d) 6 -- | |
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| (d) 7 -- | |
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| (d) 8 -- | |
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|
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(d) 910 -- | |
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| (d) 11 -- | Indenture of Mortgage, dated September 1, 1926, as amended by the following Supplemental Indentures: (7-A-9 in Registration No. 2-6893 (Seventh); 4(d)15 to Form 10-K for the year ended December 31, 2017 in 1-32718 (Eighteenth); 2-A-8 in Registration No. 2-66612 (Thirty-eighth); 4(b) to Form 10-Q for the quarter ended March 31,1999 in 1-27031 (Fifty-eighth); 4(a) to Form 10-Q for the quarter ended September 30, 2009 in 0-20371 (Seventy-seventh); 4.07 to Form 8-K filed October 1, 2010 in 0-20371 (Seventy-eighth); 4.07 to Form 8-K filed July 1, 2014 in 0-20371 (Eighty-first); 4.2 to Form 8-K12B filed October 1, 2015 in 1-32718 (Eighty-second); 4.3 to Form 8-K12B filed October 1, 2015 in 1-32718 (Eighty-third); 4.42 to Form 8-K filed March 24, 2016 in 1-32718 (Eighty-fourth); 4.42 to Form 8-K filed May 19, 2016 in 1-32718 (Eighty-fifth); 4.42 to Form 8-K filed August 17, 2016 in 1-32718 (Eighty-sixth); 4.42 to Form 8-K filed October 4, 2016 in 1-32718 (Eighty-seventh); 4.42 to Form 8-K filed May 23, 2017 in 1-32718 (Eighty-eighth); 4.42 to Form 8-K filed March 23, 2018 in 1-32718 (Eighty-ninth); 4.42 to Form 8-K filed August 14, 2018 in 1-32718 (Ninetieth); and 4.42 to Form 8-K filed March 12, 2019 in 1-32718 (Ninety-first); 4.52 to Form 8-K filed March 6, 2020 in 1-32718 (Ninety-second); 4.52(b) to Form 8-K filed November 13, 2020 in 1-32718 (Ninety-third);4.52 to Form 8-K filed March 10, 2021 in 1-32718 (Ninety-fourth); 4.52 to Form 8-K filed October 1, 2021 in 1-32718 (Ninety-fifth); and 4.69 to Form 8-K filed August 24, 2022 in 1-32718 (Ninety-sixth)). |
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(d) 1012 -- | Agreement of Resignation, Appointment and Acceptance, dated as of October 3, 2007, among Entergy Gulf States, Inc., JPMorgan Chase Bank, National Association, as resigning trustee, and The Bank of New York, as successor trustee (4(a) to Form 10-Q for the quarter ended September 30, 2007 in 1-27031). |
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(d) 1113 -- | Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015, as amended by the following Supplemental Indentures: (4.38 in Registration No. 333-190911-07 (Mortgage); 4(f) to Form 8-K filed March 18, 2016 in 1-32718 (First); 4.40 to Form 8-K filed March 24, 2016 in 1-32718 (Second); 4(h) to Form 10-Q for the quarter ended March 31, 2016 in 1-32718 (Fourth); 4.40 to Form 8-K filed May 19, 2016 in 1-32718 (Fifth); 4.40 to Form 8-K filed August 17, 2016 in 1-32718 (Sixth); 4.41 to Form 8-K filed October 4, 2016 in 1-32718 (Seventh); 4.41 to Form 8-K filed May 23, 2017 in 1-32718 (Eighth); 4.41 to Form 8-K filed March 23, 2018 in 1-32718 (Ninth); 4.41 to Form 8-K filed August 14, 2018 in 1-32718 (Tenth); and 4.41 to Form 8-K filed March 12, 2019 in 1-32718 (Eleventh)).; |
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(d) 12 -- | Officer’s Certificate No. 1-B-1, dated March 18, 2016, supplemental to Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015 (4(e)4.51 to Form 8-K filed March 18, 20166, 2020 in 1-32718)1-32718 (Twelfth); 4.51(b) to Form 8-K filed November 13, 2020 in 1-32718 (Thirteenth); 4.51 to Form 8-K filed November 24, 2020 in 1-32718 (Fourteenth); 4.51 to Form 8-K filed March 10, 2021 in 1-32718 (Fifteenth); 4(b) to Form 8-K filed April 1, 2021 in 1-32718 (Sixteenth); 4.51 to Form 8-K filed October 1, 2021 in 1-32718 (Seventeenth); and 4.68 to Form 8-K filed August 24, 2022 in 1-32718 (Eighteenth)). |
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(d) 1314 -- | |
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(d) 1415 -- | |
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(d) 1516 -- | |
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(d) 1617 -- | |
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(d) 1718 -- | |
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(d) 1819 -- | |
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(d) 1920 -- | |
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(d) 2021 -- | |
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| (d) 22 -- | |
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| (d) 23 -- | |
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| (d) 24 -- | |
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| (d) 25 -- | |
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| (d) 26 -- | |
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| (d) 27 -- | |
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| (d) 28 -- | |
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| (d) 29 -- | |
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*(d) 2130 -- | |
Entergy Mississippi
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| (e) 1 -- | Mortgage and Deed of Trust, dated as of February 1, 1988, as amended by the following Supplemental Indentures: (4(e)1 to Form 10-K for the year ended December 31, 2017 in 1-31508 (Mortgage); 4(e)1 to Form 10-K for the year ended December 31, 2017 in 1-31508 (Sixth); A-2(c) to Rule 24 Certificate filed May 14, 1999 in 70-8719 (Thirteenth); 4(b) to Form 10-Q for the quarter ended June 30, 2009 in 1-31508 (Twenty-sixth); 4.38 to Form 8-K filed December 11, 2012 in 1-31508 (Thirtieth); 4.05 to Form 8-K filed March 21, 2014 in 1-31508 (Thirty-first); 4.05 to Form 8-K filed May 13, 2016 in 1-31508 (Thirty-second); 4.16 to Form 8-K filed September 15, 2016 in 1-31508 (Thirty-third); 4.16 to Form 8-K filed November 14, 2017 in 1-31508 (Thirty-fourth); 4.1 to Form 8-K filed November 21, 2018 in 1-31508 (Thirty-fifth); 4.1 to Form 8-K12B filed December 3, 2018 in 1-31508 (Thirty-sixth); 4(a) to Form 8-K filed December 12, 2018 in 1-31508 (Thirty-seventh); and 4.46 to Form 8-K filed June 5, 2019 in 1-31508 (Thirty-eighth); 4.56 to Form 8-K filed May 22, 2020 in 1-31508 (Thirty-ninth); and 4.56 to Form 8-K filed November 16, 2021 in 1-31508 (Fortieth)). |
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*(e) 2 -- | |
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| (e) 3 -- | |
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| *(e) 4 -- | |
Entergy New Orleans
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| (f) 1 -- | Mortgage and Deed of Trust, dated as of May 1, 1987, as amended by the following Supplemental Indentures: (4(f)1 to Form 10-K for the year ended December 31, 2017 in 1-35747 (Mortgage); 4(f)1 to Form 10-K for the year ended December 31, 2017 in 1-35747 (Third); 4(b) to Form 10-Q for the quarter ended June 30, 1998 in 0-5807 (Seventh); 4.02 to Form 8-K filed November 23, 2010 in 0-5807 (Fifteenth); 4.02 to Form 8-K filed November 29, 2012 in 1-35747 (Sixteenth); 4.02 to Form 8-K filed June 21, 2013 in 1-35747 (Seventeenth); 4(m) to Form 10-Q for the quarter ended March 31, 2016 in 1-35747 (Eighteenth); 4.02 to Form 8-K filed March 22, 2016 in 1-35747 (Nineteenth); 4.02 to Form 8-K filed May 24, 2016 in 1-35747 (Twentieth); 4.1 to Form 8-K12B filed December 1, 2017 in 1-35747 (Twenty-first); and 4(a) to Form 8-K filed September 27, 2018 in 1-35747 (Twenty-second); 4(a) to Form 8-K filed March 26, 2020 in 1-35747 (Twenty-third); and 4(a) to Form 8-K filed November 19, 2021 in 1-35747 (Twenty-fourth)). |
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| (f) 2 -- | SecondThird Amended and Restated Credit Agreement dated as of November 16, 2018,June 22, 2021, among Entergy New Orleans, as Borrower, the banks and other financial institutions listed on the signature pages thereof, as Lenders, Bank of America, N.A., as Administrative Agent and LC Issuing Bank, and the other LC Issuing Banks from time to time parties thereto (4(f)2(4 to Form 10-K for the year ended December 31, 20188-K filed June 22, 2021 in 1-35747). |
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| (f) 3 -- | Amended and Restated Term Loan Credit Agreement dated as of December 18, 2019,November 9, 2021, by and among Entergy New Orleans, the banks and other financial institutions listed on the signature pages thereof, as Lenders party thereto, and Bank of America, N.A., as Administrative Agent (4(a) to Form 8-K filed December 18, 2019November 10, 2021 in 1-35747). |
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| *(f) 4 -- | |
Entergy Texas
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(g) 53 -- | |
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(g) 6 -- | |
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(g) 74 -- | |
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(g) 85 -- | |
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(g) 96 -- | |
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| (g) 7 -- | |
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| (g) 8 -- | |
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| (g) 9 -- | |
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| (g) 10 -- | SecondThird Amended and Restated Credit Agreement dated as of September 14, 2018,June 3, 2021, among Entergy Texas, as Borrower, the banks and other financial institutions listed on the signature pages thereof, as Lenders, Citibank, N.A., as Administrative Agent, JPMorgan Chase Bank, N.A., BNP Paribas, Mizuho Bank, Ltd., and The Bank of Nova Scotia, as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4(j)(4.4 to Form 10-Q for the quarter ended September 30, 20188-K filed June 3, 2021 in 1-34360). |
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| (g) 11 -- | First Extension and Amendment Agreement, dated September 13, 2019, to Secondas of June 3, 2022, amending the Third Amended and Restated Credit Agreement, dated as of September 14, 2018,June 3, 2021, among Entergy Texas, as Borrower, the banksLenders and other financial institutions listed on the signature pages thereof, as Lenders,LC Issuing Banks parties thereto and Citibank, N.A., as Administrative Agent, JPMorgan Chase Bank, N.A., BNP Paribas, Mizuho Bank, Ltd.,as set forth in Exhibit A to the First Extension and The Bank of Nova Scotia, as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4(d)Amendment Agreement (4(f) to Form 10-Q for the quarter ended Septemberended June 30, 20192022 in 1-34360). |
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| (g) 12 -- | |
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*(g) 13 -- | |
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| (g) 14 -- | |
(10) Material Contracts
Entergy Corporation
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+(a) 1 -- | |
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+(a) 2 -- | |
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+(a) 3 -- | |
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+(a) 4 -- | |
(10) Material Contracts
Entergy Corporation |
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+(a) 5 --1-- | |
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+(a) 62 -- | |
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+(a) 73 -- | |
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+(a) 84 -- | |
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+(a) 95 -- | |
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+(a) 106 -- | |
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+(a) 117 -- | |
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+(a) 128 -- | |
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+(a) 139 -- | |
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+(a) 1410 -- | |
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+(a) 1511 -- | |
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+(a) 1612 -- | |
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+(a) 1713 -- | |
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+(a) 1814 -- | |
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+(a) 1915 -- | |
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+(a) 2016 -- | |
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+(a) 2319 -- | |
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+(a) 24 -- | |
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+(a) 25 -- | |
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+(a) 2620 -- | |
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+(a) 2721 -- | |
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+(a) 2822 -- | |
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+(a) 2923 -- | |
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+(a) 3024 -- | |
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*+(a) 3128 -- | |
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+(a) 3230 -- | |
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+(a) 3331 -- | |
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+(a) 3432 -- | |
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+(a) 3533 -- | |
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+(a) 3634 -- | |
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+(a) 3735 -- | |
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| +(a) 39 -- | |
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+(a) 3940 -- | |
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+(a) 4041 -- | |
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+(a) 4142 -- | |
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+(a) 4243 -- | |
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+(a) 4346 -- | |
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+(a) 49 -- | |
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+(a) 5052 -- | |
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| +(a) 54 -- | |
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| +(a) 55 -- | |
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+(a) 5156 -- | |
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+(a) 5257 -- | |
System Energy
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| +(a) 58 -- | |
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| +(a) 59 -- | |
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| +(a) 60 -- | |
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| +(a) 61 -- | |
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| +(a) 62 -- | |
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| *+(a) 63 -- | |
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| *+(a) 64 -- | |
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| *+(a) 65 -- | |
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| *+(a) 66 -- | |
System Energy | | | | | |
| (b) 1 -- | |
| |
| (b) 2 -- | |
| |
| (b) 3 -- | |
| |
| (b) 4 -- | |
| |
| | | | | |
| (b) 5 -- | |
| |
| (b) 6 -- | Thirty-seventh Assignment of Availability Agreement, Consent and Agreement, dated as of September 1, 2012, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and The Bank of New York Mellon, as successor trustee (10(a)15 to Form 10-K for the year ended December 31, 2012 in 1-11299). |
| |
| (b) 7 -- | Amendment to the Thirty-seventh Assignment of Availability Agreement, Consent and Agreement, dated as of September 18, 2015, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and The Bank of New York Mellon, as successor trustee (4.25 to Form S-3 filed October 2, 2015). |
|
| |
| |
| (b) 8 -- | Thirty-eighth Assignment of Availability Agreement, Consent and Agreement, dated as of December 9, 2020, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and The Bank of New York Mellon, as successor trustee (4.60 to Form 8-K filed December 9, 2020 in 1-09067). |
| |
| (b) 9 -- | Thirty-ninth Assignment of Availability Agreement, Consent and Agreement, dated as of June 15, 2021, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans,The Bank of New York Mellon, as Mortgage Trustee and The Bank of New York Mellon, as Indenture Trustee (4(b) to Form 8-K filed June 15, 2021 in 1-09067). |
| |
| (b) 10 -- | Fortieth Assignment of Availability Agreement, Consent and Agreement, dated as of May 6, 2022, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, The Bank of New York Mellon, as Mortgage Trustee, and Royal Bank of Canada, as Administrative Agent (4(c) to Form 8-K filed May 6, 2022 in 1-09067). |
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| (b) 11 -- | |
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(b) 912 -- | |
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(b) 1013 -- | |
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(b) 1114 -- | |
| |
(b) 1215 -- | |
| |
(b) 1316 -- | |
(14) Code of Ethics
Entergy Corporation
(23) Consents of Experts and Counsel
(31) Rule 13a-14(a)/15d-14(a) Certifications
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(32) Section 1350 Certifications
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(101) Interactive Data File
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| *INS - | Inline XBRL Instance Document - The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. |
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| *SCH - | Inline XBRL Schema Document. |
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| *CAL - | Inline XBRL Calculation Linkbase Document. |
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| *DEF - | Inline XBRL Definition Linkbase Document. |
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| *LAB - | Inline XBRL Label Linkbase Document. |
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| *PRE - | Inline XBRL Presentation Linkbase Document. |
*(104) Cover Page Interactive Data File (formatted in Inline XBRL and contained in Exhibits 101)
_________________
|
| | | | | | | |
| * | Filed herewith. |
| ** | Furnished, not filed, herewith. |
| + | Management contracts or compensatory plans or arrangements. |
ENTERGY CORPORATION
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
| | | | | |
| ENTERGY CORPORATION |
| |
| ENTERGY CORPORATION |
| |
| By /s/ Kimberly A. FontanReginald T. Jackson |
| Kimberly A. FontanReginald T. Jackson |
| Senior Vice President and Chief Accounting Officer |
| |
| Date: February 21, 202024, 2023 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
|
| | | | | | | |
| Signature | Title | Date |
| | |
/s/ Kimberly A. FontanReginald T. Jackson Kimberly A. FontanReginald T. Jackson
| Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
| February 21, 202024, 2023 |
Leo P. DenaultAndrew S. Marsh (Chairman of the Board, Chief Executive Officer and Director; Principal Executive Officer); Andrew S. MarshKimberly A. Fontan (Executive Vice President and Chief Financial Officer; Principal Financial Officer); John R. Burbank, Patrick J. Condon, Kirkland H. Donald, Brian W. Ellis, Philip L. Frederickson, Alexis M. Herman, M. Elise Hyland, Stuart L. Levenick, Blanche L. Lincoln, and Karen A. Puckett (Directors).
|
| | | | |
By: /s/ Kimberly A. FontanReginald T. Jackson | February 21, 202024, 2023 |
(Kimberly A. Fontan,Reginald T. Jackson, Attorney-in-fact) | |
ENTERGY ARKANSAS, LLC
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
| | | | | |
| ENTERGY ARKANSAS, LLC |
| |
| ENTERGY ARKANSAS, LLC |
| |
| By /s/ Kimberly A. FontanReginald T. Jackson |
| Kimberly A. FontanReginald T. Jackson |
| Senior Vice President and Chief Accounting Officer |
| |
| Date: February 21, 202024, 2023 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
|
| | | | | | | |
| Signature | Title | Date |
| | |
/s/ Kimberly A. FontanReginald T. Jackson Kimberly A. FontanReginald T. Jackson
| Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
| February 21, 202024, 2023 |
Laura R. Landreaux (Chair of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. MarshKimberly A. Fontan (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Paul D. HinnenkampPeter S. Norgeot, Jr. and Roderick K. West (Directors).
|
| | | | |
By: /s/ Kimberly A. FontanReginald T. Jackson | February 21, 202024, 2023 |
(Kimberly A. Fontan,Reginald T. Jackson, Attorney-in-fact) | |
ENTERGY LOUISIANA, LLC
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
| | | | | |
| ENTERGY LOUISIANA, LLC |
| |
| ENTERGY LOUISIANA, LLC |
| |
| By /s/ Kimberly A. FontanReginald T. Jackson |
| Kimberly A. FontanReginald T. Jackson |
| Senior Vice President and Chief Accounting Officer |
| |
| Date: February 21, 202024, 2023 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
|
| | | | | | | |
| Signature | Title | Date |
| | |
/s/ Kimberly A. FontanReginald T. Jackson Kimberly A. FontanReginald T. Jackson
| Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
| February 21, 202024, 2023 |
Phillip R. May, Jr. (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. MarshKimberly A. Fontan (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Paul D. HinnenkampPeter S. Norgeot, Jr. and Roderick K. West (Directors).
|
| | | | |
By: /s/ Kimberly A. FontanReginald T. Jackson | February 21, 202024, 2023 |
(Kimberly A. Fontan,Reginald T. Jackson, Attorney-in-fact) | |
ENTERGY MISSISSIPPI, LLC
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
| | | | | |
| ENTERGY MISSISSIPPI, LLC |
| |
| ENTERGY MISSISSIPPI, LLC |
| |
| By /s/ Kimberly A. FontanReginald T. Jackson |
| Kimberly A. FontanReginald T. Jackson |
| Senior Vice President and Chief Accounting Officer |
| |
| Date: February 21, 202024, 2023 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
|
| | | | | | | |
| Signature | Title | Date |
| | |
/s/ Kimberly A. FontanReginald T. Jackson Kimberly A. FontanReginald T. Jackson
| Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
| February 21, 202024, 2023 |
Haley R. Fisackerly (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. MarshKimberly A. Fontan (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Paul D. HinnenkampPeter S. Norgeot, Jr. and Roderick K. West (Directors).
|
| | | | |
By: /s/ Kimberly A. FontanReginald T. Jackson | February 21, 202024, 2023 |
(Kimberly A. Fontan,Reginald T. Jackson, Attorney-in-fact) | |
ENTERGY NEW ORLEANS, LLC
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
| | | | | |
| ENTERGY NEW ORLEANS, LLC |
| |
| ENTERGY NEW ORLEANS, LLC |
| |
| By /s/ Kimberly A. FontanReginald T. Jackson |
| Kimberly A. FontanReginald T. Jackson |
| Senior Vice President and Chief Accounting Officer |
| |
| Date: February 21, 202024, 2023 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
|
| | | | | | | |
| Signature | Title | Date |
| | |
/s/ Kimberly A. FontanReginald T. Jackson Kimberly A. FontanReginald T. Jackson
| Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
| February 21, 202024, 2023 |
DavidDeanna D. Ellis (ChairmanRodriguez (Chair of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. MarshKimberly A. Fontan (Executive Vice President and Chief Financial Officer, and Director;Officer; Principal Financial Officer); Paul D. HinnenkampPeter S. Norgeot, Jr. and Roderick K. West (Directors).
|
| | | | |
By: /s/ Kimberly A. FontanReginald T. Jackson | February 21, 202024, 2023 |
(Kimberly A. Fontan,Reginald T. Jackson, Attorney-in-fact) | |
ENTERGY TEXAS, INC.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
| | | | | |
| ENTERGY TEXAS, INC. |
| |
| ENTERGY TEXAS, INC. |
| |
| By /s/ Kimberly A. FontanReginald T. Jackson |
| Kimberly A. FontanReginald T. Jackson |
| Senior Vice President and Chief Accounting Officer |
| |
| Date: February 21, 202024, 2023 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
|
| | | | | | | |
| Signature | Title | Date |
| | |
/s/ Kimberly A. FontanReginald T. Jackson Kimberly A. FontanReginald T. Jackson
| Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
| February 21, 202024, 2023 |
Sallie T. Rainer (ChairEliecer Viamontes (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. MarshKimberly A. Fontan (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Paul D. HinnenkampPeter S. Norgeot, Jr. and Roderick K. West (Directors).
|
| | | | |
By: /s/ Kimberly A. FontanReginald T. Jackson | February 21, 202024, 2023 |
(Kimberly A. Fontan,Reginald T. Jackson, Attorney-in-fact) | |
SYSTEM ENERGY RESOURCES, INC.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
| | | | | |
| SYSTEM ENERGY RESOURCES, INC. |
| |
| SYSTEM ENERGY RESOURCES, INC. |
| |
| By /s/ Kimberly A. FontanReginald T. Jackson |
| Kimberly A. FontanReginald T. Jackson |
| Senior Vice President and Chief Accounting Officer |
| |
| Date: February 21, 202024, 2023 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
|
| | | | | | | |
| Signature | Title | Date |
| | |
/s/ Kimberly A. FontanReginald T. Jackson Kimberly A. FontanReginald T. Jackson
| Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
| February 21, 202024, 2023 |
Roderick K. West (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. MarshKimberly A. Fontan (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); A. Christopher Bakken, IIIKimberly Cook-Nelson and Steven C. McNealBarrett E. Green (Directors).
|
| | | | |
By: /s/ Kimberly A. FontanReginald T. Jackson | February 21, 202024, 2023 |
(Kimberly A. Fontan,Reginald T. Jackson, Attorney-in-fact) | |
EXHIBIT 23(a)
CONSENTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statement No. 333-233403333-266624 on Form S-3 and in Registration Statements Nos. 333-140183, 333-174148, 333-204546, 333-206556, 333-227150333-231800 and 333-231800333-251819 on Form S-8 of our reports dated February 21, 2020,24, 2023, relating to the financial statements and financial statement schedule of Entergy Corporation and Subsidiaries, and the effectiveness of Entergy Corporation and Subsidiaries’ internal control over financial reporting, appearing in this Annual Report on Form 10-K of Entergy Corporation for the year ended December 31, 2019.2022.
We consent to the incorporation by reference in Registration Statement No. 333-233403-05333-266624-05 on Form S-3 of our reports dated February 21, 2020,24, 2023, relating to the financial statements and financial statement schedule of Entergy Arkansas, LLC and Subsidiaries appearing in this Annual Report on Form 10-K of Entergy Arkansas, LLC for the year ended December 31, 2019.2022.
We consent to the incorporation by reference in Registration Statement No. 233403-04266624-04 on Form S-3 of our reports dated February 21, 2020,24, 2023, relating to the financial statements and financial statement schedule of Entergy Louisiana, LLC and Subsidiaries appearing in this Annual Report on Form 10‑K of Entergy Louisiana, LLC for the year ended December 31, 2019.2022.
We consent to the incorporation by reference in Registration Statement No. 233403-03266624-03 on Form S-3 of our reports dated February 21, 2020,24, 2023, relating to the financial statements and financial statement schedule of Entergy Mississippi, LLC and Subsidiaries appearing in this Annual Report on Form 10‑K of Entergy Mississippi, LLC for the year ended December 31, 2019.2022.
We consent to the incorporation by reference in Registration Statement No. 233403-02266624-02 on Form S-3 of our reports dated February 21, 2020,24, 2023, relating to the financial statements and financial statement schedule of Entergy Texas, Inc. and Subsidiaries appearing in this Annual Report on Form 10-K of Entergy Texas, Inc. for the year ended December 31, 2019.2022.
We consent to the incorporation by reference in Registration Statement No. 233403-01266624-01 on Form S-3 of our report dated February 21, 2020,24, 2023, relating to the financial statements of System Energy Resources, Inc. appearing in this Annual Report on Form 10-K of System Energy Resources, Inc. for the year ended December 31, 2019.2022.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 21, 202024, 2023
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and Board of Directors of
Entergy Corporation and Subsidiaries
Opinion on the Financial Statement Schedule
We have audited the consolidated financial statements of Entergy Corporation and Subsidiaries (the “Corporation”) as of December 31, 20192022 and 2018,2021, and for each of the three years in the period ended December 31, 2019,2022, and the Corporation’s internal control over financial reporting as of December 31, 2019,2022, and have issued our reports thereon dated February 21, 2020.24, 2023. Our audits also included the consolidated financial statement schedule of the Corporation listed in Item 15. This consolidated financial statement schedule is the responsibility of the Corporation’s management. Our responsibility is to express an opinion on the Corporation’s consolidated financial statement schedule based on our audits. In our opinion, such consolidated financial statement schedule, when considered in relation to the consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 21, 202024, 2023
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and Board of Directors of
Entergy Texas, Inc. and Subsidiaries
To the member and Board of Directors of
Entergy Arkansas, LLC and Subsidiaries
Entergy Louisiana, LLC and Subsidiaries
Entergy Mississippi, LLC and Subsidiaries
Entergy New Orleans, LLC and Subsidiaries
Opinion on the Financial Statement Schedules
We have audited the consolidated financial statements of Entergy Arkansas, LLC and Subsidiaries, Entergy Louisiana, LLC and Subsidiaries, Entergy Mississippi, LLC and Subsidiaries, Entergy New Orleans, LLC and Subsidiaries, and Entergy Texas, Inc. and Subsidiaries and we have also audited the financial statements of Entergy Mississippi, LLC (collectively the “Companies”) as of December 31, 20192022 and 2018,2021, and for each of the three years in the period ended December 31, 2019,2022, and have issued our reports thereon dated February 21, 2020.24, 2023. Our audits also included the financial statement schedules of the respective Companies listed in Item 15. These financial statement schedules are the responsibility of the respective Companies’ management. Our responsibility is to express an opinion on the Companies’ financial statement schedules based on our audits. In our opinion, such financial statement schedules, when considered in relation to the financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 21, 202024, 2023
INDEX TO FINANCIAL STATEMENT SCHEDULES
|
| | | | | | | |
| Schedule | | Page |
| | |
| II | Valuation and Qualifying Accounts 2019, 2018,2022, 2021, and 2017:2020: | |
| | |
| | |
| | |
| | |
| | |
| | |
Schedules other than those listed above are omitted because they are not required, not applicable, or the required information is shown in the financial statements or notes thereto.
Columns have been omitted from schedules filed because the information is not applicable.
|
| | | | | | | | | | | | | | | | |
| 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. |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| ENTERGY CORPORATION AND SUBSIDIARIES |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2022, 2021, and 2020 |
| (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
(1) | | Deductions (2) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2022 | | $68,608 | | | $40,307 | | | $78,059 | | | $30,856 | |
| 2021 | | $117,794 | | | $57,517 | | | $106,703 | | | $68,608 | |
| 2020 | | $7,404 | | | $111,687 | | | $1,297 | | | $117,794 | |
| Notes: | | | | | | | | |
| (1) A portion of the charges to income are deferred as a regulatory asset. |
| (2) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
|
| | | | | | | | | | | | | | | | |
| 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. |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2022, 2021, and 2020 |
| (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
(1) | | Deductions (2) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2022 | | $13,072 | | | $14,947 | | | $21,491 | | | $6,528 | |
| 2021 | | $18,334 | | | $30,433 | | | $35,695 | | | $13,072 | |
| 2020 | | $1,169 | | | $17,307 | | | $142 | | | $18,334 | |
| Notes: | | | | | | | | |
| (1) A portion of the charges to income are deferred as a regulatory asset. |
| (2) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
|
| | | | | | | | | | | | | | | | |
| 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. |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2022, 2021, and 2020 |
| (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
(1) | | Deductions (2) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2022 | | $29,231 | | | $10,574 | | | $32,210 | | | $7,595 | |
| 2021 | | $45,693 | | | $17,219 | | | $33,681 | | | $29,231 | |
| 2020 | | $1,902 | | | $44,542 | | | $751 | | | $45,693 | |
| Notes: | | | | | | | | |
| (1) A portion of the charges to income are deferred as a regulatory asset. |
| (2) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
|
| | | | | | | | | | | | | | | | |
| 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. |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2022, 2021, and 2020 |
| (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
(1) | | Deductions (2) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2022 | | $7,209 | | | $3,052 | | | $7,789 | | | $2,472 | |
| 2021 | | $19,527 | | | $850 | | | $13,168 | | | $7,209 | |
| 2020 | | $636 | | | $19,081 | | | $190 | | | $19,527 | |
| Notes: | | | | | | | | |
| (1) A portion of the charges to income are deferred as a regulatory asset. |
| (2) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
|
| | | | | | | | | | | | | | | | |
| 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. |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2022, 2021, and 2020 |
| (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
(1) | | Deductions (2) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2022 | | $13,282 | | | $7,691 | | | $9,064 | | | $11,909 | |
| 2021 | | $17,430 | | | $6,850 | | | $10,998 | | | $13,282 | |
| 2020 | | $3,226 | | | $14,204 | | | $— | | | $17,430 | |
| Notes: | | | | | | | | |
| (1) A portion of the charges to income are deferred as a regulatory asset. |
| (2) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
|
| | | | | | | | | | | | | | | | |
| 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. |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2022, 2021, and 2020 |
| (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
(1) | | Deductions (2) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2022 | | $5,814 | | | $4,042 | | | $7,504 | | | $2,352 | |
| 2021 | | $16,810 | | | $2,166 | | | $13,162 | | | $5,814 | |
| 2020 | | $471 | | | $16,554 | | | $215 | | | $16,810 | |
| Notes: | | | | | | | | |
| (1) A portion of the charges to income are deferred as a regulatory asset. |
| (2) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |