EDGAR 10-K Filing

Company CIK: 202584
Filing Year: 2022
Filename: 202584_10-K_2022_0000065984-22-000017.json

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ITEM 1. BUSINESS
Item 1. Business
RISK FACTORS SUMMARY
Entergy’s business is subject to numerous risks and uncertainties that could affect its ability to successfully implement its business strategy and affect its financial results. Carefully consider all of the information in this report and, in particular, the following principal risks and all of the other specific factors described in Item 1A. of this report, “Risk Factors,” before deciding whether to invest in Entergy or the Registrant Subsidiaries.
Utility Regulatory Risks
•The impacts of the COVID-19 pandemic and responsive measures taken are highly uncertain and cannot be predicted.
•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.
•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.
•Entergy’s business could experience adverse effects related to changes to state or federal legislation or regulation.
•The Utility operating companies are subject to risks associated with participation in the MISO markets and the allocation of transmission upgrade costs.
•A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather (including from Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Hurricane Ida) could have material effects on Entergy and those Utility operating companies affected by severe weather.
Nuclear Operating, Shutdown, and Regulatory Risks
•The results of operations, financial condition, and liquidity of Entergy Arkansas, Entergy Louisiana, System Energy, and Entergy Wholesale Commodities could be materially affected by the following:
◦failure to consistently operate their nuclear power plants at high capacity factors;
◦refueling outages that last 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 from 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.
•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.
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Entergy Corporation, Utility operating companies, and System Energy
General Business Risks
•Entergy and the Utility operating companies 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.
•A downgrade in Entergy Corporation’s or its subsidiaries’ credit ratings could, among other things, negatively affect Entergy Corporation’s and its subsidiaries’ ability to access capital.
•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, the Utility operating companies’, and System Energy’s 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.
•The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business may incur substantial costs (i) to fulfill their obligations related to environmental and other matters or (ii) related to reliability standards.
•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.
•Entergy could be negatively affected by the effects of climate change, including transition and physical risks, and environmental and regulatory obligations intended to compel greenhouse gas emission reductions or increase clean or renewable energy requirements or to place a price on greenhouse gas emissions.
•Entergy is 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 the Entergy Wholesale Commodities business 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 certain Entergy subsidiaries operate poses a significant risk to those businesses.
•Terrorist attacks, cyber attacks, system failures, or data breaches of Entergy’s and its subsidiaries’ or its suppliers’ technology systems may adversely affect Entergy’s results of operations.
•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.
•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.
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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 26,000 MW of electric generating capacity, including approximately 6,000 MW of nuclear power. Entergy delivers electricity to 3 million utility customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy had annual revenues of $11.7 billion in 2021 and had more than 12,000 employees as of December 31, 2021.
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 operation and planned shutdown and sale of each of the Entergy Wholesale Commodities nuclear power plants, including the planned shutdown of Palisades, the only remaining operating plant in Entergy Wholesale Commodities’ merchant nuclear fleet.
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 for Entergy and its customers. Entergy is also executing the wind down of the Entergy Wholesale Commodities merchant nuclear generation business, which is expected to be 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 overall generation portfolio of the Utility, which relies heavily on natural gas and nuclear generation, is consistent with Entergy’s strong support for the environment.
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Entergy Corporation, Utility operating companies, and System Energy
Customers
As of December 31, 2021, 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 728 24 %
Entergy Louisiana Portions of Louisiana 1,100 37 % 96 47 %
Entergy Mississippi Portions of Mississippi 461 16 %
Entergy New Orleans City of New Orleans 209 7 % 110 53 %
Entergy Texas Portions of Texas 486 16 %
Total customers 2,984 100 % 206 100 %
Electric Energy Sales
The 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 August 23, 2021, Entergy reached a 2021 peak demand of 22,051 MWh, compared to the 2020 peak of 21,340 MWh recorded on August 10, 2020. Selected electric energy sales data is shown in the table below:
Selected 2021 Electric Energy Sales Data
Entergy Arkansas Entergy Louisiana Entergy Mississippi Entergy New Orleans Entergy Texas System Energy Entergy (a)
(In GWh)
Sales to retail customers 22,280 54,634 12,745 5,406 19,679 - 114,744
Sales for resale:
Affiliates 2,254 4,950 - - 1,364 10,593 -
Others 6,151 2,764 4,364 2,369 1,008 - 16,656
Total 30,685 62,348 17,109 7,775 22,051 10,593 131,400
Average use per residential customer (kWh) 13,390 14,139 14,555 12,032 14,601 - 13,947
(a)Includes the effect of intercompany eliminations.
The following table illustrates the Utility operating companies’ 2021 combined electric sales volume as a percentage of total electric sales volume, and 2021 combined electric revenues as a percentage of total 2021 electric revenue, each by customer class.
Customer Class % of Sales Volume % of Revenue
Residential 27.1 36.6
Commercial 20.4 24.0
Industrial (a) 37.9 27.0
Governmental 1.9 2.3
Wholesale/Other 12.7 10.1
(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
Selected 2021 Natural Gas Sales Data
Entergy New Orleans and Entergy Louisiana provide both electric power and natural gas to retail customers. Entergy New Orleans and Entergy Louisiana sold 10,686,659 and 7,409,278 Mcf, respectively, of natural gas to retail customers in 2021. In 2021, 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, 87% of operating revenue was derived from the electric utility business and 13% from the natural gas distribution business in 2021.
Following is data concerning Entergy New Orleans’s 2021 retail operating revenue sources.
Customer Class Electric Operating Revenue Natural Gas Operating Revenue
Residential 47% 50%
Commercial 36% 24%
Industrial 5% 19%
Governmental/Municipal 12% 7%
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 $8.7 (a) 9.15% - 10.15% 5.17% 37.6% - forward test year formula rate
plan
- riders: MISO, capacity, Grand
Gulf, tax adjustment, energy
efficiency, fuel and purchased
power
Entergy Louisiana (electric) $13.6 (b) 9.0% - 10.0% 6.74% 49.98% - formula rate plan through 2022
test year
- riders/specific recovery: MISO,
capacity, transmission, fuel,
distribution
Entergy Louisiana (gas) $0.09 (c) 9.3% - 10.3% 6.97% 49.31% - gas rate stabilization plan
- rider: gas infrastructure
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Entergy Mississippi $3.6 (d) 9.03% - 11.08% 6.85% 48.63% - 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) $1.1 (e) 9.35% 6.89% 51% - formula rate plan with
forward-looking features
- riders/specific recovery: fuel and
purchased power, MISO, energy
efficiency, environmental
Entergy New Orleans (gas) $0.2 (e) 9.35% 6.89% 51% - formula rate plan with
forward-looking features
- rider: purchased gas
Entergy Texas $2.4 (f) 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 $1.55 (g) 10.94% (h) 8.26 % 65% (h) - monthly cost of service
(a)Based on 2022 test year.
(b)Based on December 31, 2020 test year and excludes approximately $800 million for the Lake Charles Power Station and $300 million for the Washington Parish Energy Center, each included in the capacity rider, and $400 million of transmission plant, included in the transmission rider.
(c)Based on September 30, 2020 test year.
(d)Based on 2021 forward test year.
(e)Based on December 31, 2020 test year and known and measurables through December 31, 2021.
(f)Based on December 31, 2017 test year and excludes $1.4 billion in cost recovery riders.
(g)Based on calculation as of December 31, 2021.
(h)See Note 2 to the financial statements for discussion of ongoing proceedings at the FERC challenging System Energy’s authorized return on common equity and capital structure.
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Entergy Corporation, Utility operating companies, and System Energy
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 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. 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 investment, 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.
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Entergy Corporation, Utility operating companies, and System Energy
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.
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.
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-
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Entergy Corporation, Utility operating companies, and System Energy
corporate debt financing of a utility’s capital structure as well as the use of investment tax credits to mitigate the tax 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.
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 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.
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 over- or under-recovery of fuel and purchased energy costs.
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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 proceedings regarding 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, in July 2021, Entergy New Orleans submitted its formula rate plan filing and rates were implemented in November 2021. 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 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 efforts to recover storm-related costs.
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Entergy Corporation, Utility operating companies, and System Energy
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 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.
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Entergy Corporation, Utility operating companies, and System Energy
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. 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. Beginning in 2021, System Energy has implemented billing protocols to provide retail regulators with information regarding rates billed under the Unit Power Sales Agreement.
Franchises
Entergy Arkansas holds exclusive franchises to provide electric service in approximately 308 incorporated cities and towns in Arkansas. These franchises are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas franchises are considered to be contracts and, therefore, are terminable pursuant to the terms of the franchise agreement and applicable statutes.
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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 69 incorporated municipalities. Entergy Texas typically obtains 25-year franchise agreements as existing agreements expire. Entergy Texas’s electric franchises expire over the period 2022-2058.
The business of System Energy is limited to wholesale power sales. It has no distribution franchises.
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, 2021, is indicated below:
Owned and Leased Capability MW(a)
Company Total Gas/Oil Nuclear Coal Hydro Solar
Entergy Arkansas 5,175 2,091 1,819 1,193 72 -
Entergy Louisiana 10,741 8,261 2,140 340 - -
Entergy Mississippi 3,252 2,938 - 312 - 2
Entergy New Orleans 666 639 - - - 27
Entergy Texas 3,256 3,004 - 252 - -
System Energy 1,263 - 1,263 - - -
Total 24,353 16,933 5,222 2,097 72 29
(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.
Summer peak load for the Utility has averaged 21,557 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.
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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 9,243 MW of new long-term resources and the deactivation of about 4,353 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.
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;
•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. The self-build alternative will be constructed upon receipt of regulatory approvals. The facility is expected to be in service by mid-2026;
•Entergy New Orleans received regulatory approval in August 2019 to construct the New Orleans Solar Station (a 20 MW self-build solar project) located at the NASA Michoud Facility. The facility was placed in service in December 2020;
•In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be 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 facility was placed in service in January 2022;
•In October 2018, Entergy Mississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and the facility is scheduled to be in service by mid-2022;
•In June 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy 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 facility. Closing was targeted to occur in 2022. The counter-party has notified Entergy Arkansas that it is seeking changes to certain terms of the build-own-transfer agreement, including both cost and schedule. Negotiations are ongoing, but at this time the project is not expected to achieve commercial operation in 2022;
•In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,500 acres in
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Crittenden County, Arkansas. In October 2021, the APSC issued an order approving the acquisition of the facility. Closing is expected to occur in 2023; and
•In November 2021, Entergy Louisiana signed an agreement for the purchase of an approximately 150 MW to-be-constructed solar photovoltaic energy facility that will be sited in St. James Parish near Vacherie, Louisiana. In November 2021, Entergy Louisiana filed a petition with the LPSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur in 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 May 2011, Entergy Texas and Calpine Energy Services, L.P. executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. Entergy Louisiana purchases 50% of the facility’s capacity and energy from Entergy Texas. In November 2019, LS Power sold and transferred the Carville Energy Center and facility to Argo Infrastructure Partners, which included the power purchase agreement;
•In September 2012, Entergy Gulf States Louisiana executed a 20-year agreement for 28 MW, with the potential to purchase an additional 9 MW when available, from Rain CII Carbon LLC’s petroleum coke calcining facility in Sulphur, Louisiana. The facility began commercial operation in May 2013. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with the facility;
•In March 2013, Entergy Gulf States Louisiana executed a 20-year agreement for 8.5 MW from Agrilectric Power Partners, LP’s refurbished rice hull-fueled electric generation facility located in Lake Charles, Louisiana. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with Agrilectric;
•In September 2013, Entergy Louisiana executed a 10-year agreement with TX LFG Energy, LP, a wholly-owned subsidiary of Montauk Energy Holdings, LLC, to purchase approximately 3 MW from its landfill gas-fueled power generation facility located in Cleveland, Texas;
•Entergy Mississippi’s cost-based purchase, beginning in January 2013, of 90 MW from Entergy Arkansas’s share of Grand Gulf (only 60 MW of this PPA came through the RFP process). Cost recovery for the 90 MW was approved by the MPSC in January 2013;
•In April 2015, Entergy Arkansas and Stuttgart Solar, LLC executed a 20-year agreement for 81 MW from a solar photovoltaic electric generation facility located near Stuttgart, Arkansas. The APSC approved the project and deliveries pursuant to that agreement commenced in June 2018;
•In November 2016, Entergy Louisiana and LS Power executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. 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 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 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 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 October 2022;
•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 solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in August 2022;
•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a solar photovoltaic electric generating facility located in Polk County, Texas. The PPA is expected to start when the facility reaches commercial operation in 2023;
•In June 2021, Entergy Louisiana and Sunlight Road Solar, LLC executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in Washington Parish, Louisiana. In November 2021, Entergy Louisiana signed an amended and re-stated PPA and filed a petition with the LPSC requesting all necessary approvals. The facility is expected to reach commercial operation in February 2024;
•In June 2021, Entergy Louisiana and St. James Solar II, LLC and Vacherie Solar Energy Center, LLC executed a 20-year agreement for 150 MW from a solar photovoltaic electric generating facility located in St. James Parish, Louisiana. In November 2021, Entergy Louisiana signed the PPA and filed a petition with the LPSC requesting all necessary approvals. The facility is expected to reach commercial operation in May 2024; and
•In November 2021, Entergy Louisiana signed a PPA for approximately 125 MW from a to-be-constructed solar photovoltaic energy facility in Allen, Louisiana. Following execution of the agreement, Entergy Louisiana filed a petition with the LPSC requesting all necessary approvals. The facility is expected to reach commercial operation in February 2024.
In March 2021, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic resources. The RFP is seeking up to 600 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 July 2021, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar generation resources. The RFP is seeking a target of 400 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. Evaluations are currently in progress.
In August 2021, Entergy Services, on behalf of Entergy Arkansas, 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 Arkansas customers.
In January 2022, 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.
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Other Procurements From Third Parties
The Utility operating companies have also made resource acquisitions outside of the RFP process, including Entergy Mississippi’s January 2006 acquisition of the 480 MW, combined-cycle, gas-fired Attala power plant; Entergy Gulf States Louisiana’s March 2008 acquisition of the 322 MW, simple-cycle, gas-fired Calcasieu Generating Facility; Entergy Louisiana’s April 2011 acquisition of the 580 MW, combined-cycle, gas-fired Acadia Energy Center Unit 2; 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 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. If approved, 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 and is evaluating when to file a new application for a distributed generation-related tariff.
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.
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.
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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-electric production facilities, combustion-turbine generators, reciprocating internal combustion engine generators, pressurized and boiling water nuclear reactors, and inverter-based technologies integrating both solar resources and energy storage devices that operate in the MISO energy and ancillary services 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, 2021, 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, 2021, 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.
Fuel Supply
The sources of generation and average fuel cost per kWh for the Utility operating companies and System Energy for the years 2019-2021 were:
Natural Gas Nuclear Coal Purchased Power MISO Purchases
Year % of Gen Cents Per kWh % of Gen Cents Per kWh % of Gen Cents Per kWh % of Gen Cents Per kWh % of Gen Cents Per kWh
2021 46 3.75 30 0.56 6 2.48 6 5.82 12 4.08
2020 47 1.92 29 0.57 3 2.54 8 4.36 13 2.48
2019 40 2.33 28 0.73 6 2.31 8 4.86 18 2.71
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Actual 2021 and projected 2022 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:
Natural Gas Nuclear Coal Solar Purchased Power (c) MISO Purchases (d)
2021 2022 2021 2022 2021 2022 2021 2022 2021 2022 2021 2022
Entergy Arkansas (a) 26 % 17 % 52 % 60 % 16 % 20 % - 1 % 1 % 2 % 5 % -
Entergy Louisiana 50 % 48 % 27 % 33 % 2 % 5 % - - 8 % 14 % 13 % -
Entergy Mississippi 61 % 56 % 24 % 31 % 6 % 11 % - 2 % - - 9 % -
Entergy New Orleans 45 % 42 % 43 % 50 % 2 % 3 % - 1 % 1 % 4 % 9 % -
Entergy Texas 48 % 57 % 10 % 17 % 4 % 10 % - - 16 % 16 % 22 % -
System Energy (b) - - 100 % 100 % - - - - - - - -
Utility (a) 46 % 42 % 30 % 39 % 6 % 10 % - - 6 % 9 % 12 % -
(a)Hydroelectric power provided less than 1% of Entergy Arkansas’s generation in 2021 and is expected to provide less than 1% of its generation in 2022.
(b)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.
(c)Excludes MISO purchases.
(d)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 2021 is not projected for 2022.
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 2022, 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. 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.
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Coal
Entergy Arkansas has committed to six one- to three-year contracts that will supply approximately 85% of the total coal supply needs in 2022. These contracts are staggered in term so that not all contracts have to be renewed the same year. The remaining 15% of total coal requirements will be satisfied by contracts with a term of less than one year. Based on continued improved Powder River Basin (PRB) coal deliveries by rail and the high cost of alternate sources and modes of transportation, no alternative coal consumption is expected at Entergy Arkansas during 2022. Coal will be transported to Arkansas via a Union Pacific transportation agreement that is expected to provide all of Entergy Arkansas’s rail transportation requirements for the first half of 2022. A new long-term transportation agreement is anticipated to be executed to meet Entergy Arkansas’s rail transportation requirements for the second half of 2022.
Entergy Louisiana has committed to two one- to three-year contracts that will supply approximately 90% of Nelson Unit 6 coal needs in 2022. 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 for Entergy Arkansas’s plants, no alternative coal consumption is expected at Nelson Unit 6 during 2022. Coal will be transported to Nelson primarily via an existing transportation agreement that is expected to provide all of Entergy Louisiana’s rail transportation requirements for 2022.
For the year 2021, 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. The rate of deliveries has begun to improve and is expected to normalize later in 2022. Both Entergy Arkansas and Entergy Louisiana control a sufficient number of 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 2022. 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 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
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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 2021 under a firm contract from Sequent Energy Management L.P. The gas is delivered through a combination of intrastate and interstate pipelines.
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,
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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.
System Agreement (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Prior to each operating company’s termination of participation in the System Agreement (Entergy Arkansas in December 2013, Entergy Mississippi in November 2015, and Entergy Louisiana, Entergy New Orleans, and Entergy Texas each in August 2016), the Utility operating companies engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which was a rate schedule approved by the FERC. Under the terms of the System Agreement, generating capacity and other power resources were jointly operated by the Utility operating companies that were participating in the System Agreement. The System Agreement provided, among other things, that parties having generating reserves greater than their allocated share of reserves (long companies) would receive payments from those parties having generating reserves that were less than their allocated share of reserves (short companies). Such payments were at amounts sufficient to cover certain of the long companies’ costs for intermediate and peaking oil/gas-fired generation, including operating expenses, fixed charges on debt, dividend requirements on preferred equity, and a fair rate of return on common equity investment. Under the System Agreement, the rates used to compensate long companies were based on costs associated with the long companies’ steam electric generating units fueled by oil or gas and having an annual average heat rate above 10,000 Btu/kWh. In addition, for all energy exchanged among the Utility operating companies under the System Agreement, the companies purchasing exchange energy were required to pay the cost of fuel consumed in generating such energy plus a charge to cover other associated costs.
Although the System Agreement has terminated, certain of the Utility operating companies’ and their retail regulators are pursuing litigation involving the System Agreement at the FERC and in federal courts. The proceedings include challenges to the allocation of costs as defined by the System Agreement and other matters. See Note 2 to the financial statements for discussion of legal proceedings at the FERC and in federal courts involving the System Agreement.
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 July 2001 a rate proceeding commenced by System Energy at the
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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 with the FERC regarding System Energy’s return on equity.
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.
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 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.
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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 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 its two outstanding series of first mortgage bonds. 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 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
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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.
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
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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.
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.
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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
Entergy Wholesale Commodities includes the ownership, operation, and decommissioning of nuclear power plants, located in the northern United States, and the sale of the electric power produced by its operating plant, Palisades, to wholesale customers. Entergy Wholesale Commodities also provides operations and management services, including decommissioning-related services, to nuclear power plants owned by non-affiliated entities in the United States. Entergy Wholesale Commodities also includes the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers.
See “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion of the operation and planned shutdown and sale of each of the remaining Entergy Wholesale Commodities nuclear power plants.
Property
Nuclear Generating Stations
Entergy Wholesale Commodities includes the ownership of the following nuclear power plant as of December 31, 2021:
Power Plant Market In Service Year Acquired Location Capacity - Reactor Type License Expiration Date
Palisades (a) MISO 1971 April 2007 Covert,
MI 811 MW - Pressurized Water 2031 (a)
(a)The Palisades plant is expected to cease operations on May 31, 2022. Entergy and Holtec jointly filed a license transfer application with the NRC in December 2020, requesting approval for the transfer of the Palisades and Big Rock Point licenses from Entergy to Holtec. The NRC approved the license transfer application in December 2021.
Entergy Wholesale Commodities also includes the ownership of one non-operating nuclear facility, Big Rock Point in Michigan, that was acquired when Entergy purchased the Palisades plant. Big Rock Point is under contract to be sold with Palisades to Holtec.
See “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion of the operation and planned shutdown and sale of each of the remaining Entergy Wholesale Commodities nuclear power plants.
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Non-nuclear Generating Stations
Entergy Wholesale Commodities includes the ownership, or interests in joint ventures that own, 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
RS Cogen; 425 MW (c) Lake Charles, LA 50% 213 MW Gas/Steam
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.
(c)Indirectly owned through an interest in an unconsolidated joint venture. In December 2020, Entergy’s wholly-owned subsidiary with a direct interest in RS Cogen, LLC entered into a membership interest purchase agreement with a subsidiary of the other 50% equity partner to sell its 50% membership interest in the joint venture to the equity partner. The targeted closing date for the transaction is October 2022.
Independent System Operator
The Palisades plant falls under the authority of the MISO. The primary purpose of MISO is to direct the operations of the major generation and transmission facilities in their region; ensure grid reliability; administer and monitor wholesale electricity markets; and plan for their region’s energy needs.
Energy and Capacity Sales
As a wholesale generator, Entergy Wholesale Commodities’ core business is selling energy, measured in MWh, to its customers. As part of the purchase of the Palisades plant in 2007, Entergy executed a 15-year PPA with the seller, Consumers Energy, for 100% of the plant’s output, excluding any future uprates. Under the purchased power agreement, Consumers Energy received the value of any new environmental credits for the first fourteen years of the agreement. Palisades and Consumers Energy will share on a 50/50 basis the value of any new environmental credits for the last year of the agreement. The environmental credits are defined as benefits from a change in law that causes capability of the plant as of the purchase date to become a tradable attribute (e.g., emission credit, renewable energy credit, environmental credit, “green” credit, etc.) or otherwise to have a market value. Entergy intends to shut down the Palisades plant permanently on May 31, 2022 and transfer to Holtec thereafter.
Customers
Entergy Wholesale Commodities’ customers for the sale of both energy and capacity from its nuclear plants 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 MISO. Substantially all the credit exposure associated with the planned energy output under contract for Palisades is with counterparties or their guarantors that have public investment grade credit ratings.
Competition
MISO does not have a centralized clearing capacity market, but load serving entities do meet most of their capacity needs through bilateral contracts and self-supply with a smaller portion coming through voluntary MISO
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auctions. Almost all of Palisades’ current output is contracted to Consumers Energy through May 2022. Entergy Wholesale Commodities does not expect to be materially affected by competition in the MISO market in the near term.
Seasonality
Entergy Wholesale Commodities’ revenues and operating income are subject to fluctuations during the year due to seasonal factors, weather conditions, and contract pricing. When outdoor and cooling water temperatures are low, generally during colder months, Entergy Wholesale Commodities’ nuclear power plants operate more efficiently, and consequently, generates more electricity. Entergy Wholesale Commodities’ contracts provide for shaped pricing over the course of the year. As a result of these factors, Entergy Wholesale Commodities’ revenues are typically higher in the first and third quarters than in the second and fourth quarters.
Fuel Supply
Nuclear Fuel
See “Fuel Supply - Nuclear Fuel” in the Utility portion of Part I, Item 1 for a discussion of the nuclear fuel cycle and markets. Entergy Nuclear Fuels Company, a wholly-owned subsidiary, was responsible for contracts to acquire nuclear materials, except for fuel fabrication, for Entergy Wholesale Commodities nuclear power plants, while Entergy Nuclear Operations, Inc. acted as the agent for the purchase of nuclear fuel assembly fabrication services. All contracts for the disposal of spent nuclear fuel were between the DOE and each of the nuclear power plant owners. 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 of the Palisades plant. Fuel procurement for the Entergy Wholesale Commodities segment ceased after the Palisades plant’s final refueling in 2020.
Other Business Activities
Entergy Nuclear Power Marketing, LLC (ENPM) was formed in 2005 to centralize the power marketing function for Entergy Wholesale Commodities nuclear plants. Upon its formation, ENPM entered into long-term power purchase agreements with the Entergy Wholesale Commodities subsidiaries that owned nuclear power plants (generating subsidiaries). As part of a series of agreements, ENPM agreed to assume and/or otherwise service the existing power purchase agreements that were in effect between the generating subsidiaries and their customers. ENPM’s functions include origination of new energy and capacity transactions and generation scheduling.
Services provided by either Entergy Nuclear, Inc. or other Entergy Wholesale Commodities subsidiaries include engineering, operations and maintenance, fuel procurement, management and supervision, technical support and training, administrative support, and other managerial or technical services required to operate, maintain, and decommission nuclear electric power facilities.
TLG Services, a subsidiary in the Entergy Wholesale Commodities segment, offers decommissioning, engineering, and related services to nuclear power plant owners.
Entergy provides plant operation support services for the 800 MW Cooper Nuclear Station located near Brownville, Nebraska. In 2010 an Entergy subsidiary signed an agreement to extend the management support services to Cooper Nuclear Station by 15 years, through January 2029.
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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 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.
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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 or other regulatory 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 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 environmental adjustment charge, avoided cost payment to non-exempt Qualifying Facilities, and energy efficiency rider;
•integrated resource planning;
•net energy metering; and
•utility mergers and acquisitions and other changes of control.
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
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•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.
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. Entergy subsidiaries in the Entergy Wholesale Commodities segment are subject to the NRC’s jurisdiction as the owners and operators of Palisades and Big Rock Point.
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, 2021 of $192.1 million for the one-time fee. Entergy accepted assignment of the Palisades and Big Rock Point spent fuel disposal contracts with the DOE held by their previous owner. The owner of these plants prior to Entergy has paid or retained liability for the fees for all generation prior to the purchase dates of the 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 billion (exclusive of amounts relating to Entergy plants that were paid or are owed by prior owners of those plants).
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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.
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 2019, 2020, and 2021 related to Entergy’s nuclear owner licensee subsidiaries’ litigation with the DOE. Through 2021, Entergy’s subsidiaries won and collected on judgments against the government totaling approximately $900 million.
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, 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 October 2020, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that both ANO 1 and ANO 2
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decommissioning trusts were adequately funded without further collections, and in December 2020, the APSC ordered zero collections for ANO 1 and ANO 2 decommissioning.
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. Management cannot predict the outcome of this filing. A hearing in the case has been scheduled for September 2022.
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 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.
In March 2021 filings with the NRC were made reporting on decommissioning funding for all of Entergy 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 95 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, Entergy Louisiana, 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
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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 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. The nuclear generating plants owned and operated by Entergy’s Utility and Entergy Wholesale Commodities businesses are currently in Column 1.
In March 2021 the NRC placed Grand Gulf in Column 3 based on the incidence of five unplanned plant scrams during calendar year 2020, some of which were related to upgrades made to the plant’s turbine control system during the spring 2020 refueling outage. The NRC conducted a supplemental inspection of Grand Gulf in accordance with its inspection procedures for nuclear plants in Column 3 and, in October 2021, notified Entergy that all inspection objectives were met. The NRC issued its report in November 2021 and Grand Gulf was returned to Column 1.
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;
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•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.
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 construction and 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 SO2 Nonattainment
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 fine 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. The EPA must file status reports with the court every 120 days. 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
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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 September 2016 the EPA finalized the CSAPR Update Rule to address interstate transport for the 2008 ozone NAAQS. Starting in 2017 the final rule requires reductions in summer nitrogen oxides (NOx) emissions. Several states, including Arkansas and Texas, filed a challenge to the Update Rule. In September 2019 the D.C. Circuit upheld the EPA’s underlying approach to the Update Rule, but determined that it was inconsistent with the Clean Air Act because it failed to include deadlines consistent with downwind states’ deadlines for attainment. The court remanded the rule to the EPA for further consideration, but did not vacate it so the rule remains in effect pending the EPA’s further review. In April 2021, addressing the D.C. Circuit’s remand, the EPA finalized revisions to the Update Rule, which became effective June 29, 2021. The rule finalizes interstate transport obligations for 21 states. For 12 states, including Louisiana, the EPA further reduced the number of NOx emission allowances allocated to each state. Entergy is currently analyzing the potential impact on its facilities in Louisiana. Early indications are that the cost of Group 3 allowances will increase significantly (approximately $3,000 per allowance) in the near-term, which could impact the cost to dispatch Entergy’s legacy gas units located in Louisiana. However, Entergy’s 2021 ozone season NOx emissions were below 2020 levels and it does not appear that additional allowances will be needed to satisfy Entergy’s 2021 obligations. The final determination will be made in March 2022.
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 (BART) 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
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meet the other requirements of the settlement.
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 visibility improvements. Entergy has 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. The LDEQ is now expected to finalize its Regional Haze SIP in early 2022.
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 and is expected to issue a proposed SIP for the second planning period in the first quarter of 2022.
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, the Clean Power Plan will not take effect during the rulemaking process and 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. The court’s decision could impact whether and to what extent the EPA may regulate greenhouse gases. Despite the pending decision, the EPA appears to be moving forward with a new proposal to regulate greenhouse gas emissions from new and existing electric generating units.
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
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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 gases, and all emissions. 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 2021 was listed on the North American Index. Entergy has been listed on the World or North American Index, or both, for twenty consecutive years. Entergy also participated in the 2021 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 NOx, SO2, mercury, carbon dioxide and other air emissions. New legislation or regulations applicable to stationary sources could take the form of market-based cap-and-trade programs, direct requirements for the installation of air emission controls onto air emission sources, or other or combined regulatory programs;
•efforts in Congress or at the EPA to establish a federal carbon dioxide emission tax, control structure, or unit performance standards;
•revisions to the estimates of the Social Cost of Carbon and its use for regulatory impact analysis of federal laws and regulations;
•implementation of the regional 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;
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•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.
Steam Electric Effluent Guidelines
The 2015 Steam Electric Effluent Limitations Guidelines (ELG) rule required, among other things, that there be no discharge of bottom ash transport water. In October 2020 the EPA issued its final rule revision on bottom ash transport water allowing the discharge of up to 10% system volume for certain purge waters, including storm events and non-routine operations. The final rule requires compliance as soon as possible beginning October 31, 2021, but no later than December 31, 2025. Several challenges to the final rule have been filed. Additionally, the Fifth Circuit Court of Appeals previously vacated and remanded the provisions of the rule related to legacy wastewater and leachate, which the EPA plans to address in a separate rulemaking. Despite the final rule and pending challenges, Entergy has implemented projects at its White Bluff and Independence plants to convert to zero-discharge systems to comply with the ELG rule and the coal combustion residuals restrictions on impoundments. Additionally, the Nelson Unit 6 facility is implementing operational and maintenance measures to minimize the potential for discharge of bottom ash transport water from the existing bottom ash handling system at the site, and is reviewing the effectiveness of these changes for compliance with the requirements of the October 2020 final rule.
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 2021, the EPA and the Corps proposed a revised definition of waters of the United States by repealing the NWPR and codifying a definition that reflects the pre-2015 regulatory regime as interpreted by several United States Supreme Court decisions. Comments on the proposed rule were due in February 2022. In January 2022, despite pending rulemaking, the United States Supreme Court agreed to hear a case regarding the proper test under previous Supreme Court decisions for determining jurisdiction of waters of the United States. This case likely will impact the current rulemaking process but it still is unclear whether the final rulemaking will be delayed to await guidance from the Supreme Court or the agencies will finalize the rule prior to the Supreme Court’s consideration of the matter.
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Groundwater at Certain Nuclear Sites
The NRC requires nuclear power plants to monitor and report regularly the presence of radioactive material in the environment. Entergy joined other nuclear utilities and the Nuclear Energy Institute in 2006 to develop a voluntary groundwater monitoring and protection program. This initiative began after detection of very low levels of radioactive material, primarily tritium, in groundwater at several plants in the United States. Tritium is a radioactive form of hydrogen that occurs naturally and is also a byproduct of nuclear plant operations. In addition to tritium, other radionuclides have been found in site groundwater at nuclear plants.
As part of the groundwater monitoring and protection program, Entergy has: (1) performed reviews of plant groundwater characteristics (hydrology) and historical records of past events on site that may have potentially impacted groundwater; (2) implemented fleet procedures on how to handle events that could impact groundwater; and (3) installed groundwater monitoring wells and began periodic sampling. The program also includes protocols for notifying local officials if contamination is found. To date, radionuclides such as tritium have been detected at Arkansas Nuclear One, Palisades, Grand Gulf, and River Bend. Each of these sites has installed groundwater monitoring wells and implemented a program for testing groundwater at the sites for the presence of tritium and other radionuclides. Based on current information, the concentrations and locations of radionuclides detected at these plants pose no threat to public health or safety, but each site continues to evaluate the results from its groundwater monitoring program.
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 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.
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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, 2021, Entergy has recorded asset retirement obligations related to CCR management of $21 million.
In December 2016 the Water Infrastructure Improvements for the Nation Act (WIIN Act) was signed into law, which authorizes states to regulate coal ash rather than leaving primary enforcement to citizen suit actions. States may submit to the EPA proposals for a permit program.
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. The demand letter is being evaluated and liability and PRP 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.
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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, 2021, Entergy subsidiaries employed 12,369 people.
Utility:
Entergy Arkansas 1,220
Entergy Louisiana 1,656
Entergy Mississippi 741
Entergy New Orleans 299
Entergy Texas 669
System Energy -
Entergy Operations 3,380
Entergy Services 3,798
Entergy Nuclear Operations 571
Other subsidiaries 35
Total Entergy 12,369
Approximately 3,400 employees are represented by the International Brotherhood of Electrical Workers, the Utility Workers Union of America, the United Government Security Officers of America, and the International Union, Security, Police, and Fire Professionals of America.
Below is the breakdown of Entergy’s employees by gender and race/ethnicity:
Gender (%) 2021 2020
Female 21.4 20.7
Male 78.6 79.3
Race/Ethnicity (%) 2021 2020
White 76.4 77.6
Black/African American 16.4 15.3
Hispanic/Latino 2.7 2.7
Asian 2.0 2.0
Other 2.5 2.4
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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 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 Personnel 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 Personnel 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.
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 0.46 in 2021, compared to 0.40 in 2020 and 0.56 in 2019. 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. 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.
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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 2019 of 66 (second quartile), in 2020 of 72 (second quartile), and in 2021of 63 (third quartile). Although the score declined in 2021 as compared to 2020, 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 90 percent in 2018-2021.
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. Among other actions, the primary focus of its 2021 actions was implementing customized DIB interventions 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.
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 (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
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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
Item 1A. RISK FACTORS
See “RISK FACTOR 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 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.
In December 2019 a novel strain of coronavirus was reported to have surfaced in Wuhan, China. Since then, several variants of the COVID-19 virus have spread throughout the world, including the United States. To mitigate the spread of COVID-19, public health officials in the United States have at various times both recommended and mandated wearing of masks and other precautions, including prohibitions on congregating in heavily-populated areas, closure or limitations on the functions of non-essential business, and shelter-in-place orders or similar measures, including throughout Entergy’s service areas. While many of these mitigation measures have been lifted following the wide availability of COVID-19 vaccines, there is a risk that certain of these measures could be reinstated and/or continued or that customers could elect to curtail operations to reduce the spread of an outbreak, and that such measures could have an adverse effect on the general economy, Entergy’s customers, and its operations.
Entergy and its Utility operating companies experienced a decline in commercial and industrial sales and an increase in arrearages and bad debt expense due to non-payment by customers. Much of the commercial and industrial sales have recovered, and the arrearages have begun to decline, although management cannot predict the timing of the completion of collections of such arrearages. The Utility operating companies have resumed disconnecting customers for non-payment of bills, but such disconnects could again be suspended at the Utility operating companies by their various regulators, for various reasons, including should another shelter-in-place order or similar measure occur. While they 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, 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, quarantining, or concerns with vaccination or testing mandates, health or safety issues; increased storm recovery costs; increased cybersecurity risks as a result of many employees telecommuting; risks or uncertainties associated with the return for many employees from telecommuting to on-site work on a full-time or hybrid basis; 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.
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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 increasingly inflationary environment. In addition, if the COVID-19 pandemic creates additional disruptions or turmoil in the credit or financial markets, or adversely impacts 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 outbreak, the impact of new or existing variants of COVID-19, the effectiveness of mitigation efforts, vaccines, anti-viral or other treatments for COVID-19, 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.
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 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.
In addition, regulators may initiate 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.
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. 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
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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. 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 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.
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, 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 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. For a description of fuel and purchased power recovery mechanisms and information regarding the regulatory proceedings for fuel and purchased power costs 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’
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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 generating facilities into the MISO 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. 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.
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.
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(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 (including from Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Hurricane Ida), or the impact on customer bills of permitted storm cost recovery, 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 or revenues lost as a result of severe weather could have a material effect on Entergy and those Utility operating companies affected by severe weather. 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.
In August and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of the Utility’s service areas in Louisiana, including New Orleans, Texas, and to a lesser extent, in Arkansas and Mississippi. The storms resulted in widespread power outages, significant damage to distribution and transmission infrastructure, and the loss of sales during the outages. Additionally, as a result of Hurricane Laura’s extensive damage to the grid infrastructure serving the impacted area, large portions of the underlying transmission system required nearly a complete rebuild. Total restoration costs for the repair and/or replacement of the electrical system damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta were approximately $2.4 billion.
In August 2021, Hurricane Ida caused extensive damage to the Entergy distribution and, to a lesser extent, transmission systems across Louisiana resulting in widespread power outages. Total restoration costs for the repair and/or replacement of the electrical system damaged by Hurricane Ida for Entergy Louisiana and Entergy New Orleans are currently estimated to be approximately $2.7 billion. Most of the storm costs were incurred by Entergy Louisiana and Entergy New Orleans. Also, Utility revenues in 2021 were adversely affected by extended power outages resulting from the hurricane.
Because Entergy has not completed the regulatory processes regarding these storm costs, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
Nuclear Operating, Shutdown, and Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)
Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities must 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, System Energy, and Entergy Wholesale Commodities. 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
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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 plant, lower capacity factors directly affect revenues and cash flow from operations.
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 2021 and beyond. 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, 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; 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 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.
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
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), its 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 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.
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, System Energy, or Entergy Wholesale Commodities.
Certain of the Utility operating companies, 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, System Energy, and 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 the 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 the Utility operating companies and System Energy, this could result in certain costs being stranded 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.
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
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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.
The costs associated with the storage of the spent nuclear fuel of certain of the Utility operating companies, 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, System Energy, and the Palisades plant owner 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, 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 from 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, 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. 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 95 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
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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, System Energy, and the Palisades plant owner, regardless of fault or proximity to the incident, will be required to 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 $826 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, System Energy, and the owners of the Palisades plant. 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 to insured losses. As of December 31, 2021, the maximum annual assessment amounts total approximately $98 million for the Utility plants. Retrospective premium insurance available through NEIL’s reinsurance treaty can cover the potential assessments and the Palisades plant owner currently maintains 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, or liquidity of Entergy, certain of the Utility operating companies, System Energy, or the Entergy Wholesale Commodities subsidiaries.
The decommissioning trust fund assets for the nuclear power plants owned by the Utility operating companies, 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, System Energy, and the Palisades plant owner maintain decommissioning trust funds for this purpose. Certain of the Utility operating companies 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
Part I Item 1A and 1B
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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.
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 Utility operating companies, System Energy, or the Palisades plant owner 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’s results of operations, liquidity, and financial condition 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 the Utility operating companies, System Energy, or the Palisades plant owner may be required to provide significant additional funds or credit support to satisfy regulatory requirements for decommissioning, which, with respect to the Utility operating companies, 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, the impairment charges that resulted from such decision, and the planned sale of Palisades (which will include the transfer of the associated 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 and 14 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.
(Entergy Corporation)
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.
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. 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 $1.29 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.
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.
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
General Business
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Entergy and the Utility operating companies 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 and Entergy Wholesale Commodities. In addition, Entergy’s and the Utility operating companies’ 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 territory with Hurricane Katrina and Hurricane Rita in 2005, 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 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 and the Utility operating companies, 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 companies that are impacted by 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 (including an increasing interest rate environment) 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. 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.
(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 number of factors that rating agencies evaluate to arrive at credit ratings for each of Entergy Corporation 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, any of the Utility operating companies’, or System Energy’s ratings, particularly
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
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 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 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 Corporation or its subsidiaries. At December 31, 2021 based on power prices at that time, Entergy had liquidity exposure of $29 million under the guarantees in place supporting Entergy Wholesale Commodities transactions and $8 million of posted cash collateral. In the event of a decrease in Entergy Corporation’s credit rating to below investment grade, based on power prices as of December 31, 2021, Entergy would have been required to provide approximately $30 million of additional cash or letters of credit under some of the agreements.
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 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.
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 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 2019, 2020, and 2021 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.
Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy’s, the Utility operating companies’, and System Energy’s 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, 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’, and System Energy’s results of operations, financial condition, and liquidity. For instance, pending federal tax legislation, including the Build Back Better Act or related legislation, could significantly change the U.S. Internal Revenue Code, including the taxation of U.S. corporations, by, among other things, adopting an alternative minimum income tax on a U.S. corporation’s book income. The intended and unintended consequences
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
of this proposed 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, 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, Entergy has entered into an agreement to sell its equity interests in the subsidiary that owns Palisades and the decommissioned Big Rock Point Nuclear Power Plant after Palisades has been shut down and defueled. Also, 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;
•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, 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, 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,
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reliance on suppliers for timely and satisfactory performance, and pandemic-related delays and cost increases. 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, supply chain delays or disruptions, and other events beyond the control of the Utility operating companies or the Entergy Wholesale Commodities business 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 territory, and as to 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 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 anticipate future workforce needs, workforce impacts of 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.
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 the Entergy Wholesale Commodities business 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, System Energy, and the Entergy Wholesale Commodities business conduct their operations and make capital expenditures. These laws and regulations also affect how the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business 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
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
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, System Energy, and the Entergy Wholesale Commodities business 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, 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 currently are 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 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 compel greenhouse gas emission reductions, 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.
The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business 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 Wholesale Commodities businesses.
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
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 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, could reduce sales, and other non-traditional procurements, such as virtual purchase power agreements, could limit growth opportunities 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, 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 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
The effects of climate change, environmental and regulatory obligations intended to compel greenhouse gas emission reductions or increase clean or renewable energy requirements or to place a price on greenhouse gas emissions, or achieving voluntary climate commitments could materially affect the financial condition, results of operations, and liquidity of Entergy, the Utility operating companies, 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, 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. 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 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 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 the Utility operating companies, System Energy, or Entergy Wholesale Commodities do business. Violations of such requirements may subject Entergy Wholesale Commodities and 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 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 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 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) 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
In September 2020, Entergy voluntarily committed to achieving net zero carbon emissions by 2050. Technology research and development, innovation, and advancement are critical to Entergy’s ability to achieve this commitment. Moreover, Entergy cannot predict the ultimate impact of achieving this objective, 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, the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business.
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, 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 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, Entergy Wholesale Commodities’, System Energy’s, and the Utility operating companies’ financial condition, results of operations, and liquidity.
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 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
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
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 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, 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 the Entergy Wholesale Commodities business 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
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
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 certain Entergy 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 ratepayer matters, and injuries and damages issues, among other matters. The states in which the Utility operating companies 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 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 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 and employees, 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 an act or threat 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
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
contractors. Further, attacks may become more frequent in the future as technology becomes more prevalent in energy infrastructure. An actual act 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 coverage for cyber-attacks or data breaches, such insurance 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).
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 its 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 its 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 period when gas is purchased and the time when ultimate recovery from customers occurs.
Part I Item 1A and 1B
Entergy Corporation, Utility operating companies, and System Energy
(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.
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 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 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 net book value of System Energy. 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. 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.
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 5 and 8 to the financial statements and the “Utility - System Energy and Related Agreements” 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 are paid directly to Entergy Utility Holding Company and are therefore subject to prior payment of distributions on its preferred securities.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments
None.
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
2021 Compared to 2020
Net Income
Net income increased $53.3 million primarily due to higher volume/weather and higher retail electric price, partially offset by a higher effective income tax rate, higher depreciation and amortization expenses, and higher other operation and maintenance expenses.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 2021 to 2020:
Amount
(In Millions)
2020 operating revenues $2,084.5
Fuel, rider, and other revenues that do not significantly affect net income 170.5
Volume/weather 46.4
Retail electric price 37.2
2021 operating revenues $2,338.6
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 volume/weather variance is primarily due to an increase of 1,531 GWh, or 7%, in billed electricity usage, including an increase in industrial usage and the effect of more favorable weather on residential and commercial sales. The increase in industrial usage is primarily due to an increase in demand from expansion projects, primarily in the metals industry.
The retail electric price variance is primarily due to an increase in formula rate plan rates effective May 2021. See Note 2 to the financial statements for further discussion of the 2020 formula rate plan filing.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Billed electric energy sales for Entergy Arkansas for the years ended December 31, 2021 and 2020 are as follows:
2021 2020 % Change
(GWh)
Residential 8,054 7,584 6
Commercial 5,492 5,356 3
Industrial 8,509 7,586 12
Governmental 225 223 1
Total retail 22,280 20,749 7
Sales for resale:
Associated companies 2,254 1,659 36
Non-associated companies 6,151 4,198 47
Total 30,685 26,606 15
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 $13.5 million in compensation and benefits costs in 2021 primarily due to higher incentive-based compensation accruals in 2021 as compared to prior year, lower healthcare claims activity in 2020 as a result of the COVID-19 pandemic, an increase in healthcare cost rates, and an increase in net periodic pension and other postretirement benefits costs as a result of a decrease in the discount rate used to value the benefit liabilities. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs;
•lower nuclear insurance refunds of $5.8 million;
•an increase of $5.8 million primarily due to an increase in contract costs related to customer solutions and sustainability initiatives, including customer service center support and enhanced customer billing;
•an increase of $3.6 million in distribution operations expenses primarily due to higher reliability costs; and
•an increase of $3.2 million as a result of the amount of transmission costs allocated by MISO.
The increase was partially offset by:
•a decrease of $6.9 million in nuclear generation expenses primarily due to lower nuclear labor costs, including contract labor, and a lower scope of work performed in 2021 as compared to 2020;
•a decrease of $5.9 million in meter reading expenses as a result of the deployment of advanced metering systems;
•a decrease of $4.6 million in energy efficiency expenses due to the timing of recovery from customers; and
•a decrease of $3.4 million in vegetation maintenance costs.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Other regulatory charges (credits) - net includes:
•regulatory credits of $46.6 million, recorded in 2020, to reflect the amortization of the 2018 historical year netting adjustment reflected in the 2019 formula rate plan proceeding. See Note 2 to the financial statements for discussion of the 2019 formula rate plan proceeding;
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Management’s Financial Discussion and Analysis
•regulatory charges of $43.5 million, recorded in the fourth quarter 2020, to reflect the 2019 historical year netting adjustment included in the APSC’s December 2020 order in the 2020 formula rate plan proceeding. See Note 2 to the financial statements for discussion of the 2020 formula rate plan proceeding; and
•the reversal in 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.
In addition, Entergy Arkansas records a regulatory charge or credit for the difference between asset retirement obligation-related expenses and trust earnings plus asset retirement obligation related costs collected in revenue.
Other income increased primarily due to changes in decommissioning trust fund investment activity, including portfolio rebalancing for the ANO 1 and ANO 2 decommissioning trust funds in 2021.
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 has recorded a regulatory charge of $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 20.1% for 2021 and 16.3% for 2020. 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.
2020 Compared to 2019
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, 2020, filed with the SEC on February 26, 2021, for discussion of results of operations for 2020 compared to 2019.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2021, 2020, and 2019 were as follows:
2021 2020 2019
(In Thousands)
Cash and cash equivalents at beginning of period $192,128 $3,519 $119
Net cash provided by (used in):
Operating activities 549,216 659,818 677,766
Investing activities (898,193) (795,709) (676,293)
Financing activities 169,764 324,500 1,927
Net increase (decrease) in cash and cash equivalents (179,213) 188,609 3,400
Cash and cash equivalents at end of period $12,915 $192,128 $3,519
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2021 Compared to 2020
Operating Activities
Net cash flow provided by operating activities decreased $110.6 million in 2021 primarily due to:
•increased fuel costs and 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;
•$25 million in proceeds received from the DOE in 2020 resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and
•an increase in spending of $18.1 million on nuclear refueling outages in 2021.
The decrease was partially offset by higher collections from customers.
Investing Activities
Net cash flow used in investing activities increased $102.5 million in 2021 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;
•an increase of $62.6 million in nuclear construction expenditures primarily due to increased spending on various nuclear projects in 2021 as compared to 2020; and
•$55 million in proceeds received from the DOE in 2020 resulting from litigation regarding spent nuclear fuel storage costs that were previously capitalized. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.
The increase was partially offset by:
•a decrease of $53.0 million in transmission construction expenditures primarily due to a lower scope of work on projects performed in 2021 as compared to 2020 and lower capital expenditures for storm restoration in 2021;
•a decrease of $32.8 million in distribution construction expenditures primarily due to lower capital expenditures for storm restoration and lower spending on advanced meter infrastructure in 2021, partially offset by a higher scope of work performed in 2021 as compared to 2020;
•a decrease of $20.9 million in decommissioning trust fund investment activity; and
•a decrease of $20.1 million in information technology construction expenditures primarily due to decreased spending on various technology projects, including advanced metering infrastructure.
Financing Activities
Net cash flow provided by financing activities decreased $154.7 million in 2021 primarily due to:
•the issuances of $100 million of 4.00% Series mortgage bonds in March 2020 and $675 million of 2.65% Series mortgage bonds in September 2020;
•the repayment, at maturity, of $350 million of 3.75% Series mortgage bonds due February 2021; and
•the repayment, at maturity, of $45 million of 2.375% Series governmental bonds due January 2021.
The decrease was partially offset by:
•the issuance of $400 million of 3.35% Series mortgage bonds in March 2021;
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Management’s Financial Discussion and Analysis
•the repayment in October 2020 of $200 million of 4.90% Series mortgage bonds due December 2052;
•money pool activity;
•the repayment in October 2020 of $125 million of 4.75% Series mortgage bonds due June 2063;
•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;
•a decrease of $45 million in common equity distributions in 2021 in order to maintain Entergy Arkansas’s capital structure; and
•higher prepaid deposits of $36 million related to contributions-in-aid-of-construction generation interconnection agreements in 2021 as compared to 2020.
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 by $139.9 million in 2021 compared to decreasing by $21.6 million in 2020. 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.
2020 Compared to 2019
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, 2020, filed with the SEC on February 26, 2021, for discussion of operating, investing, and financing cash flow activities for 2020 compared to 2019.
Capital Structure
Entergy Arkansas’s debt to capital ratio is shown in the following table. The decrease in the debt to capital ratio is primarily due to an increase in equity resulting from retained earnings in 2021.
December 31,
2021 December 31,
Debt to capital 52.6 % 54.8 %
Effect of subtracting cash - % (1.2 %)
Net debt to net capital 52.6 % 53.6 %
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. 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, 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
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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.
Following are the amounts of Entergy Arkansas’s planned construction and other capital investments.
2022 2023 2024
(In Millions)
Planned construction and capital investment:
Generation $285 $440 $320
Transmission 80 135 225
Distribution 270 310 490
Utility Support 125 95 65
Total $760 $980 $1,100
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Arkansas includes generation projects to modernize, decarbonize, and diversify Entergy Arkansas’s portfolio, such as the Walnut Bend Solar Facility and the West Memphis Solar Facility; 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, 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 Arkansas’s existing debt and lease obligations (includes estimated interest payments).
2022 2023 2024 2025-2026 After 2026
(In Millions)
Long-term debt (a) $138 $423 $501 $904 $4,771
Operating leases (b) $14 $13 $11 $17 $6
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.
Other Obligations
Entergy Arkansas currently expects to contribute approximately $40.8 million to its qualified pension plans and approximately $517 thousand to its other postretirement health care and life insurance plans in 2022, although the 2022 required pension contributions will be known with more certainty when the January 1, 2022 valuations are completed, which is expected by April 1, 2022. See “Critical Accounting Estimates - Qualified Pension and
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Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Entergy Arkansas has $415.9 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, 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 Facility
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. Entergy Arkansas views the progress of the outreach to potential tax equity investors and the current status of the discussions as consistent with its expectations for the timeline for achieving a tax equity partnership. Closing was expected to occur in 2022. The counter-party has notified Entergy Arkansas that it is seeking changes to certain terms of the build-own-transfer agreement, including both cost and schedule. Negotiations are ongoing, but at this time the project is not expected to achieve commercial operation in 2022.
West Memphis Solar Facility
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. Closing is expected to occur in 2023.
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.
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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.
2021 2020 2019 2018
(In Thousands)
($139,904) $3,110 ($21,634) ($182,738)
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 2026. Entergy Arkansas also has a $25 million credit facility scheduled to expire in April 2022. 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, 2021, 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, 2021, $8.5 million in 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 2024. As of December 31, 2021, $4.8 million in loans were 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 2022.
State and Local Rate Regulation and Fuel-Cost Recovery
Retail Rates
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
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change designed to produce a target rate of return on common equity of 9.75% is $15.3 million, which is based upon a deficiency of approximately $61.9 million for the 2020 projected year, netted with a credit of approximately $46.6 million in the 2018 historical year netting adjustment. During 2018 Entergy Arkansas experienced higher-than expected sales volume, and actual costs were lower than forecasted. These changes, coupled with a reduced income tax rate resulting from the Tax Cuts and Jobs Act, resulted in the credit for the historical year netting adjustment. In the fourth quarter 2018, Entergy Arkansas recorded a provision of $35.1 million that reflected the estimate of the historical year netting adjustment that was expected to be included in the 2019 filing. In 2019, Entergy Arkansas recorded additional provisions totaling $11.5 million to reflect the updated estimate of the historical year netting adjustment included in the 2019 filing. In October 2019 other parties in the proceeding filed their errors and objections requesting certain adjustments to Entergy Arkansas’s filing that would reduce or eliminate Entergy Arkansas’s proposed revenue change. Entergy Arkansas filed its response addressing the requested adjustments in October 2019. In its response, Entergy Arkansas accepted certain of the adjustments recommended by the General Staff of the APSC that would reduce the proposed formula rate plan rider revenue change to $14 million. Entergy Arkansas disputed the remaining adjustments proposed by the parties. In October 2019, Entergy Arkansas filed a unanimous settlement agreement with the other parties in the proceeding seeking APSC approval of a revised total formula rate plan rider revenue change of $10.1 million. In its July 2019 formula rate plan filing, Entergy Arkansas proposed to recover an $11.2 million regulatory asset, amortized over five years, associated with specific costs related to the potential construction of scrubbers at the White Bluff plant. Although Entergy Arkansas does not concede that the regulatory asset lacks merit, for purposes of reaching a settlement on the total formula rate plan rider amount, Entergy Arkansas agreed not to include the White Bluff scrubber regulatory asset cost in the 2019 formula rate plan filing or future filings. Entergy Arkansas recorded a write-off in 2019 of the $11.2 million White Bluff scrubber regulatory asset. In December 2019 the APSC approved the settlement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2020.
2020 Formula Rate Plan Filing
In July 2020, Entergy Arkansas filed with the APSC its 2020 formula rate plan filing to set its formula rate for the 2021 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2021, as amended through subsequent filings in the proceeding, and a netting adjustment for the historical year 2019. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2021 projected year is 8.22% resulting in a revenue deficiency of $64.3 million. The earned rate of return on common equity for the 2019 historical year was 9.07% resulting in a $23.9 million netting adjustment. The total proposed revenue change for the 2021 projected year and 2019 historical year netting adjustment was $88.2 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $74.3 million. 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 to customers in 2021. Entergy Arkansas also requested an extension of the formula rate plan rider for a second five-
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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.
Production Cost Allocation Rider
The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings.
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
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authorize Entergy Arkansas to exclude from the redetermination of its 2014 energy cost rate $65.9 million of incremental fuel and replacement energy costs incurred in 2013 as a result of the ANO stator incident. Entergy Arkansas requested that the APSC authorize Entergy Arkansas to retain that amount in its deferred fuel balance, with recovery to be reviewed in a later period after more information was available regarding various claims associated with the ANO stator incident. In February 2014 the APSC approved Entergy Arkansas’s request to retain that amount in its deferred fuel balance. In July 2017, Entergy Arkansas filed for a change in rates pursuant to its formula rate plan rider. In that proceeding, the APSC approved a settlement agreement agreed upon by the parties, including a provision that requires Entergy Arkansas to initiate a regulatory proceeding for the purpose of recovering funds currently withheld from rates and related to the stator incident, including the $65.9 million of deferred fuel and purchased energy costs previously noted, subject to certain timelines and conditions set forth in the settlement agreement. In October 2021 the APSC approved Entergy Arkansas’s second request to extend the deadline for initiating a regulatory proceeding for the purpose of recovering funds related to the stator incident for twelve additional months, or until December 1, 2022. See the “ANO Damage, Outage, and NRC Reviews” section in Note 8 to the financial statements for further discussion of the ANO stator incident.
In March 2017, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01164 per kWh to $0.01547 per kWh. The APSC staff filed testimony in March 2017 recommending that the redetermined rate be implemented with the first billing cycle of April 2017 under the normal operation of the tariff. Accordingly, the redetermined rate went into effect on March 31, 2017 pursuant to the tariff. In July 2017 the Arkansas Attorney General requested additional information to support certain of the costs included in Entergy Arkansas’s 2017 energy cost rate redetermination.
In March 2018, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01547 per kWh to $0.01882 per kWh. The Arkansas Attorney General filed a response to Entergy Arkansas’s annual redetermination filing requesting that the APSC suspend the proposed tariff to investigate the amount of the redetermination or, alternatively, to allow recovery subject to refund. Among the reasons the Attorney General cited for suspension were questions pertaining to how Entergy Arkansas forecasted sales and potential implications of the Tax 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, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $0.01882 per kWh to $0.01462 per kWh and became effective with the first billing cycle in April 2019. In March 2019 the Arkansas Attorney General filed a response to Entergy Arkansas’s annual adjustment and included with its filing a motion for investigation of alleged overcharges to customers in connection with the FERC’s October 2018 order in the opportunity sales proceeding. Entergy Arkansas filed its response to the Attorney General’s motion in April 2019 in which Entergy Arkansas stated its
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intent to initiate a proceeding to address recovery issues related to the October 2018 FERC order. In May 2019, Entergy Arkansas initiated the opportunity sales recovery proceeding, discussed below, and requested that the APSC establish that proceeding as the single designated proceeding in which interested parties may assert claims related to the appropriate retail rate treatment of the FERC October 2018 order and related FERC orders in the opportunity sales proceeding. In June 2019 the APSC granted Entergy Arkansas’s request and also denied the Attorney General’s motion in the energy cost recovery proceeding seeking an investigation into Entergy Arkansas’s annual energy cost recovery rider adjustment and referred the evaluation of such matters to the opportunity sales recovery proceeding.
In March 2020, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $0.01462 per kWh to $0.01052 per kWh. The redetermined rate became effective with the first billing cycle in April 2020 through the normal operation of the tariff.
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.
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.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
In April 2016 the FERC issued orders addressing requests for rehearing filed in July 2012 and the ALJ’s August 2013 initial decision. The first order denied Entergy’s request for rehearing and affirmed the FERC’s earlier rulings that Entergy’s original methodology for allocating energy costs to the opportunity sales was incorrect and, as a result, Entergy Arkansas must make payments to the other Utility operating companies to put them in the same position that they would have been in absent the incorrect allocation. The FERC clarified that interest should be included with the payments. The second order affirmed in part, and reversed in part, the rulings in the ALJ’s August 2013 initial decision regarding the methodology that should be used to calculate the payments Entergy Arkansas is to make to the other Utility operating companies. The FERC affirmed the ALJ’s ruling that a full re-run of intra-system bills should be performed but required that methodology be modified so that the sales have the same priority for purposes of energy allocation as joint account sales. The FERC reversed the ALJ’s decision that any payments by Entergy Arkansas should be reduced by 20%. The FERC also reversed the ALJ’s decision that adjustments to other System Agreement service schedules and excess bandwidth payments should not be taken into account when calculating the payments to be made by Entergy Arkansas. The FERC held that such adjustments and excess bandwidth payments should be taken into account but ordered further proceedings before an ALJ to address whether a cap on any reduction due to bandwidth payments was necessary and to implement the other adjustments to the calculation methodology.
In May 2016, Entergy Services filed a request for rehearing of the FERC’s April 2016 order arguing that payments made by Entergy Arkansas should be reduced as a result of the timing of the LPSC’s approval of certain contracts. Entergy Services also filed a request for clarification and/or rehearing of the FERC’s April 2016 order addressing the ALJ’s August 2013 initial decision. The APSC and the LPSC also filed requests for rehearing of the FERC’s April 2016 order. In September 2017 the FERC issued an order denying the request for rehearing on the issue of whether any payments by Entergy Arkansas to the other Utility operating companies should be reduced due to the timing of the LPSC’s approval of Entergy Arkansas’s wholesale baseload contract with Entergy Louisiana. In November 2017 the FERC issued an order denying all of the remaining requests for rehearing of the April 2016 order. In November 2017, Entergy Services filed a petition for review in the D.C. Circuit of the FERC’s orders in the first two phases of the opportunity sales case. In December 2017 the D.C. Circuit granted Entergy Services’ request to hold the appeal in abeyance pending final resolution of the related proceeding before the FERC. In January 2018 the APSC and the LPSC filed separate petitions for review in the D.C. Circuit, and the D.C. Circuit consolidated the appeals with Entergy Services’ appeal.
The hearing required by the FERC’s April 2016 order was held in May 2017. In July 2017 the ALJ issued an initial decision addressing whether a cap on any reduction due to bandwidth payments was necessary and whether to implement the other adjustments to the calculation methodology. In August 2017 the Utility operating companies, the LPSC, the APSC, and FERC staff filed individual briefs on exceptions challenging various aspects of the initial decision. In September 2017 the Utility operating companies, the LPSC, the APSC, the MPSC, the City Council, and FERC staff filed separate briefs opposing exceptions taken by various parties.
Based on testimony previously submitted in the case and its assessment of the April 2016 FERC orders, in the first quarter 2016, Entergy Arkansas recorded a liability of $87 million, which included interest, for its estimated increased costs and payment to the other Utility operating companies, and a deferred fuel regulatory asset of $75 million. Following its assessment of the course of the proceedings, including the FERC’s denial of rehearing in November 2017 described above, in the fourth quarter 2017, Entergy Arkansas recorded an additional liability of $35 million and a regulatory asset of $31 million.
In October 2018 the FERC issued an order addressing the ALJ’s July 2017 initial decision. The FERC reversed the ALJ’s decision to cap the reduction in Entergy Arkansas’s payment to account for the increased bandwidth payments that Entergy Arkansas made to the other operating companies. The FERC also reversed the ALJ’s decision that Grand Gulf sales from January through September 2000 should be included in the calculation of Entergy Arkansas’s payment. The FERC affirmed on other grounds the ALJ’s rejection of the LPSC’s claim that certain joint account sales should be accounted for as part of the calculation of Entergy Arkansas’s payment. In November 2018 the LPSC requested rehearing of the FERC’s October 2018 decision. In December 2019 the FERC
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
denied the LPSC’s request for rehearing. In January 2020 the LPSC appealed the December 2019 decision to the D.C. Circuit.
In December 2018, Entergy made a compliance filing in response to the FERC’s October 2018 order. The compliance filing provided a final calculation of Entergy Arkansas’s payments to the other Utility operating companies, including interest. No protests were filed in response to the December 2018 compliance filing. The December 2018 compliance filing is pending FERC action. Refunds and interest in the following amounts were paid by Entergy Arkansas to the other operating companies in December 2018:
Total refunds including interest
Payment/(Receipt)
(In Millions)
Principal Interest Total
Entergy Arkansas $68 $67 $135
Entergy Louisiana ($30) ($29) ($59)
Entergy Mississippi ($18) ($18) ($36)
Entergy New Orleans ($3) ($4) ($7)
Entergy Texas ($17) ($16) ($33)
Entergy Arkansas previously recognized a regulatory asset with a balance of $116 million as of December 31, 2018 for a portion of the payments due as a result of this proceeding.
As described above, the FERC’s opportunity sales orders have been appealed to the D.C. Circuit. In February 2020 all of the appeals were consolidated and in April 2020 the D.C. Circuit established a briefing schedule. Briefing was completed in September 2020 and oral argument was heard in December 2020. In 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
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
application alleging that the APSC, in a prior proceeding, ruled on the issues addressed in the application and determined that Entergy Arkansas’s requested relief violates the filed rate doctrine and the prohibition against retroactive ratemaking. Entergy Arkansas responded to the joint motion in February 2020 rebutting these arguments, including demonstrating that the claims in this proceeding differ substantially from those the APSC addressed previously and that the payment resulting from a FERC tariff violation for which Entergy Arkansas seeks retail cost recovery in this proceeding differs materially from the refunds resulting from a FERC tariff amendment that the APSC previously rejected on filed rate doctrine and the retroactive ratemaking grounds. In addition, in January 2020 the Attorney General and Arkansas Electric Energy Consumers, Inc. filed testimony opposing the recovery by Entergy Arkansas of the opportunity sales payment but also claiming that certain components of the payment should be segregated and refunded to customers. In March 2020, Entergy Arkansas filed rebuttal testimony.
In July 2020 the APSC issued a decision finding that Entergy Arkansas’s application is not in the public interest. The order also directed Entergy Arkansas to refund to its retail customers within 30 days of the order the FERC-determined over-collection of $13.7 million, plus interest, associated with a recalculated bandwidth remedy. In addition to these primary findings, the order also denied the Attorney General’s request for Entergy Arkansas to prepare a compliance filing detailing all of the retail impacts from the opportunity sales and denied a request by the Arkansas Electric Energy Consumers to recalculate all costs using the revised responsibility ratio. Entergy Arkansas filed a motion for temporary stay of the 30-day requirement to allow Entergy Arkansas a reasonable opportunity to seek rehearing of the APSC order, but in July 2020 the APSC denied Entergy Arkansas’s request for a stay and directed Entergy Arkansas to refund to its retail customers the component of the total FERC-determined opportunity sales payment that was associated with increased bandwidth remedy payments of $13.7 million, plus interest. The refunds were issued in the August 2020 billing cycle. While the APSC denied Entergy Arkansas’s stay request, Entergy Arkansas believes its actions were prudent and, therefore, the costs, including the $13.7 million, plus interest, are recoverable. In July 2020, Entergy Arkansas requested rehearing of the APSC order, which rehearing was denied by the APSC in August 2020. In September 2020, Entergy Arkansas filed a complaint in the U.S. District Court for the Eastern District of Arkansas challenging the APSC’s order denying Entergy Arkansas’s request to recover the costs of these payments. In October 2020 the APSC filed a motion to dismiss Entergy Arkansas’s complaint, to which Entergy Arkansas responded. Also in December 2020, Entergy Arkansas and the APSC held a pre-trial conference, and filed a report with the court in January 2021. The court held a hearing in February 2021 regarding issues addressed in the pre-trial conference report, and in June 2021 the court stayed all discovery until it rules on pending motions, after which the court will issue an amended schedule if necessary.
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, cooperatives, the Arkansas Attorney General, 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; 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
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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 remain pending with that court.
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.
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 currently designated to be available under this tariff is up to 200 MW. In September and October 2021 the APSC general staff and two net-metering solar developer intervenors filed responses indicating opposition to the tariff as proposed. The tariff is 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 does 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 solar 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. An APSC decision is expected in second quarter 2022.
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
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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, 2021, Entergy Arkansas had a regulatory asset of $32.6 million for costs associated with the COVID-19 pandemic.
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
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; 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; 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 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.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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
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 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 2022 Qualified Pension Cost Impact on 2021 Qualified Projected Benefit Obligation
Increase/(Decrease)
Discount rate (0.25%) $1,876 $42,262
Rate of return on plan assets (0.25%) $2,851 $-
Rate of increase in compensation 0.25% $1,908 $8,509
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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 2022 Postretirement Benefit Cost Impact on 2021 Accumulated Postretirement Benefit Obligation
Increase/(Decrease)
Discount rate (0.25%) $171 $6,791
Health care cost trend 0.25% $282 $4,789
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Employer Contributions
Total qualified pension cost for Entergy Arkansas in 2021 was $92.9 million, including $37.7 million in settlement costs. Entergy Arkansas anticipates 2022 qualified pension cost to be $41.4 million. Entergy Arkansas contributed $66.6 million to its qualified pension plans in 2021 and estimates pension contributions will be approximately $40.8 million in 2022, although the 2022 required pension contributions will be known with more certainty when the January 1, 2022 valuations are completed, which is expected by April 1, 2022.
Total other postretirement health care and life insurance benefit income for Entergy Arkansas in 2021 was $11.1 million. Entergy Arkansas expects 2022 postretirement health care and life insurance benefit income of approximately $5.7 million. In 2021, Entergy Arkansas’ contributions (that is, contributions to the external trusts plus claims payments) were offset by trust claims reimbursements, resulting in a net reimbursement of $767 thousand. Entergy Arkansas estimates that 2022 contributions will be approximately $517 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, 2021 and 2020, the related consolidated statements of income, cash flows and changes in member’s equity (pages 324 through 328 and applicable items in pages 49 through 233), for each of the three years in the period ended December 31, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, 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, such as property, plant, and equipment; regulatory assets and liabilities; income taxes; operating revenues; operation and maintenance expense; and depreciation and amortization expense.
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 especially subjective judgment and specialized knowledge of accounting for rate regulation and the rate setting process.
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 and other public utilities, regulatory statutes, interpretations, procedural memorandums, 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 25, 2022
We have served as the Company’s auditor since 2001.
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENTS
For the Years Ended December 31,
2021 2020 2019
(In Thousands)
OPERATING REVENUES
Electric $2,338,590 $2,084,494 $2,259,594
OPERATING EXPENSES
Operation and Maintenance:
Fuel, fuel-related expenses, and gas purchased for resale 347,166 271,896 458,907
Purchased power 280,504 187,690 204,640
Nuclear refueling outage expenses 51,141 55,737 68,769
Other operation and maintenance 687,418 669,518 720,217
Decommissioning 77,696 73,319 68,030
Taxes other than income taxes 127,249 121,057 115,869
Depreciation and amortization 361,479 338,029 307,351
Other regulatory charges (credits) - net (31,501) (35,310) (11,186)
TOTAL 1,901,152 1,681,936 1,932,597
OPERATING INCOME 437,438 402,558 326,997
OTHER INCOME
Allowance for equity funds used during construction 15,273 15,019 15,499
Interest and investment income 76,953 35,579 26,020
Miscellaneous - net (22,278) (21,908) (18,566)
TOTAL 69,948 28,690 22,953
INTEREST EXPENSE
Interest expense 140,348 144,834 140,087
Allowance for borrowed funds used during construction (6,641) (6,595) (6,332)
TOTAL 133,707 138,239 133,755
INCOME BEFORE INCOME TAXES 373,679 293,009 216,195
Income taxes 75,195 47,777 (46,769)
NET INCOME 298,484 245,232 262,964
Net loss attributable to noncontrolling interest (18,092) - -
EARNINGS APPLICABLE TO MEMBER'S EQUITY $316,576 $245,232 $262,964
See Notes to Financial Statements.
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
2021 2020 2019
(In Thousands)
OPERATING ACTIVITIES
Net income $298,484 $245,232 $262,964
Adjustments to reconcile net income to net cash flow provided by operating activities:
Depreciation, amortization, and decommissioning, including nuclear fuel amortization 503,539 490,457 465,299
Deferred income taxes, investment tax credits, and non-current taxes accrued 100,459 87,019 94,368
Changes in assets and liabilities:
Receivables 17,682 (24,507) (58,077)
Fuel inventory (7,081) (10,066) (10,597)
Accounts payable 27,967 (22,773) 3,059
Prepaid taxes and taxes accrued 7,753 6 24,942
Interest accrued (5,637) (43) 3,895
Deferred fuel costs (162,458) (1,186) 72,560
Other working capital accounts (53,343) (11,061) 18,783
Provisions for estimated losses 6,915 6,289 14,901
Other regulatory assets 142,706 (165,534) (131,873)
Other regulatory liabilities 21,066 106,878 39,293
Pension and other postretirement liabilities (175,863) 42,576 5,831
Other assets and liabilities (172,973) (83,469) (127,582)
Net cash flow provided by operating activities 549,216 659,818 677,766
INVESTING ACTIVITIES
Construction expenditures (722,628) (775,595) (641,525)
Allowance for equity funds used during construction 15,273 15,019 15,306
Nuclear fuel purchases (84,302) (100,678) (54,344)
Proceeds from sale of nuclear fuel 16,279 30,638 22,782
Proceeds from nuclear decommissioning trust fund sales 530,628 321,360 317,377
Investment in nuclear decommissioning trust funds (524,783) (336,392) (336,519)
Payment for purchase of assets (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 - 4,036 630
Net cash flow used in investing activities (898,193) (795,709) (676,293)
FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt 719,284 1,071,121 834,038
Retirement of long-term debt (728,917) (632,175) (548,952)
Capital contributions from noncontrolling interest 51,202 - -
Change in money pool payable - net 139,904 (21,634) (161,104)
Common equity distributions paid (50,000) (95,000) (115,000)
Other 38,291 2,188 (7,055)
Net cash flow provided by financing activities 169,764 324,500 1,927
Net increase (decrease) in cash and cash equivalents (179,213) 188,609 3,400
Cash and cash equivalents at beginning of period 192,128 3,519 119
Cash and cash equivalents at end of period $12,915 $192,128 $3,519
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized $143,561 $140,735 $131,134
Income taxes ($18,933) ($21,971) ($33,989)
See Notes to Financial Statements.
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31,
2021 2020
(In Thousands)
CURRENT ASSETS
Cash and cash equivalents:
Cash $8,155 $24,108
Temporary cash investments 4,760 168,020
Total cash and cash equivalents 12,915 192,128
Accounts receivable:
Customer 154,412 183,719
Allowance for doubtful accounts (13,072) (18,334)
Associated companies 29,587 34,216
Other 51,064 35,845
Accrued unbilled revenues 101,663 109,000
Total accounts receivable 323,654 344,446
Deferred fuel costs 108,862 -
Fuel inventory - at average cost 50,892 43,811
Materials and supplies - at average cost 247,980 237,640
Deferred nuclear refueling outage costs 65,318 32,692
Prepayments and other 14,863 13,296
TOTAL 824,484 864,013
OTHER PROPERTY AND INVESTMENTS
Decommissioning trust funds 1,438,416 1,273,921
Other 947 341
TOTAL 1,439,363 1,274,262
UTILITY PLANT
Electric 13,578,297 12,905,322
Construction work in progress 241,127 234,213
Nuclear fuel 182,055 163,044
TOTAL UTILITY PLANT 14,001,479 13,302,579
Less - accumulated depreciation and amortization 5,472,296 5,255,355
UTILITY PLANT - NET 8,529,183 8,047,224
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Other regulatory assets 1,689,678 1,832,384
Deferred fuel costs 68,751 68,220
Other 13,660 14,028
TOTAL 1,772,089 1,914,632
TOTAL ASSETS $12,565,119 $12,100,131
See Notes to Financial Statements.
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
December 31,
2021 2020
(In Thousands)
CURRENT LIABILITIES
Currently maturing long-term debt $- $485,000
Accounts payable:
Associated companies 217,310 59,448
Other 190,476 208,591
Customer deposits 92,511 98,506
Taxes accrued 89,590 81,837
Interest accrued 17,108 22,745
Deferred fuel costs - 53,065
Other 38,901 40,628
TOTAL 645,896 1,049,820
NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued 1,416,201 1,286,123
Accumulated deferred investment tax credits 29,299 30,500
Regulatory liability for income taxes - net 431,655 467,031
Other regulatory liabilities 743,314 686,872
Decommissioning 1,390,410 1,314,160
Accumulated provisions 77,084 70,169
Pension and other postretirement liabilities 185,789 361,682
Long-term debt 3,958,862 3,482,507
Other 110,754 75,098
TOTAL 8,343,368 7,774,142
Commitments and Contingencies
EQUITY
Member's equity 3,542,745 3,276,169
Noncontrolling interest 33,110 -
TOTAL 3,575,855 3,276,169
TOTAL LIABILITIES AND EQUITY $12,565,119 $12,100,131
See Notes to Financial Statements.
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY
For the Years Ended December 31, 2021, 2020, and 2019
Noncontrolling Interest Member's Equity Total
(In Thousands)
Balance at December 31, 2018 $- $2,983,103 $2,983,103
Net income - 262,964 262,964
Common equity distributions - (115,000) (115,000)
Other - (5,130) (5,130)
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
See Notes to Financial Statements.
ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Hurricane Ida
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. Total restoration costs for the repair and/or replacement of the electrical system damaged by Hurricane Ida are currently estimated to be approximately $2.5 billion. Also, Entergy Louisiana’s revenues in 2021 were adversely affected by extended power outages resulting from the hurricane.
Entergy Louisiana has recorded accounts payable for the estimated costs incurred that were necessary to return customers to service. Entergy Louisiana recorded corresponding regulatory assets of approximately $1 billion and construction work in progress of approximately $1.5 billion. Entergy Louisiana recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. There are well-established mechanisms and precedent for addressing these catastrophic events and providing for recovery of prudently incurred storm costs in accordance with applicable regulatory and legal principles. Because Entergy Louisiana has not gone through the regulatory process regarding these storm costs, there is an element of risk, and Entergy Louisiana is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
Entergy Louisiana is considering all available avenues to recover storm-related costs from Hurricane Ida, including federal government assistance and securitization financing. 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, as discussed below in “Storm Cost Filings - Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida,” Entergy Louisiana sought approval for the creation and funding of a $1 billion restricted escrow account for Hurricane Ida restoration costs, subject to a subsequent prudence review. Storm cost recovery or financing will be subject to review by applicable regulatory authorities, with a prudence review likely being initiated in the second quarter of 2022.
Results of Operations
2021 Compared to 2020
Net Income
Net income decreased $428.4 million primarily due to the $382.8 million reduction in deferred income tax expense related to the basis of assets contributed in the 2015 Entergy Louisiana and Entergy Gulf States Louisiana business combination as a result of the resolution of the 2014-2015 IRS audit in the fourth quarter 2020 and the $58 million reduction in income tax expense resulting from an IRS settlement in the first quarter 2020 related to the uncertain tax position regarding the Hurricane Isaac Louisiana Act 55 financing, which also resulted in a $29 million ($21 million net-of-tax) regulatory charge to reflect Entergy Louisiana’s agreement to share the savings with customers. Also contributing to the decrease was higher other operation and maintenance expenses, higher depreciation and amortization expenses, higher interest expense, and higher taxes other than income taxes. The decrease was partially offset by higher retail electric price and higher other income. See Note 3 to the financial statements for further discussion of the tax settlement.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Operating Revenues
Following is an analysis of the change in operating revenues comparing 2021 to 2020:
Amount
(In Millions)
2020 operating revenues $4,069.9
Fuel, rider, and other revenues that do not significantly affect net income 865.0
Retail electric price 136.7
Volume/weather (3.2)
2021 operating revenues $5,068.4
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 interim increase in formula rate plan revenues effective April 2020 due to the inclusion of the first-year revenue requirement for the Lake Charles Power Station;
•an increase in overall formula rate plan revenues, including an increase in the transmission recovery mechanism, effective September 2020;
•an interim increase in formula rate plan revenues effective December 2020 due to the inclusion of the first-year revenue requirement for the Washington Parish Energy Center; and
•an increase in formula rate plan revenues, including increases in the transmission and distribution recovery mechanisms, effective September 2021.
See Note 2 to the financial statements for further discussion of the formula rate plan proceedings.
The volume/weather variance is primarily due to a decrease in usage during the unbilled sales period and a decrease in weather-adjusted billed electricity usage for residential customers, partially offset by an increase in industrial usage and the effect of more favorable weather on residential sales. The decrease in weather-adjusted residential usage is primarily due to the effect of Hurricane Ida in 2021 and the impact that the COVID-19 pandemic had on prior year usage. The increase in industrial usage is primarily due to increased demand from expansion projects, primarily in the chemicals and transportation industries, and an increase in demand from co-generation customers, partially offset by a decrease in demand from existing customers in the chemicals and petroleum refining industries. See “Hurricane Ida” above for discussion of the impacts from the storm.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Billed electric energy sales for Entergy Louisiana for the years ended December 31, 2021 and 2020 are as follows:
2021 2020 % Change
(GWh)
Residential 13,588 13,771 (1)
Commercial 10,385 10,465 (1)
Industrial 29,869 28,881 3
Governmental 792 779 2
Total retail 54,634 53,896 1
Sales for resale:
Associated companies 4,950 5,585 (11)
Non-associated companies 2,764 2,365 17
Total 62,348 61,846 1
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 $21.7 million in compensation and benefits costs in 2021 primarily due to lower healthcare claims activity in 2020 as a result of the COVID-19 pandemic, an increase in healthcare cost rates, an increase in net periodic pension and other postretirement benefits costs as a result of a decrease in the discount rate used to value the benefit liabilities, and higher incentive-based compensation accruals in 2021 as compared to prior year. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs;
•an increase of $19.3 million in distribution operations expenses primarily due to higher reliability costs;
•an increase of $12.7 million in nuclear generation expenses primarily due to a higher scope of work performed in 2021 as compared to 2020;
•an increase of $10.7 million primarily due to an increase in contract costs related to customer solutions and sustainability initiatives, including customer service center support and enhanced customer billing;
•an increase of $6 million in energy efficiency costs due to the timing of recovery from customers and higher energy efficiency costs;
•an increase of $4.9 million as a result of the amount of transmission costs allocated by MISO. See Note 2 to the financial statements for further information on the recovery of these costs; and
•lower nuclear insurance refunds of $4.2 million.
The increase was partially offset by a gain of $14.8 million, recorded in 2021, on the sale of a pipeline.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Taxes other than income taxes increased primarily due to increases in ad valorem taxes resulting from higher assessments and an increase in local franchise taxes resulting from an increase in revenue collected.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including the Lake Charles Power Station, which was placed in service in March 2020, and the Washington Parish Energy Center, which was placed in service in November 2020.
Other regulatory charges (credits) include regulatory charges of $32.6 million recorded in the fourth quarter 2020 due to a settlement with the IRS related to the uncertain tax position regarding Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing because the savings will be shared with customers and $29 million recorded in the first quarter 2020 due to a settlement with the IRS related to the uncertain tax position regarding Hurricane Isaac Louisiana Act 55 financing because the savings will be shared with customers. See Note 3 to the financial statements for further discussion of the settlements and savings obligations. In addition, Entergy Louisiana records a regulatory charge or credit for the difference between asset retirement obligation-related expenses and trust earnings plus asset retirement obligation related costs collected in revenue.
Other income increased primarily due to changes in decommissioning trust fund activity, including portfolio rebalancing for the Waterford 3 and River Bend decommissioning trust funds in 2021. The increase was partially offset by a decrease in the allowance for equity funds used during construction due to higher construction work in progress in 2020, including the Lake Charles Power Station project.
Interest expense increased primarily due to:
•the issuances of $1.1 billion of 0.62% Series mortgage bonds, $300 million of 2.90% Series mortgage bonds, and $300 million of 1.60% Series mortgage bonds, each in November 2020;
•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; and
•a decrease in the allowance for borrowed funds used during construction due to higher construction work in progress in 2020, including the Lake Charles Power Station project.
The increase was partially offset by the repayment of $200 million of 5.25% Series mortgage bonds and $100 million of 4.70% Series mortgage bonds, each in December 2020, and $200 million of 4.8% Series mortgage bonds in May 2021.
The effective income tax rates were 15.5% for 2021 and (54.6%) for 2020. The difference in the effective income tax rate versus the federal statutory rate of 21% for 2020 was primarily due to completion of the 2014-2015 IRS audit effectively settling the tax positions for those years. See Notes 2 and 3 to the financial statements for a discussion of the effects and regulatory activity regarding the Tax Cuts and Jobs Act. 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.
2020 Compared to 2019
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, 2020, filed with the SEC on February 26, 2021, for discussion of results of operations for 2020 compared to 2019.
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, 2021, 2020, and 2019 were as follows:
2021 2020 2019
(In Thousands)
Cash and cash equivalents at beginning of period $728,020 $2,006 $43,364
Net cash provided by (used in):
Operating activities 1,052,526 1,072,986 1,236,002
Investing activities (3,700,199) (1,944,671) (1,653,634)
Financing activities 1,938,226 1,597,699 376,274
Net increase (decrease) in cash and cash equivalents (709,447) 726,014 (41,358)
Cash and cash equivalents at end of period $18,573 $728,020 $2,006
2021 Compared to 2020
Operating Activities
Net cash flow provided by operating activities decreased $20.5 million in 2021 primarily due to:
•an increase of approximately $197.2 million in storm spending in 2021. See Note 2 to the financial statements for discussion of recent storms;
•an increase in spending of $11.9 million on nuclear refueling outages in 2021; and
•an increase of $4.4 million in pension contributions in 2021. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
The decrease was partially offset by the timing of payments to vendors, higher collections from customers, and the timing of recovery of fuel and purchased power costs.
Investing Activities
Net cash flow used in investing activities increased $1,755.5 million in 2021 primarily due to:
•an increase of $1,119 million in distribution construction expenditures, primarily due to higher capital expenditures for storm restoration in 2021, partially offset by lower spending in 2021 on advanced metering infrastructure;
•an increase of $530.1 million in transmission construction expenditures primarily due to higher capital expenditures for storm restoration in 2021;
•$295.9 million in net receipts from storm reserve escrow accounts in 2020;
•an increase of $35 million in nuclear decommissioning trust fund activity as a result of a lump sum contribution for amounts collected over a 17-month period. See Note 2 for a discussion of nuclear decommissioning expense recovery;
•an increase of $23.8 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; and
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
•an increase of $22.8 million in nuclear construction expenditures primarily due to increased spending on various nuclear projects in 2021 and higher capital expenditures for storm restoration in 2021.
The increase was partially offset by:
•the purchase of Washington Parish Energy Center in November 2020 for approximately $222 million. See Note 14 to the financial statements for further discussion of the Washington Parish Energy Center purchase;
•a decrease of $33.1 million in non-nuclear generation construction expenditures due to higher spending in 2020 on the Lake Charles Power Station;
•the sale of a pipeline for $15 million in 2021;
•the purchase of a portion of a transmission operating center from Entergy Services for $14.5 million in 2020; and
•money pool activity.
Increases in Entergy Louisiana’s receivable from the money pool are a use of cash flow, and Entergy Louisiana’s receivable from the money pool increased by $1.1 million in 2021 compared to increasing by $13.4 million in 2020. 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 $340.5 million in 2021 primarily due to:
•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;
•the repayment of $250 million of 3.95% Series mortgage bonds in August 2020;
•the repayment in December 2020 of $200 million of 5.25% Series mortgage bonds due July 2052;
•a capital contribution of $125 million received from Entergy Corporation in December 2021 in order to assist in paying costs associated with Hurricane Ida;
•net borrowings of $125 million in 2021 on Entergy Louisiana’s credit facility;
•the repayment in December 2020 of $100 million of 4.70% Series mortgage bonds due June 2063;
•net long-term borrowings of $24.1 million in 2021 compared to net repayments of long-term borrowings of $62 million in 2020 on the nuclear fuel company variable interest entities’ credit facilities; and
•money pool activity.
The increase was partially offset by:
•the issuance of $1.1 billion of 0.62% Series mortgage bonds in November 2020;
•the issuance of $350 million of 2.90% Series mortgage bonds and $300 million of 4.20% Series mortgage bonds, each in March 2020,
•the issuance of $300 million of 2.90% Series mortgage bonds and $300 million of 1.60% Series mortgage bonds, each in November 2020,
•the repayment of $200 million of 4.80% Series mortgage bonds in May 2021;
•the repayment in February 2021 of $40 million of 3.92% Series H notes by the Entergy Louisiana Waterford variable interest entity; and
•an increase of $38.5 million in common equity distributions in 2021 primarily to maintain Entergy Louisiana’s targeted capital structure. In addition, common equity distributions were lower in 2020 due to spending on the Lake Charles Power Station and the purchase of the Washington Parish Energy Center.
Decreases in Entergy Louisiana’s payable to the money pool are a use of cash flow, and Entergy Louisiana’s payable to the money pool decreased by $82.8 million in 2020.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
See Note 5 to the financial statements for details of long-term debt.
2020 Compared to 2019
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, 2020, filed with the SEC on February 26, 2021, for discussion of operating, investing, and financing cash flow activities for 2020 compared to 2019.
Capital Structure
Entergy Louisiana’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio for Entergy Louisiana is primarily due to the net issuances of long-term debt in 2021 partially offset by the $125 million capital contribution received from Entergy Corporation in December 2021.
December 31,
2021 December 31,
Debt to capital 57.2 % 54.8 %
Effect of subtracting cash 0.0 % (2.1 %)
Net debt to net capital 57.2 % 52.7 %
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. 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, 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.
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.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy Louisiana’s planned construction and other capital investments.
2022 2023 2024
(In Millions)
Planned construction and capital investment:
Generation $395 $380 $555
Transmission 460 340 260
Distribution 430 480 415
Utility Support 195 150 105
Total $1,480 $1,350 $1,335
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Louisiana includes specific investments such as generation projects to modernize, decarbonize, and diversify Entergy Louisiana’s portfolio, including St. Jacques Louisiana Solar; 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, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.
In addition to the planned spending in the table above, Entergy Louisiana also expects to pay for $785 million of capital investments in 2022 related to Hurricane Ida restoration work that has been accrued as of December 31, 2021.
Following are the amounts of Entergy Louisiana’s existing debt and lease obligations (includes estimated interest payments).
2022 2023 2024 2025-2026 After 2026
(In Millions)
Long-term debt (a) $534 $1,772 $2,083 $1,566 $9,957
Operating leases (b) $14 $12 $10 $11 $3
Finance leases (b) $4 $4 $4 $5 $3
(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 $22.9 million to its qualified pension plans and approximately $15.8 million to its other postretirement health care and life insurance plans in 2022, although the 2022 required pension contributions will be known with more certainty when the January 1, 2022 valuations are completed, which is expected by April 1, 2022. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
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.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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 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) Vacherie Solar Energy Center, a 150 megawatt resource in St. James Parish; (ii) Sunlight Road Solar, a 50 megawatt resource in Washington Parish; (iii) St. Jacques Louisiana Solar, a 150 megawatt resource in St. James; and (iv) Elizabeth Solar Facility, a 125 megawatt resource in Allen Parish. St. Jacques Louisiana Solar would be acquired through a build-own-transfer agreement; the remaining resources involve power purchase agreements. The filing proposes to recover the costs of the power purchase agreements through the fuel adjustment clause and the acquisition costs through the formula rate plan.
The proposed Rider GGO is a voluntary rate schedule that would 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.
The LPSC has established a procedural schedule that is expected to result in an LPSC decision by the end of 2022. Discovery is currently underway.
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, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Louisiana’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
2021 2020 2019 2018
(In Thousands)
$14,539 $13,426 ($82,826) $46,843
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 2026. 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, 2021, there were $125 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, 2021, $15 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.
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 2024. As of December 31, 2021, $42.7 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, 2021, $39.6 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 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.
In December 2021, Entergy Louisiana entered into a term loan credit agreement providing a $1.2 billion unsecured term loan due June 2023. The term loan bears interest at a variable interest rate based on an adjusted term Secured Overnight Financing Rate plus the applicable margin. Entergy Louisiana received the funds in January 2022 and used the proceeds for general corporate purposes, including storm restoration costs related to Hurricane Ida.
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
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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 are currently 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 is seeking an LPSC determination that $2.11 billion was prudently incurred and, therefore, is eligible for recovery from customers. Additionally, Entergy Louisiana is requesting that the LPSC determine that re-establishment of a storm escrow account to the previously authorized amount of $290 million is 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. As previously discussed, 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 supplemented the application with a request to establish and securitize a $1 billion restricted storm escrow account for Hurricane Ida related restoration costs, subject to a subsequent prudence review. In total, Entergy Louisiana requested authorization for the issuance of system restoration bonds in one or more series in an aggregate principal amount of $3.18 billion, which includes the costs of re-establishing and funding a storm damage escrow account, carrying costs and unamortized debt costs on interim financing, and issuance costs. After filing of testimony by LPSC staff and intervenors, which generally supported or did not oppose Entergy Louisiana’s requests, the parties negotiated and executed an uncontested stipulated settlement which was filed with the LPSC in February 2022. The settlement agreement contains 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 are eligible for recovery; carrying costs of $51 million are 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 is authorized to finance $3.186 billion utilizing the securitization process authorized by Act 55, as supplemented by Act 293. The LPSC voted to approve the settlement at its February 2022 meeting.
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.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Retail Rates - Electric
Filings with the LPSC
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 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 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.
Commercial operation at J. Wayne Leonard Power Station (formerly St. Charles Power Station) commenced in May 2019. In May 2019, Entergy Louisiana filed an update to its 2017 formula rate plan evaluation report to include the estimated first-year revenue requirement of $109.5 million associated with the J. Wayne Leonard Power Station. The resulting interim adjustment to rates became effective with the first billing cycle of June 2019. In June 2020, Entergy Louisiana submitted information to the LPSC to review the prudence of Entergy Louisiana’s management of the project. In August 2020 discovery commenced and a procedural schedule was established with a hearing in July 2021. In February 2021 the LPSC staff filed testimony that substantially all the costs to construct J. Wayne Leonard Power Station were prudently incurred and eligible for recovery from customers. The LPSC staff further recommended that the LPSC consider monitoring the remaining $3.1 million that was estimated to be incurred for completion of the project in the event the final costs exceed the estimated amounts. In July 2021 the LPSC approved a settlement between the LPSC staff and Entergy Louisiana finding that
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
substantially all the costs to construct J. Wayne Leonard Power Station were prudently incurred and eligible for recovery from customers.
2018 Formula Rate Plan Filing
In May 2019, Entergy Louisiana filed its formula rate plan evaluation report for its 2018 calendar year operations. The 2018 test year evaluation report produced an earned return on common equity of 10.61% leading to a base rider formula rate plan revenue decrease of $8.9 million. While base rider formula rate plan revenue will decrease as a result of this filing, overall formula rate plan revenues will increase by approximately $118.7 million. This outcome is primarily driven by a reduction to the credits previously flowed through the tax reform adjustment mechanism and an increase in the transmission recovery mechanism, partially offset by reductions in the additional capacity mechanism revenue requirements and extraordinary cost items. The filing is subject to review by the LPSC. Resulting rates were implemented in September 2019, subject to refund.
Entergy Louisiana also included in its filing a presentation of an initial proposal to combine the legacy Entergy Louisiana and legacy Entergy Gulf States Louisiana residential rates, which combination, if approved, would be accomplished on a revenue-neutral basis intended not to affect the rates of other customer classes. Entergy Louisiana contemplates that any combination of residential rates resulting from this request would be implemented with the results of the 2019 test year formula rate plan filing.
Several parties intervened in the proceeding and the LPSC staff filed its report of objections/reservations in accordance with the applicable provisions of the formula rate plan. In its report the LPSC staff re-urged reservations with respect to the outstanding issues from the 2017 test year formula rate plan filing and disputed the inclusion of certain affiliate costs for test years 2017 and 2018. The LPSC staff objected to Entergy Louisiana’s proposal to combine residential rates but proposed the setting of a status conference to establish a procedural schedule to more fully address the issue. The LPSC staff also reserved its right to object to the treatment of the sale of Willow Glen reflected in the evaluation report and to the August 2019 compliance update, which was made primarily to update the capital additions reflected in the formula rate plan’s transmission recovery mechanism, based on limited time to review it. Additionally, since the completion of certain transmission projects, the LPSC staff issued supplemental data requests addressing the prudence of Entergy Louisiana’s expenditures in connection with those projects. Entergy Louisiana 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.
In an effort to narrow the remaining issues in formula rate plan test years 2017 and 2018, Entergy Louisiana provided notice to the parties in October 2020 that it was withdrawing its request to combine residential rates. Entergy Louisiana noted that the withdrawal is without prejudice to Entergy Louisiana’s right to seek to combine residential rates in a future proceeding.
2019 Formula Rate Plan Filing
In May 2020, Entergy Louisiana filed with the LPSC its formula rate plan evaluation report for its 2019 calendar year operations. The 2019 test year evaluation report produced an earned return on common equity of 9.66%. As such, no change to base rider formula rate plan revenue is required. Although base rider formula rate
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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 would increase formula rate plan revenues by approximately $1.2 million. The resulting interim adjustment to rates became effective with the first billing cycle of February 2021.
2020 Formula Rate Plan Filing
In June 2021, Entergy Louisiana filed its formula rate plan evaluation report for its 2020 calendar year operations. The 2020 test year evaluation report produced an earned return on common equity of 8.45%, with a base formula rate plan revenue increase of $63 million. Certain reductions in formula rate plan revenue driven by lower sales volumes, reductions in capacity cost and net MISO cost, and higher credits resulting from the Tax Cuts and Jobs Act offset the base formula rate plan revenue increase, leading to a net increase in formula rate plan revenue of $50.7 million. The report also included multiple new adjustments to account for, among other things, the calculation of distribution recovery mechanism revenues. The effects of the changes to total formula rate plan revenue 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 will increase by $27 million and legacy Entergy Gulf States Louisiana formula rate plan revenues will increase 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 will increase by $32.8 million and legacy Entergy Gulf States Louisiana formula rate plan revenues will increase 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.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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 FRP 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 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.
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.
Fuel and purchased power 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 2014 the LPSC authorized its staff to initiate an audit of the fuel adjustment clause filings by Entergy Gulf States Louisiana, whose business was combined with Entergy Louisiana in 2015. The audit includes a review of the reasonableness of charges flowed through Entergy Gulf States Louisiana’s fuel adjustment clause for the period from 2010 through 2013. In January 2019 the LPSC staff consultant issued its audit report. In its report, the LPSC staff consultant recommended that Entergy Louisiana refund approximately $900,000, plus interest, to customers based upon the imputation of a claim of vendor fault in servicing its nuclear plant. Entergy Louisiana recorded a provision in the first quarter 2019 for the potential outcome of the audit. In August 2019, Entergy Louisiana filed direct testimony challenging the basis for the LPSC staff’s recommended disallowance and providing an alternative calculation of replacement power costs should it be determined that a disallowance is appropriate. Entergy Louisiana’s calculation would require no refund to customers.
In July 2014 the LPSC authorized its staff to initiate an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed by Entergy Louisiana through its fuel adjustment clause for the period from 2010 through 2013. In January 2019 the LPSC staff issued its audit report recommending that Entergy Louisiana refund approximately $7.3 million, plus interest, to customers based upon the imputation of a claim of vendor fault in servicing its nuclear plant. Entergy Louisiana recorded a provision in the first quarter 2019 for the potential outcome of the audit. In August 2019, Entergy Louisiana filed direct testimony challenging the basis for the LPSC staff’s recommended disallowance and providing an alternative calculation of replacement power costs should it be determined that a disallowance is appropriate. Entergy Louisiana’s
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
calculation would require a refund to customers of approximately $4.3 million, plus interest, as compared to the LPSC staff’s recommendation of $7.3 million, plus interest. Responsive testimony was filed by the LPSC staff and intervenors in September 2019; all parties either agreed with or did not oppose Entergy Louisiana’s alternative calculation of replacement power costs.
In November 2019 the pending LPSC proceedings for the 2010-2013 Entergy Louisiana and Entergy Gulf States Louisiana audits were consolidated to facilitate a settlement of both fuel audits. In December 2019 an unopposed settlement was reached that requires a refund to legacy Entergy Louisiana customers of approximately $2.3 million, including interest, and no refund to legacy Entergy Gulf States Louisiana customers. The LPSC approved the settlement in January 2020. A one-time refund was made in February 2020.
In March 2020 the LPSC staff provided notice of an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2016 through 2019. In September 2021 the LPSC submitted its audit report and found that all costs recovered through the fuel adjustment clause were reasonable and eligible for recovery through the fuel adjustment clause. Intervenors are conducting discovery regarding the LPSC staff’s report.
In February 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 review the prudence of the February 2021 fuel costs incurred by all LPSC-jurisdictional utilities. At its June 2021 meeting, the LPSC approved the hiring of consultants to assist its staff in this review. Discovery is ongoing.
In March 2021 the LPSC staff provided notice of an audit of Entergy Louisiana’s purchased gas adjustment clause 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 that period. Discovery is ongoing, and no audit report has been filed.
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, 2021, Entergy Louisiana had a regulatory asset of $56.3 million for costs associated with the COVID-19 pandemic.
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
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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
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, to position Entergy’s nuclear fleet to meet its operational goals; the performance and capacity factors of these nuclear plants; 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 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.
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 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, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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.
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
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 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 “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.
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 2022 Qualified Pension Cost Impact on 2021 Projected Qualified Benefit Obligation
Increase/(Decrease)
Discount rate (0.25%) $2,265 $46,936
Rate of return on plan assets (0.25%) $3,132 $-
Rate of increase in compensation 0.25% $2,307 $10,908
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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 2022 Postretirement Benefit Cost Impact on 2021 Accumulated postretirement Benefit Obligation
Increase/(Decrease)
Discount rate (0.25%) $788 $7,934
Health care cost trend 0.25% $923 $5,453
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 2021 was $117.2 million, including $61.9 million in settlement costs. Entergy Louisiana anticipates 2022 qualified pension cost to be $44.4 million. Entergy Louisiana contributed $59.9 million to its qualified pension plans in 2021 and estimates pension contributions will be approximately $22.9 million in 2022, although the 2022 required pension contributions will be known with more certainty when the January 1, 2022 valuations are completed, which is expected by April 1, 2022.
Total postretirement health care and life insurance benefit costs for Entergy Louisiana in 2021 were $5.4 million. Entergy Louisiana expects 2022 postretirement health care and life insurance benefit costs of approximately $6 million. Entergy Louisiana contributed $11.3 million to its other postretirement plans in 2021 and estimates that 2022 contributions will be approximately $15.8 million.
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 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, 2021 and 2020, the related consolidated statements of income, comprehensive income, cash flows, and changes in equity (pages 351 through 356 and applicable items in pages 49 through 233), for each of the three years in the period ended December 31, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, 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 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, such as property, plant, and equipment; regulatory assets and liabilities; income taxes; operating revenues; operation and maintenance expense; and depreciation and amortization expense.
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, including major storm restoration costs, and refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the LPSC and the FERC, involved especially subjective judgment and specialized knowledge of accounting for rate regulation and the rate setting process.
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 and other public utilities, regulatory statutes, interpretations, procedural memorandums, 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, including major storm restoration costs, 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, including major storm restoration costs, 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 25, 2022
We have served as the Company’s auditor since 2001.
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ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENTS
For the Years Ended December 31,
2021 2020 2019
(In Thousands)
OPERATING REVENUES
Electric $4,994,459 $4,019,063 $4,223,027
Natural gas 73,989 50,799 62,148
TOTAL 5,068,448 4,069,862 4,285,175
OPERATING EXPENSES
Operation and Maintenance:
Fuel, fuel-related expenses, and gas purchased for resale 1,302,291 700,152 845,108
Purchased power 768,546 596,480 810,462
Nuclear refueling outage expenses 49,373 55,305 54,170
Other operation and maintenance 1,034,427 969,630 994,637
Decommissioning 68,575 65,225 59,346
Taxes other than income taxes 224,079 208,902 194,222
Depreciation and amortization 656,132 609,931 535,791
Other regulatory charges (credits) - net 38,245 (584) (105,203)
TOTAL 4,141,668 3,205,041 3,388,533
OPERATING INCOME 926,780 864,821 896,642
OTHER INCOME
Allowance for equity funds used during construction 28,648 38,151 74,023
Interest and investment income 282,200 225,627 231,985
Miscellaneous - net (125,886) (116,366) (115,427)
TOTAL 184,962 147,412 190,581
INTEREST EXPENSE
Interest expense 350,227 331,352 309,493
Allowance for borrowed funds used during construction (12,878) (19,147) (35,430)
TOTAL 337,349 312,205 274,063
INCOME BEFORE INCOME TAXES 774,393 700,028 813,160
Income taxes 120,409 (382,324) 121,623
NET INCOME $653,984 $1,082,352 $691,537
See Notes to Financial Statements.
ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31,
2021 2020 2019
(In Thousands)
Net Income $653,984 $1,082,352 $691,537
Other comprehensive income (loss)
Pension and other postretirement liabilities
(net of tax expense (benefit) of $1,523, ($83), and $3,781)
3,951 (235) 10,715
Other comprehensive income (loss) 3,951 (235) 10,715
Comprehensive Income $657,935 $1,082,117 $702,252
See Notes to Financial Statements.
ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
2021 2020 2019
(In Thousands)
OPERATING ACTIVITIES
Net income $653,984 $1,082,352 $691,537
Adjustments to reconcile net income to net cash flow provided by operating activities:
Depreciation, amortization, and decommissioning, including nuclear fuel amortization 818,389 783,616 685,062
Deferred income taxes, investment tax credits, and non-current taxes accrued 175,700 (356,256) 196,533
Changes in working capital:
Receivables (58,466) (79,451) 13,942
Fuel inventory 7,722 (9,067) (7,195)
Accounts payable 358,536 160,659 (33,375)
Prepaid taxes and taxes accrued 21,631 50,576 (38,827)
Interest accrued 803 4,505 4,294
Deferred fuel costs (43,124) (57,895) 24,234
Other working capital accounts (45,517) (76,284) (62,536)
Changes in provisions for estimated losses (449) (295,480) 9,664
Changes in other regulatory assets (1,050,600) (410,855) (210,134)
Changes in other regulatory liabilities (16,478) 71,698 (35,881)
Changes in pension and other postretirement liabilities (164,263) 12,199 35,162
Other 394,658 192,669 (36,478)
Net cash flow provided by operating activities 1,052,526 1,072,986 1,236,002
INVESTING ACTIVITIES
Construction expenditures (3,621,775) (1,960,787) (1,673,194)
Allowance for equity funds used during construction 28,648 38,151 74,023
Nuclear fuel purchases (85,419) (92,831) (85,984)
Proceeds from the sale of nuclear fuel 13,254 44,511 11,596
Payments to storm reserve escrow account - (1,488) (6,353)
Receipts from storm reserve escrow account - 297,363 -
Changes in securitization account 2,700 951 (32)
Proceeds from nuclear decommissioning trust fund sales 944,703 347,021 412,559
Investment in nuclear decommissioning trust funds (1,004,888) (372,227) (442,501)
Changes in money pool receivable - net (1,113) (13,426) 46,843
Proceeds from sale of assets 15,000 - -
Payment for purchase of assets - (236,999) -
Insurance proceeds - - 7,040
Litigation proceeds for reimbursement of spent nuclear fuel storage costs 8,691 5,090 2,369
Net cash flow used in investing activities (3,700,199) (1,944,671) (1,653,634)
FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt 3,769,166 3,675,083 2,691,133
Retirement of long-term debt (1,895,091) (1,962,635) (2,199,053)
Capital contribution from parent 125,000 - -
Change in money pool payable - net - (82,826) 82,826
Distributions paid:
Common equity (60,000) (21,500) (208,000)
Other (849) (10,423) 9,368
Net cash flow provided by financing activities 1,938,226 1,597,699 376,274
Net increase (decrease) in cash and cash equivalents (709,447) 726,014 (41,358)
Cash and cash equivalents at beginning of period 728,020 2,006 43,364
Cash and cash equivalents at end of period $18,573 $728,020 $2,006
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized $337,926 $318,352 $296,842
Income taxes ($18,453) ($14,714) $15,272
See Notes to Financial Statements.
ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31,
2021 2020
(In Thousands)
CURRENT ASSETS
Cash and cash equivalents:
Cash $195 $1,303
Temporary cash investments 18,378 726,717
Total cash and cash equivalents 18,573 728,020
Accounts receivable:
Customer 355,265 317,905
Allowance for doubtful accounts (29,231) (45,693)
Associated companies 96,539 81,624
Other 36,674 41,760
Accrued unbilled revenues 174,768 178,840
Total accounts receivable 634,015 574,436
Deferred fuel costs 45,374 2,250
Fuel inventory 42,958 50,680
Materials and supplies - at average cost 485,325 437,933
Deferred nuclear refueling outage costs 39,582 48,407
Prepayments and other 44,187 36,813
TOTAL 1,310,014 1,878,539
OTHER PROPERTY AND INVESTMENTS
Investment in affiliate preferred membership interests 1,390,587 1,390,587
Decommissioning trust funds 2,114,523 1,794,042
Non-utility property - at cost (less accumulated depreciation) 337,247 323,110
Other 13,744 13,399
TOTAL 3,856,101 3,521,138
UTILITY PLANT
Electric 28,055,038 25,619,789
Natural gas 285,006 262,744
Construction work in progress 847,924 667,281
Nuclear fuel 209,418 210,128
TOTAL UTILITY PLANT 29,397,386 26,759,942
Less - accumulated depreciation and amortization 9,860,252 9,372,224
UTILITY PLANT - NET 19,537,134 17,387,718
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Other regulatory assets (includes securitization property of $- as of December 31, 2021 and $5,088 as of December 31, 2020)
2,776,666 1,726,066
Deferred fuel costs 168,122 168,122
Other 27,801 23,924
TOTAL 2,972,589 1,918,112
TOTAL ASSETS $27,675,838 $24,705,507
See Notes to Financial Statements.
ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
December 31,
2021 2020
(In Thousands)
CURRENT LIABILITIES
Currently maturing long-term debt $200,000 $240,000
Accounts payable:
Associated companies 183,172 103,148
Other 1,481,902 1,450,008
Customer deposits 150,697 152,612
Taxes accrued 64,248 42,617
Interest accrued 93,052 92,249
Current portion of unprotected excess accumulated deferred income taxes 24,291 31,138
Other 68,995 62,968
TOTAL 2,266,357 2,174,740
NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued 2,433,854 2,138,522
Accumulated deferred investment tax credits 102,588 107,317
Regulatory liability for income taxes - net 313,693 447,628
Other regulatory liabilities 1,042,597 918,293
Decommissioning 1,653,198 1,573,307
Accumulated provisions 24,490 24,939
Pension and other postretirement liabilities 528,213 692,728
Long-term debt (includes securitization bonds of $- as of December 31, 2021 and $10,278 as of December 31, 2020)
10,714,346 8,787,451
Other 415,930 382,894
TOTAL 17,228,909 15,073,079
Commitments and Contingencies
EQUITY
Member’s equity
8,172,294 7,453,361
Accumulated other comprehensive income 8,278 4,327
TOTAL 8,180,572 7,457,688
TOTAL LIABILITIES AND EQUITY $27,675,838 $24,705,507
See Notes to Financial Statements.
ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Years Ended December 31, 2021, 2020, and 2019
Common Equity
Member’s Equity
Accumulated Other Comprehensive Income (Loss) Total
(In Thousands)
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
Net income 1,082,352 - 1,082,352
Other comprehensive loss - (235) (235)
Distributions declared on common equity (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 loss - 3,951 3,951
Contributions from parent 125,000 - 125,000
Distributions declared on common equity (60,000) - (60,000)
Other (51) - (51)
Balance at December 31, 2021 $8,172,294 $8,278 $8,180,572
See Notes to Financial Statements.
ENTERGY MISSISSIPPI, LLC
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
2021 Compared to 2020
Net Income
Net income increased $26.3 million primarily due to higher retail electric price, partially offset by higher depreciation and amortization expenses, a higher effective income tax rate, higher taxes other than income taxes, and higher other operation and maintenance expenses.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 2021 to 2020.
Amount
(In Millions)
2020 operating revenues $1,247.9
Fuel, rider, and other revenues that do not significantly affect net income 89.0
Retail electric price 66.5
Volume/weather 2.9
2021 operating revenues $1,406.3
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 the formula rate plan rates effective April 2020, April 2021, and July 2021. See Note 2 to the financial statements for further discussion of the formula rate plan filings.
The volume/weather variance is primarily due to an increase of 343 GWh, or 3%, in billed electricity usage, including the effect of more favorable weather on residential sales and an increase in commercial usage, partially offset by a decrease in industrial usage and a decrease in usage during the unbilled sales period. The increase in commercial usage was primarily due to an increase in customers and reduced impacts from the COVID-19 pandemic on businesses as compared to prior year. The decrease in industrial usage is primarily due to a decrease in demand from mid-to-small customers.
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
Billed electric energy sales for Entergy Mississippi for the years ended December 31, 2021 and 2020 are as follows:
2021 2020 % Change
(GWh)
Residential 5,568 5,378 4
Commercial 4,469 4,283 4
Industrial 2,298 2,343 (2)
Governmental 410 398 3
Total retail 12,745 12,402 3
Sales for resale:
Non-associated companies 4,364 4,316 1
Total 17,109 16,718 2
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 $4.6 million as a result of the amount of transmission costs allocated by MISO;
•an increase of $4.3 million in compensation and benefits costs in 2021 primarily due to lower healthcare claims activity in 2020 as a result of the COVID-19 pandemic, an increase in healthcare cost rates, an increase in net periodic pension and other postretirement benefits costs as a result of a decrease in the discount rate used to value the benefit liabilities, and higher incentive-based compensation accruals in 2021 as compared to prior year. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs;
•an increase of $3.1 million in distribution maintenance work to improve reliability;
•an increase of $3.0 million primarily due to an increase in contract costs related to customer solutions and sustainability initiatives, including customer service center support and enhanced customer billing;
•an increase of $2.4 million primarily due to the amortization of deferred litigation costs related to the Mississippi Attorney General complaint against Entergy Mississippi, which was dismissed by the Hinds County Chancery Court in February 2020; and
•several individually insignificant items.
The increase was partially offset by:
•a decrease of $8.9 million in energy efficiency expenses due to the timing of recovery from customers;
•a decrease of $2.9 million in loss provisions; and
•a decrease of $2.6 million in meter reading expenses as a result of the deployment of advanced metering systems.
Taxes other than income taxes increased primarily due to increases in ad valorem taxes resulting from higher assessments.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Other regulatory charges (credits) - net includes 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
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
and regulatory credits of $19 million, recorded in the fourth quarter 2021, to reflect that the 2021 earned return is below the formula bandwidth. See Note 2 to the financial statements for discussion of the formula rate plan filings.
Interest expense increased primarily due to the issuance of $170 million of 3.50% Series mortgage bonds in May 2020 and an additional $200 million in a reopening of the same series in March 2021.
The effective income tax rates were 21.4% for 2021 and 16.2% for 2020. 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.
2020 Compared to 2019
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, 2020, filed with the SEC on February 26, 2021, for discussion of results of operations for 2020 compared to 2019.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2021, 2020, and 2019 were as follows:
2021 2020 2019
(In Thousands)
Cash and cash equivalents at beginning of period $18 $51,601 $36,954
Net cash provided by (used in):
Operating activities 350,960 300,314 339,952
Investing activities (686,654) (530,762) (733,684)
Financing activities 383,303 178,865 408,379
Net increase (decrease) in cash and cash equivalents 47,609 (51,583) 14,647
Cash and cash equivalents at end of period $47,627 $18 $51,601
2021 Compared to 2020
Operating Activities
Net cash flow provided by operating activities increased $50.6 million in 2021 primarily due to higher collections from customers and an increase of $11.6 million in income tax refunds. The increase was partially offset by the timing of payments to vendors, increased fuel costs, including those related to Winter Storm Uri, and an increase of approximately $12.3 million in storm spending in 2021, primarily due to Winter Storm Uri. Entergy Mississippi received income tax refunds in 2021 and 2020, each in accordance with an intercompany income tax allocation agreement. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery.
Investing Activities
Net cash flow used in investing activities increased $155.9 million in 2021 primarily due to:
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
•an increase $89.9 million in distribution construction expenditures primarily due to increased spending on the reliability and infrastructure of the distribution system and higher capital expenditures for storm restoration in 2021, partially offset by decreased spending on advanced metering infrastructure; and
•money pool activity.
The increase was partially offset by $24.6 million in plant upgrades for the Choctaw Generating Station in March 2020.
Increases in Entergy Mississippi’s receivable from the money pool are a use of cash flow, and Entergy Mississippi’s receivable from the money pool increased by $40.5 million in 2021 compared to decreasing by $44.7 million in 2020. 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 $204.4 million in 2021 primarily due to the issuance of $200 million of 3.50% Series first mortgage bonds in March 2021 and the issuance of $200 million of 2.55% Series first mortgage bonds in November 2021. The increase was partially offset by the issuance of $170 million of 3.50% Series mortgage bonds in May 2020 and money pool activity.
Decreases in Entergy Mississippi’s payable to the money pool are a use of cash flow, and Entergy Mississippi’s payable to the money pool decreased $16.5 million in 2021 as compared to increasing by $16.5 million in 2020.
See Note 5 to the financial statements for details on long-term debt.
2020 Compared to 2019
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, 2020, filed with the SEC on February 26, 2021, for discussion of operating, investing, and financing cash flow activities for 2020 compared to 2019.
Capital Structure
Entergy Mississippi’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio for Entergy Mississippi is primarily due to the issuance of long-term debt in 2021.
December 31,
2021 December 31,
Debt to capital 54.3 % 51.7 %
Effect of subtracting cash (0.5 %) - %
Net debt to net capital 53.8 % 51.7 %
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. 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
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
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, 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.
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.
2022 2023 2024
(In Millions)
Planned construction and capital investment:
Generation $185 $85 $50
Transmission 80 90 100
Distribution 220 250 225
Utility Support 100 50 30
Total $585 $475 $405
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Mississippi includes generation projects to modernize, decarbonize, and diversify Entergy Mississippi’s portfolio, such as the Sunflower Solar Facility; distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to drive reliability and resilience while 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, 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 and lease obligations (includes estimated interest payments).
2022 2023 2024 2025-2026 After 2026
(In Millions)
Long-term debt (a) $77 $323 $167 $131 $3,128
Operating leases (b) $6 $4 $3 $3 $2
Finance leases (b) $2 $2 $2 $3 $1
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
(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 Mississippi currently expects to contribute approximately $12.9 million to its qualified pension plans and approximately $130 thousand to other postretirement health care and life insurance plans in 2022, although the 2022 required pension contributions will be known with more certainty when the January 1, 2022 valuations are completed, which is expected by April 1, 2022. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Entergy Mississippi has $160.8 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, Entergy Mississippi enters into fuel and purchased power agreements that contain minimum purchase obligations. Entergy Mississippi 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 Mississippi’s obligations under the Unit Power Sales Agreement.
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 solar photovoltaic facility that will 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 Facility 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 is being built by Sunflower County Solar Project, LLC, an 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 Solar Project with the MPSC for Sunflower 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. 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. Recovery through the interim capacity rate adjustment requires MPSC approval for each new resource. In August 2019 consultants retained by the Mississippi Public Utilities Staff filed a report expressing concerns regarding the project economics. In March 2020, Entergy Mississippi filed supplemental testimony addressing questions and observations raised by the consultants retained by the Mississippi Public Utilities Staff and proposing an alternative structure for the transaction that would reduce its cost. A hearing before the MPSC was held in March 2020. In April 2020 the MPSC issued an order approving certification of the Sunflower Solar Facility and its recovery through the interim capacity rate adjustment mechanism, subject to certain conditions including: (i) that Entergy Mississippi pursue a partnership structure through which the partnership 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 order, there will be a cap of $136 million on the
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
level of recoverable costs. Closing is targeted to occur by the end of the second quarter 2022.
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, 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 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 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 for the next twelve months and beyond.
Entergy Mississippi’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
2021 2020 2019 2018
(In Thousands)
$40,456 ($16,516) $44,693 $41,380
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 million scheduled to expire in April 2022. No borrowings were outstanding under the credit facilities as of December 31, 2021. 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, 2021, $9.3 million in MISO letters of credit and $1 million in non-MISO letters of credit were outstanding under this facility. See Note 4 to the financial statements for additional discussion of the credit facilities.
Entergy Mississippi obtained authorization from the FERC through October 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 Mississippi’s short-term borrowing limits.
Entergy Mississippi has $33 million in its storm reserve escrow account at December 31, 2021.
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy Mississippi charges for electricity significantly influence its financial position, results
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
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.
Formula Rate Plan Revisions
In October 2018, Entergy Mississippi proposed revisions to its formula rate plan that would provide for a mechanism in the formula rate plan, the interim capacity rate adjustment mechanism, to recover the non-fuel related costs of additional owned capacity acquired by Entergy Mississippi, including the non-fuel annual ownership costs of the Choctaw Generating Station, as well as to allow similar cost recovery treatment for other future capacity acquisitions, such as the Sunflower Solar Facility, that are approved by the MPSC. In December 2019 the MPSC approved Entergy Mississippi’s proposed revisions to its formula rate plan to provide for an interim capacity rate adjustment mechanism to recover the $59 million first-year annual revenue requirement associated with the non-fuel ownership costs of the Choctaw Generating Station, which Entergy Mississippi began billing in January 2020. The MPSC must approve recovery through the interim capacity rate adjustment for each new resource. In addition, the MPSC approved revisions to the formula rate plan which allows Entergy Mississippi to begin billing rate adjustments effective April 1 of the filing year on a temporary basis subject to refund or credit to customers, subject to final MPSC order. The MPSC also authorized Entergy Mississippi to remove vegetation management costs from the formula rate plan and recover these costs through the establishment of a vegetation management rider. Effective with the April 2020 billing cycle, Entergy Mississippi implemented a rider to recover $22 million in vegetation management costs.
2019 Formula Rate Plan Filing
In March 2019, Entergy Mississippi submitted its formula rate plan 2019 test year filing and 2018 look-back filing showing Entergy Mississippi’s earned return for the historical 2018 calendar year to be above the formula rate plan bandwidth and projected earned return for the 2019 calendar year to be below the formula rate plan bandwidth. The 2019 test year filing shows a $36.8 million rate increase is necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.94% return on rate base, within the formula rate plan bandwidth. The 2018 look-back filing compares actual 2018 results to the approved benchmark return on rate base and shows a $10.1 million interim decrease in formula rate plan revenues is necessary. In the fourth quarter 2018, Entergy Mississippi recorded a provision of $9.3 million that reflected the estimate of the difference between the 2018 expected earned rate of return on rate base and an established performance-adjusted benchmark rate of return under the formula rate plan performance-adjusted bandwidth mechanism. In the first quarter 2019, Entergy Mississippi recorded a $0.8 million increase in the provision to reflect the amount shown in the look-back filing. In June 2019, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed that the 2019 test year filing showed that a $32.8 million rate increase is necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.93% return on rate base, within the formula rate plan bandwidth. Additionally, pursuant to the joint stipulation, Entergy Mississippi’s 2018 look-back filing reflected an earned return on rate base of 7.81% in calendar year 2018 which is above the look-back benchmark return on rate base of 7.13%, resulting in an $11 million decrease in formula rate plan revenues on an interim basis through May 2020. In the second quarter 2019, Entergy Mississippi recorded an additional $0.9 million increase in the provision to reflect the $11 million shown in the look-back filing. In June 2019 the MPSC approved the joint stipulation with rates effective for the first billing cycle of July 2019.
2020 Formula Rate Plan Filing
In March 2020, Entergy Mississippi submitted its formula rate plan 2020 test year filing and 2019 look-back filing showing Entergy Mississippi’s earned return for the historical 2019 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2020 calendar year to be below the formula rate plan bandwidth. The 2020 test year filing shows a $24.6 million rate increase is necessary to reset Entergy
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
Mississippi’s earned return on common equity to the specified point of adjustment of 6.51% return on rate base, within the formula rate plan bandwidth. The 2019 look-back filing compares actual 2019 results to the approved benchmark return on rate base and reflects the need for a $7.3 million interim increase in formula rate plan revenues. In accordance with the MPSC-approved revisions to the formula rate plan, Entergy Mississippi implemented a $24.3 million interim rate increase, reflecting a cap equal to 2% of 2019 retail revenues, effective with the April 2020 billing cycle, subject to refund. In June 2020, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed that the 2020 test year filing showed that a $23.8 million rate increase is necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.51% return on rate base, within the formula rate plan bandwidth. Pursuant to the joint stipulation, Entergy Mississippi’s 2019 look-back filing reflected an earned return on rate base of 6.75% in calendar year 2019, which is within the look-back bandwidth. As a result, there is no change in formula rate plan revenues in the 2019 look-back filing. In June 2020 the MPSC approved the joint stipulation with rates effective for the first billing cycle of July 2020. In the June 2020 order the MPSC directed Entergy Mississippi to submit revisions to its formula rate plan to realign recovery of costs from its energy efficiency cost recovery rider to its formula rate plan. In November 2020 the MPSC approved Entergy Mississippi’s revisions to its formula rate plan providing for the realignment of energy efficiency costs to its formula rate plan, the deferral of energy efficiency expenditures into a regulatory asset, and the elimination of its energy efficiency cost recovery rider effective with the January 2022 billing cycle.
2021 Formula Rate Plan Filing
In March 2021, Entergy Mississippi submitted 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 interim 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 with the April 2021 billing cycle, subject to refund, pending a final MPSC order. 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 the 2% cap of 2020 retail revenues, were included in the April 2021 rate adjustments.
In June 2021, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed the 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 June 2021 the MPSC approved 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
Entergy Mississippi’s formula rate plan includes a look-back evaluation report filing in March 2022 that
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
will compare actual 2021 results to the performance-adjusted allowed return on rate base. In fourth quarter 2021, Entergy Mississippi recorded a regulatory asset of $19 million in connection with the look-back feature of the formula rate plan to reflect that the 2021 earned return was below the formula bandwidth.
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 2021 formula rate plan filing, Entergy Mississippi stopped deferring COVID-19 non-bad debt expenses effective December 31, 2020 and included those expenses in the look-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. As of December 31, 2021, Entergy Mississippi had a regulatory asset of $15.0 million for costs associated with the COVID-19 pandemic.
Fuel and Purchased 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 November 2018, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an under-recovery of approximately $57 million as of September 30, 2018. In January 2019 the MPSC approved the proposed energy cost factor effective for February 2019 bills.
In November 2019, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation included $39.6 million of prior over-recovery flowing back to customers beginning September 2020. Entergy Mississippi’s balance in its deferred fuel account did not decrease as expected after implementation of the new factor. In an effort to assist customers during the COVID-19 pandemic, in May 2020, Entergy Mississippi requested an interim adjustment to the energy cost recovery rider to credit approximately $50 million from the over-recovered balance in the deferred fuel account to customers over four consecutive billing months. The MPSC approved this interim adjustment in May 2020 effective for June through September 2020 bills.
In November 2020, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an over-recovery of approximately $24.4 million as of September 30, 2020. In January 2021 the MPSC approved the proposed energy cost factor effective for February 2021 bills.
In November 2021, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an under-recovery of approximately $80.6 million as of September 30, 2021. In December 2021, at the request of the MPSC, Entergy Mississippi submitted a proposal to mitigate the impact of rising fuel costs on customer bills during 2022. Entergy Mississippi proposed that the deferred fuel balance as of December 31, 2021, which was $121.9 million, be amortized over three years, and that the MPSC authorize Entergy Mississippi to apply its weighted-average cost of capital as the carrying cost for the unamortized fuel balance. In January 2022 the MPSC approved the amortization
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
of $100 million of the deferred fuel balance over two years and authorized Entergy Mississippi to apply its weighted-average cost of capital as the carrying cost for the unamortized fuel balance. The MPSC approved the proposed energy cost factor effective for February 2022 bills.
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. Entergy Mississippi’s storm damage provision balance has been less than $10 million since May 2019, and Entergy Mississippi has been billing the monthly storm damage provision since July 2019.
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.
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
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 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 “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.
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 2022 Qualified Pension Cost Impact on 2021 Projected Qualified Benefit Obligation
Increase/(Decrease)
Discount rate (0.25%) $507 $11,348
Rate of return on plan assets (0.25%) $771 $-
Rate of increase in compensation 0.25% $539 $2,523
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 2022 Postretirement Benefit Cost Impact on 2021 Accumulated Postretirement Benefit Obligation
Increase/(Decrease)
Discount rate (0.25%) $51 $1,876
Health care cost trend 0.25% $71 $1,224
Each fluctuation above assumes that the other components of the calculation are held constant.
Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis
Costs and Employer Contributions
Total qualified pension cost for Entergy Mississippi in 2021 was $33.8 million, including $16.7 million in settlement costs. Entergy Mississippi anticipates 2022 qualified pension cost to be $13.7 million. Entergy Mississippi contributed $13.7 million to its qualified pension plans in 2021 and estimates 2022 pension contributions will be approximately $12.9 million, although the 2022 required pension contributions will be known with more certainty when the January 1, 2022 valuations are completed, which is expected by April 1, 2022.
Total postretirement health care and life insurance benefit income for Entergy Mississippi in 2021 was $4.7 million. Entergy Mississippi expects 2022 postretirement health care and life insurance benefit income of approximately $4.4 million. In 2021, Entergy Mississippi’s contributions (that is, contributions to the external trusts plus claims payments) were offset by trust claims reimbursements, resulting in a net reimbursement of $393 thousand. Entergy Mississippi estimates that 2022 contributions will be approximately $130 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
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Entergy Mississippi, LLC (the “Company”) as of December 31, 2021 and 2020, the related statements of income, cash flows and changes in member’s equity (pages 372 through 376 and applicable items in pages 49 through 233), for each of the three years in the period ended December 31, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, 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 - 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, such as property, plant, and equipment;
regulatory assets and liabilities; income taxes; operating revenues; operation and maintenance expense; and depreciation and amortization expense.
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 especially subjective judgment and specialized knowledge of accounting for rate regulation and the rate setting process.
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 and other public utilities, regulatory statutes, interpretations, procedural memorandums, 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 25, 2022
We have served as the Company’s auditor since 2001.
ENTERGY MISSISSIPPI, LLC
INCOME STATEMENTS
For the Years Ended December 31,
2021 2020 2019
(In Thousands)
OPERATING REVENUES
Electric $1,406,346 $1,247,854 $1,323,043
OPERATING EXPENSES
Operation and Maintenance:
Fuel, fuel-related expenses, and gas purchased for resale 181,511 187,087 277,425
Purchased power 298,034 240,471 284,492
Other operation and maintenance 298,129 288,543 266,175
Taxes other than income taxes 111,712 101,525 105,318
Depreciation and amortization 226,545 209,252 170,886
Other regulatory charges (credits) - net 5,913 (15,219) 14,993
TOTAL 1,121,844 1,011,659 1,119,289
OPERATING INCOME 284,502 236,195 203,754
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction 8,101 6,726 8,356
Interest and investment income 53 272 1,412
Miscellaneous - net (8,791) (9,253) (4,478)
TOTAL (637) (2,255) 5,290
INTEREST EXPENSE
Interest expense 75,124 68,945 61,785
Allowance for borrowed funds used during construction (3,416) (2,778) (3,532)
TOTAL 71,708 66,167 58,253
INCOME BEFORE INCOME TAXES 212,157 167,773 150,791
Income taxes 45,323 27,190 30,866
NET INCOME $166,834 $140,583 $119,925
See Notes to Financial Statements.
ENTERGY MISSISSIPPI, LLC
STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
2021 2020 2019
(In Thousands)
OPERATING ACTIVITIES
Net income $166,834 $140,583 $119,925
Adjustments to reconcile net income to net cash flow provided by operating activities:
Depreciation and amortization 226,545 209,252 170,886
Deferred income taxes, investment tax credits, and non-current taxes accrued 64,868 36,827 32,547
Changes in assets and liabilities:
Receivables 10,260 (1,889) (17,245)
Fuel inventory 6,806 (1,978) (3,208)
Accounts payable 27,068 22,794 (226)
Taxes accrued (1,811) 17,423 13,109
Interest accrued (3,606) 1,989 (1,331)
Deferred fuel costs (136,569) (55,711) 78,418
Other working capital accounts (9,522) 630 (5,557)
Provisions for estimated losses (8,476) (3,517) (1,121)
Other regulatory assets 4,909 (89,369) (34,923)
Other regulatory liabilities 21,930 (18,672) (21,524)
Pension and other postretirement liabilities (51,828) 11,319 6,534
Other assets and liabilities 33,552 30,633 3,668
Net cash flow provided by operating activities 350,960 300,314 339,952
INVESTING ACTIVITIES
Construction expenditures (654,352) (555,287) (432,600)
Allowance for equity funds used during construction 8,101 6,726 8,356
Changes in money pool receivable - net (40,456) 44,692 (3,313)
Payment for purchase of plant or assets - (28,612) (305,472)
Other 53 1,719 (655)
Net cash flow used in investing activities (686,654) (530,762) (733,684)
FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt 398,284 165,385 437,153
Retirement of long-term debt - - (150,000)
Changes in money pool payable - net (16,516) 16,516 -
Capital contributions from parent - - 130,000
Distributions/dividends paid:
Common equity - (10,000) -
Other 1,535 6,964 (8,774)
Net cash flow provided by financing activities 383,303 178,865 408,379
Net increase (decrease) in cash and cash equivalents 47,609 (51,583) 14,647
Cash and cash equivalents at beginning of period 18 51,601 36,954
Cash and cash equivalents at end of period $47,627 $18 $51,601
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized $76,245 $64,536 $60,533
Income taxes ($19,672) ($8,084) ($12,204)
See Notes to Financial Statements.
ENTERGY MISSISSIPPI, LLC
BALANCE SHEETS
ASSETS
December 31,
2021 2020
(In Thousands)
CURRENT ASSETS
Cash and cash equivalents:
Cash $29 $11
Temporary cash investments 47,598 7
Total cash and cash equivalents 47,627 18
Accounts receivable:
Customer 84,048 105,732
Allowance for doubtful accounts (7,209) (19,527)
Associated companies 42,994 2,740
Other 14,609 11,821
Accrued unbilled revenues 56,034 59,514
Total accounts receivable 190,476 160,280
Deferred fuel costs 121,878 -
Fuel inventory - at average cost 10,311 17,117
Materials and supplies - at average cost 69,639 59,542
Prepayments and other 6,394 4,876
TOTAL 446,325 241,833
OTHER PROPERTY AND INVESTMENTS
Non-utility property - at cost (less accumulated depreciation) 4,527 4,543
Escrow accounts 48,886 64,635
TOTAL 53,413 69,178
UTILITY PLANT
Electric 6,613,109 6,084,730
Construction work in progress 95,452 134,854
TOTAL UTILITY PLANT 6,708,561 6,219,584
Less - accumulated depreciation and amortization 2,127,590 2,005,087
UTILITY PLANT - NET 4,580,971 4,214,497
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Other regulatory assets 462,432 467,341
Other 14,248 14,413
TOTAL 476,680 481,754
TOTAL ASSETS $5,557,389 $5,007,262
See Notes to Financial Statements.
ENTERGY MISSISSIPPI, LLC
BALANCE SHEETS
LIABILITIES AND EQUITY
December 31,
2021 2020
(In Thousands)
CURRENT LIABILITIES
Accounts payable:
Associated companies $42,929 $61,727
Other 113,000 117,629
Customer deposits 86,167 86,200
Taxes accrued 106,273 108,084
Interest accrued 17,283 20,889
Deferred fuel costs - 14,691
Other 36,731 34,270
TOTAL 402,383 443,490
NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued 720,097 646,674
Accumulated deferred investment tax credits 10,913 9,062
Regulatory liability for income taxes - net 212,445 224,000
Other regulatory liabilities 49,313 15,828
Asset retirement cost liabilities 10,315 9,762
Accumulated provisions 38,028 46,504
Pension and other postretirement liabilities 59,065 110,901
Long-term debt 2,179,989 1,780,577
Other 35,273 47,730
TOTAL 3,315,438 2,891,038
Commitments and Contingencies
EQUITY
Member's equity 1,839,568 1,672,734
TOTAL 1,839,568 1,672,734
TOTAL LIABILITIES AND EQUITY $5,557,389 $5,007,262
See Notes to Financial Statements.
ENTERGY MISSISSIPPI, LLC
STATEMENTS OF CHANGES IN MEMBER'S EQUITY
For the Years Ended December 31, 2021, 2020, and 2019
Member's Equity
(In Thousands)
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
Net income 140,583
Common equity distributions (10,000)
Balance at December 31, 2020 $1,672,734
Net income 166,834
Balance at December 31, 2021 $1,839,568
See Notes to Financial Statements.
ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
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. Total restoration costs for the repair and/or replacement of the electrical system damaged by Hurricane Ida are currently estimated to be approximately $200 million. Also, Entergy New Orleans’s revenues in 2021 were adversely affected by extended power outages resulting from the hurricane.
Entergy New Orleans has recorded accounts payable for the estimated costs incurred that were necessary to return customers to service. Entergy New Orleans recorded corresponding regulatory assets of approximately $80 million and construction work in progress of approximately $120 million. Entergy New Orleans recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. There are well-established mechanisms and precedent for addressing these catastrophic events and providing for recovery of prudently incurred storm costs in accordance with applicable regulatory and legal principles.
Entergy New Orleans is considering all available avenues to recover storm-related costs from Hurricane Ida, including federal government assistance and securitization financing. In September 2021, Entergy New Orleans withdrew $39 million from its funded storm reserves. Entergy New Orleans believes its liquidity is sufficient to meet its current obligations. As of December 31, 2021, Entergy New Orleans has $42.9 million of cash and cash equivalents and the ability to borrow up to $150 million from the Entergy System money pool.
In September 2021 the City Council issued a number of resolutions associated with Hurricane Ida including: (1) a resolution initiating an investigation of Entergy New Orleans’s preparation for and response to Hurricane Ida and a statement that the City Council opposes recovery of Hurricane Ida costs unless it is demonstrated that any such restoration costs are unrelated to deficient maintenance practices; and (2) resolutions requesting that the LPSC and the FERC study the prudence of Entergy Louisiana’s transmission planning. Entergy New Orleans will oppose any attempt by the City Council to alter the legal standard in Louisiana that allows Entergy New Orleans to recover its prudently incurred hurricane restoration costs. Because storm cost recovery or financing will be subject to review by applicable regulatory authorities and Entergy New Orleans has not gone through the regulatory process regarding Hurricane Ida storm costs, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs and incremental losses it may ultimately recover, or the timing of such recovery. In February 2022, Entergy New Orleans 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.
Results of Operations
2021 Compared to 2020
Net Income
Net income decreased $17.5 million primarily due to higher other operation and maintenance expenses, higher depreciation and amortization expenses, a higher effective income tax rate, lower volume/weather, and lower other income. The decrease was partially offset by higher retail electric price.
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Operating Revenues
Following is an analysis of the change in operating revenues comparing 2021 to 2020:
Amount
(In Millions)
2020 operating revenues $633.8
Fuel, rider, and other revenues that do not significantly affect net income 102.4
Retail electric price 41.0
Volume/weather (8.3)
2021 operating revenues $768.9
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 an interim increase in formula rate plan revenues resulting from the recovery of New Orleans Power Station costs, effective November 2020, and a rate increase effective November 2021 in accordance with the terms of the 2021 formula rate plan filing. See Note 2 to the financial statements for further discussion of the rate case resolution and the formula rate plan filing.
The volume/weather variance is primarily due to decreased residential and industrial usage, including the effect of Hurricane Ida in the third quarter 2021, and decreased usage during the unbilled sales period, partially offset by the effect of more favorable weather on residential sales. The decrease in industrial usage is primarily due to a decrease in demand from existing customers, primarily in the food products industry. See “Hurricane Ida” above for further discussion of the effects of Hurricane Ida.
Billed electric energy sales for Entergy New Orleans for the years ended December 31, 2021 and 2020 are as follows:
2021 2020 % Change
(GWh)
Residential 2,258 2,294 (2)
Commercial 1,978 1,975 -
Industrial 415 423 (2)
Governmental 755 755 -
Total retail 5,406 5,447 (1)
Sales for resale:
Non-associated companies 2,369 1,969 20
Total 7,775 7,416 5
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:
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
•an increase of $6.5 million in non-nuclear generation expenses primarily due to the timing of the scope of work performed during plant outages in 2021 as compared to 2020 and higher expenses associated with the New Orleans Power Station, which was placed in service in May 2020;
•an increase of $5.7 million in energy efficiency expenses due to the timing of recovery from customers;
•an increase of $2.5 million primarily due to an increase in contract costs related to customer solutions and sustainability initiatives, including customer service center support and enhanced customer billing; and
•an increase of $2.3 million in compensation and benefits costs in 2021 primarily due to lower healthcare claims activity in 2020 as a result of the COVID-19 pandemic, an increase in healthcare cost rates, and an increase in net periodic pension and other postretirement benefits costs as a result of a decrease in the discount rate used to value the benefit liabilities. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs.
Taxes other than income taxes decreased primarily due to a decrease in ad valorem taxes.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including the New Orleans Power Station, which was placed in service in May 2020.
Other regulatory charges (credits) - net includes regulatory credits recorded in first quarter 2020 to reflect compliance with terms of the 2018 combined rate case resolution approved by the City Council in February 2020. See Note 2 to the financial statements for further discussion of the rate case resolution.
Other income decreased primarily due to a decrease in the allowance for equity funds used during construction due to higher construction work in progress in 2020, including the New Orleans Power Station project.
The effective income tax rates were 15.7% for 2021 and (9.3%) for 2020. 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.
2020 Compared to 2019
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, 2020, filed with the SEC on February 26, 2021, for discussion of results of operations for 2020 compared to 2019.
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, 2021, 2020, and 2019 were as follows:
2021 2020 2019
(In Thousands)
Cash and cash equivalents at beginning of period $26 $6,017 $19,677
Net cash provided by (used in):
Operating activities 78,808 64,024 115,604
Investing activities (169,920) (220,845) (204,310)
Financing activities 133,948 150,830 75,046
Net increase (decrease) in cash and cash equivalents 42,836 (5,991) (13,660)
Cash and cash equivalents at end of period $42,862 $26 $6,017
2021 Compared to 2020
Operating Activities
Net cash flow provided by operating activities increased $14.8 million in 2021 primarily due to:
•higher collections from customers;
•the timing of recovery of fuel and purchased power costs; and
•income tax refunds of $3.8 million received in 2021 compared to income tax payments of $3.4 million made in 2020, each in accordance with an intercompany income tax allocation agreement.
The increase was partially offset by the timing of payments to vendors and an increase of $20.6 million in storm spending in 2021, primarily due to Hurricane Ida restoration efforts. See “Hurricane Ida” above for discussion of hurricane restoration efforts.
Investing Activities
Net cash flow used in investing activities decreased $50.9 million in 2021 primarily due to $83 million in receipts from storm reserve escrow accounts in 2021 and a decrease of $54.3 million in non-nuclear generation construction expenditures primarily due to lower spending on the New Orleans Power Station and the New Orleans Solar Station projects.
The decrease was partially offset by:
•an increase of $74.2 million in distribution construction expenditures primarily due to higher capital expenditures for storm restoration in 2021, partially offset by lower spending on advanced metering infrastructure. The increase in storm restoration spending is primarily due to Hurricane Ida restoration efforts. See “Hurricane Ida” above for discussion of hurricane restoration efforts; and
•money pool activity.
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Increases in Entergy New Orleans’s receivable from the money pool are a use of cash flow, and Entergy New Orleans’s receivable from the money pool increased $36.4 million in 2021 compared to decreasing $5.2 million in 2020. 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 $16.9 million primarily due to a capital contribution of $60 million received from Entergy Corporation in November 2020 in order to maintain Entergy New Orleans’s capital structure and money pool activity. The decrease was partially offset by long-term debt activity providing $183.4 million of cash in 2021 compared to providing $138.9 million of cash in 2020 and repayments of long-term credit borrowings of $20 million in 2020.
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 compared to increasing by $10.2 million in 2020.
See Note 5 to the financial statements for details on long-term debt.
2020 Compared to 2019
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, 2020, filed with the SEC on February 26, 2021, for discussion of results of operations for 2020 compared to 2019.
Capital Structure
Entergy New Orleans’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio is primarily due to the net issuance of long-term debt in 2021.
December 31,
2021 December 31,
Debt to capital 55.4 % 51.5 %
Effect of excluding securitization bonds (1.0 %) (1.6 %)
Debt to capital, excluding securitization bonds (a) 54.4 % 49.9 %
Effect of subtracting cash (1.4 %) - %
Net debt to net capital, excluding securitization bonds (a) 53.0 % 49.9 %
(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. Entergy New Orleans 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 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, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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, 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.
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.
2022 2023 2024
(In Millions)
Planned construction and capital investment:
Generation $10 $- $5
Transmission 25 20 15
Distribution 105 115 140
Utility Support 25 10 10
Total $165 $145 $170
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy New Orleans includes generation projects to modernize, decarbonize, and diversify Entergy New Orleans’s portfolio; distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to drive reliability and resilience while 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, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.
In addition to the planned spending in the table above, Entergy New Orleans also expects to pay for $95 million of capital investments in 2022 related to Hurricane Ida restoration work that has been accrued as of December 31, 2021.
Following are the amounts of Entergy New Orleans’s existing debt and lease obligations (includes estimated interest payments).
2022 2023 2024 2025-2026 After 2026
(In Millions)
Long-term debt (a) $44 $211 $38 $214 $787
Operating leases (b) $2 $1 $1 $1 $1
Finance leases (b) $1 $1 $1 $1 $1
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
(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 New Orleans currently expects to contribute approximately $922 thousand to its qualified pension plan and approximately $175 thousand to other postretirement health care and life insurance plans in 2022, although the 2022 required pension contributions will be known with more certainty when the January 1, 2022 valuations are completed, which is expected by April 1, 2022. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Entergy New Orleans has $154.6 million of 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, Entergy New Orleans enters into fuel and purchased power agreements that contain minimum purchase obligations. Entergy New Orleans 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 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.
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, the 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 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. Due to a delay resulting from Hurricane Ida, Entergy New Orleans now expects to begin receiving power under the 50 MW Iris Solar and the 20 MW St. James Solar power purchase agreements in 2022.
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;
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
•storm reserve escrow accounts;
•debt and 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 New Orleans 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 New Orleans require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in its bond indenture and other agreements. Entergy New Orleans has sufficient capacity under these tests to meet its foreseeable capital 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.
2021 2020 2019 2018
(In Thousands)
$36,410 ($10,190) $5,191 $22,016
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 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, 2021, there were no cash borrowings and no 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, 2021, a $1 million letter of credit was outstanding under Entergy New Orleans’s 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 2023 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.
Hurricane Zeta
In October 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, including approximately $28 million in capital costs and approximately $8 million in non-capital 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.
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
State and Local Rate Regulation
The rates that Entergy New Orleans charges for electricity and natural gas 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
2018 Base Rate Case
In September 2018, Entergy New Orleans filed an electric and gas base rate case with the City Council. The filing requested a 10.5% return on equity for electric operations with opportunity to earn a 10.75% return on equity through a performance adder provision of the electric formula rate plan in subsequent years under a formula rate plan and requested a 10.75% return on equity for gas operations. The filing’s major provisions included: (1) a new electric rate structure, which realigns the revenue requirement associated with capacity and long-term service agreement expense from certain existing riders to base revenue, provides for the recovery of the cost of advanced metering infrastructure, and partially blends rates for Entergy New Orleans’s customers residing in Algiers with customers residing in the remainder of Orleans Parish through a three-year phase-in; (2) contemporaneous cost recovery riders for investments in energy efficiency/demand response, incremental changes in capacity/long-term service agreement costs, grid modernization investment, and gas infrastructure replacement investment; and (3) formula rate plans for both electric and gas operations.
In October 2019 the City Council’s Utility Committee approved a resolution for a change in electric and gas rates for consideration by the full City Council that included a 9.35% return on common equity, an equity ratio of the lesser of 50% or Entergy New Orleans’s actual equity ratio, and a total reduction in revenues that Entergy New Orleans initially estimated to be approximately $39 million ($36 million electric; $3 million gas). At its November 7, 2019 meeting, the full City Council approved the resolution that had previously been approved by the City Council’s Utility Committee. Based on the approved resolution, in the fourth quarter 2019 Entergy New Orleans recorded an accrual of $10 million that reflects the estimate of the revenue billed in 2019 to be refunded to customers in 2020 based on an August 2019 effective date for the rate decrease. Entergy New Orleans also recorded a total of $12 million in regulatory assets for rate case costs and information technology costs associated with integrating Algiers customers with Entergy New Orleans’s legacy system and records. Entergy New Orleans will also be allowed to recover $10 million of retired general plant costs over a 20-year period.
The resolution directed Entergy New Orleans to submit a compliance filing within 30 days of the date of the resolution to facilitate the eventual implementation of rates, including all necessary calculations and conforming rate schedules and riders. The electric formula rate plan rider includes, among other things, (1) a provision for forward-looking adjustments to include known and measurable changes realized up to 12 months after the evaluation period; (2) a decoupling mechanism; and (3) recognition that Entergy New Orleans is authorized to make an in-service adjustment to the formula rate plan to include the non-fuel cost of the New Orleans Power Station in rates, unless the two pending appeals in the New Orleans Power Station proceeding have not concluded. Under this circumstance, Entergy New Orleans shall be permitted to defer the New Orleans Power Station non-fuel costs, including the cost of capital, until Entergy New Orleans commences non-fuel cost recovery. After taking into account the requirements for submission of the compliance filing, the total annual revenue requirement reduction required by the resolution was refined to approximately $45 million ($42 million electric, including $29 million in rider reductions; $3 million gas). In January 2020 the City Council’s advisors found that the rates calculated by Entergy New Orleans and reflected in the December 2019 compliance filing should be implemented, except with respect to the City Council-approved energy efficiency cost recovery rider, which rider calculation should take into account events to be determined by the City Council in the future. On February 17, 2020, Entergy New Orleans filed with the City Council an agreement in principle between Entergy New Orleans and the City Council’s advisors. On February 20, 2020, the City Council voted to approve the proposed agreement in principle and issued
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
a resolution modifying the required treatment of certain accumulated deferred income taxes. As a result of the agreement in principle, the total annual revenue requirement reduction will be approximately $45 million ($42 million electric, including $29 million in rider reductions; and $3 million gas). Entergy New Orleans fully implemented the new rates in April 2020.
Commercial operation of the New Orleans Power Station commenced in May 2020. In accordance with the City Council resolution issued in the 2018 base rate case proceeding, Entergy New Orleans had been deferring the New Orleans Power Station non-fuel costs pending the conclusion of the appellate proceedings. In October 2020 the Louisiana Supreme Court denied all writ applications relating to the New Orleans Power Station. With those denials, Entergy New Orleans began recovering New Orleans Power Station costs in rates in November 2020. Entergy New Orleans is recovering the costs over a five-year period that began in November 2020. In December 2020 the Alliance for Affordable Energy and Sierra Club filed a joint motion with the City Council to institute a prudence review to investigate the costs of the New Orleans Power Station. On January 28, 2021, the City Council passed a resolution giving parties 30 days to respond to the motion. In March 2021, Entergy New Orleans filed a response to that motion stating that a prudence review is unnecessary given the New Orleans Power Station was constructed on budget and ahead of schedule. As of December 31, 2021 the regulatory asset for the deferral of New Orleans Power Station non-fuel costs was $4 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 in November 2019 was originally due to be filed in April 2020. The authorized return on equity under the approved three-year formula rate plan is 9.35% for both electric and gas operations. The City Council approved several extensions of the deadline to allow additional time to assess the effects of the COVID-19 pandemic on the New Orleans community, Entergy New Orleans customers, and Entergy New Orleans itself. In October 2020 the City Council approved an agreement in principle filed by Entergy New Orleans that results in Entergy New Orleans foregoing its 2020 formula rate plan filing and shifting the three-year formula rate plan to filings in 2021, 2022, and 2023. Key provisions of the agreement in principle include: changing the lower of actual equity ratio or 50% equity ratio approved in the rate case to a hypothetical capital structure of 51% equity and 49% debt for the duration of the three-year formula rate plan; changing the 2% depreciation rate for the New Orleans Power Station approved in the rate case to 3%; retention of over-recovery of $2.2 million in rider revenues; recovery of $1.4 million of certain rate case expenses outside of the earnings band; recovery of the New Orleans Solar Station costs upon commercial operation; and Entergy New Orleans’s dismissal of its 2018 rate case appeal.
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 $17.6 million
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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.
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 $17.4 million for costs associated with the COVID-19 pandemic.
In June 2020 the City Council established the City Council Cares Program and directed Entergy New Orleans to use the approximately $7 million refund received from the Entergy Arkansas opportunity sales FERC proceeding 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 maximum of $400 in residential customer bill credits. Credits of $4.3 million were applied to customer bills under the City Council Cares Program.
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.
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
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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 opens 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 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 disagrees 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. Although the City Council evidentiary record has been lodged with the Civil District count, the court has not yet established a briefing schedule.
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 component of the proposed rules. Parties to the proceeding submitted initial comments in June 2019 and reply comments in July 2019. Entergy New Orleans recommended that the City Council adopt a voluntary clean energy standard of 70% of generation being clean energy by 2030, as so defined, which, 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 representatives of the solar and wind industry, are recommending mandatory, renewables-only requirements of up to 100% renewable resources by 2040. In September 2019 the City Council advisors issued a report and recommendations, which also put forth three alternative rules for comment from the parties. Comments were submitted in October 2019 and replies were filed in November 2019. In March 2020 the City Council’s Utility Committee recommended a resolution for approval by the City Council that directed the City Council advisors to work toward development of a rule for enacting a Renewable and Clean Portfolio Standard. The four components of the Renewable and Clean Portfolio Standard that the City Council expressed a desire to implement are: (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 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 plan year total utility retail sales revenues. The City Council adopted the Utility Committee resolution in April 2020. The first technical meeting of the parties occurred in June 2020; a second technical meeting occurred in July 2020. In August 2020 the City Council advisors issued a final draft of the rules for review and comment from the parties before final rules are proposed for consideration by the City Council. Entergy New Orleans filed comments in September and October 2020. In February 2021 the City Council amended the proposed draft rules to exclude beneficial electrification and carbon capture from the technologies eligible for credit under the Renewable and Clean Portfolio Standard and opened a 30-day comment period regarding the proposed amendments. Under the
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
rule, however, these technologies can be approved by the City Council as a “qualified measure” on a case-by-case basis. The City Council approved the draft rule, as amended, in May 2021. In January 2022 the City Council issued a resolution requiring the City of New Orleans and the Sewerage and Water Board use 100% renewable power. The resolution accelerates the City Council’s Renewable and Clean Portfolio Standard goal of 100% carbon neutral by 2040 and carbon free by 2050. The resolution directs Entergy New Orleans to work with the City of New Orleans and the Sewerage and Water Board to develop details related to the new goal.
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 April 2021. The report recommended that the City Council 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 inadvertent shedding of 105MW 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 audit.
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 study. In the press release, Entergy proposed four preliminary options for consideration by the City Council: merger of 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.
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
System Resiliency 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. Entergy New Orleans’s response is due March 1, 2022. In February 2022, Entergy New Orleans filed with the City Council a request for an extension of time to file its response, until July 1, 2022. The hearing officer set a briefing schedule and is expected to rule on the motion before the March 1, 2022 deadline.
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.
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
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.
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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 “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.
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 2022 Qualified Pension Cost Impact on 2021 Projected Qualified Benefit Obligation
Increase/(Decrease)
Discount rate (0.25%) $202 $5,196
Rate of return on plan assets (0.25%) $372 $-
Rate of increase in compensation 0.25% $225 $987
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 2022 Postretirement Benefit Cost Impact on 2021 Accumulated Postretirement Benefit Obligation
Increase/(Decrease)
Discount rate (0.25%) $68 $878
Health care cost trend 0.25% $80 $531
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 2021 was $9.9 million, including $5.4 million in settlement costs. Entergy New Orleans anticipates 2022 qualified pension cost to be $3 million. Entergy New Orleans contributed $5.4 million to its qualified pension plans in 2021 and estimates 2022 pension contributions will be approximately $922 thousand, although the 2022 required pension contributions will be known with more certainty when the January 1, 2022 valuations are completed, which is expected by April 1, 2022.
Total postretirement health care and life insurance benefit income for Entergy New Orleans in 2021 was $6.4 million. Entergy New Orleans expects 2022 postretirement health care and life insurance benefit income of approximately $6.7 million. Entergy New Orleans contributed $126 thousand to its other postretirement plans in 2021 and estimates 2022 contributions will be approximately $175 thousand.
Entergy New Orleans, 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.
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, 2021 and 2020, the related consolidated statements of income, cash flows, and changes in member’s equity (pages 395 through 400 and applicable items in pages 49 through 233), for each of the three years in the period ended December 31, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, 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 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, such as property, plant, and equipment; regulatory assets and liabilities; income taxes; operating revenues; operation and maintenance expense; and depreciation and amortization expense.
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, including major storm restoration costs, and refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the City Council and the FERC, involved especially subjective judgment and specialized knowledge of accounting for rate regulation and the rate setting process.
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 and other public utilities, regulatory statutes, interpretations, procedural memorandums, 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, including major storm restoration costs, 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, including major storm restoration costs, 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 25, 2022
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,
2021 2020 2019
(In Thousands)
OPERATING REVENUES
Electric $672,231 $560,632 $594,417
Natural gas 96,621 73,209 91,806
TOTAL 768,852 633,841 686,223
OPERATING EXPENSES
Operation and Maintenance:
Fuel, fuel-related expenses, and gas purchased for resale 150,018 76,781 105,217
Purchased power 268,568 243,572 258,306
Other operation and maintenance 145,377 125,756 121,057
Taxes other than income taxes 53,569 57,454 55,270
Depreciation and amortization 73,480 64,012 56,072
Other regulatory charges (credits) - net 13,177 1,854 21,616
TOTAL 704,189 569,429 617,538
OPERATING INCOME 64,663 64,412 68,685
OTHER INCOME
Allowance for equity funds used during construction 2,371 6,339 9,941
Interest and investment income 48 120 428
Miscellaneous - net (1,240) 316 (6,038)
TOTAL 1,179 6,775 4,331
INTEREST EXPENSE
Interest expense 29,164 29,105 24,463
Allowance for borrowed funds used during construction (1,056) (3,049) (4,262)
TOTAL 28,108 26,056 20,201
INCOME BEFORE INCOME TAXES 37,734 45,131 52,815
Income taxes 5,936 (4,207) 186
NET INCOME $31,798 $49,338 $52,629
See Notes to Financial Statements.
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ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
2021 2020 2019
(In Thousands)
OPERATING ACTIVITIES
Net income $31,798 $49,338 $52,629
Adjustments to reconcile net income to net cash flow provided by operating activities:
Depreciation and amortization 73,480 64,012 56,072
Deferred income taxes, investment tax credits, and non-current taxes accrued 12,573 3,938 21,350
Changes in assets and liabilities:
Receivables (42,612) (12,003) (9,372)
Fuel inventory (967) (58) (387)
Accounts payable 22,457 5,582 (5,571)
Taxes accrued (315) 398 234
Interest accrued (104) 1,179 550
Deferred fuel costs 9,737 (7,048) 3,630
Other working capital accounts (3,233) (13,156) 5,021
Provisions for estimated losses (83,569) 1,356 1,948
Other regulatory assets 18,173 (7,427) (29,567)
Other regulatory liabilities 4,985 (4,728) (22,105)
Pension and other postretirement liabilities (32,144) (14,063) (14,624)
Other assets and liabilities 68,549 (3,296) 55,796
Net cash flow provided by operating activities 78,808 64,024 115,604
INVESTING ACTIVITIES
Construction expenditures (220,284) (228,983) (229,560)
Allowance for equity funds used during construction 2,371 6,339 9,941
Payment for purchase of assets - (1,584) -
Changes in money pool receivable - net (36,410) 5,191 16,825
Payments to storm reserve escrow account (7) (433) (1,752)
Receipts from storm reserve escrow account 83,045 - -
Changes in securitization account 1,365 (1,375) 236
Net cash flow used in investing activities (169,920) (220,845) (204,310)
FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt 183,403 138,925 113,876
Retirement of long-term debt (36,873) (56,593) (35,376)
Repayment of long-term payable due to associated company (1,618) (1,838) (1,979)
Capital contributions from parent - 60,000 -
Changes in money pool payable - net (10,190) 10,190 -
Other (774) 146 (1,475)
Net cash flow provided by financing activities 133,948 150,830 75,046
Net increase (decrease) in cash and cash equivalents 42,836 (5,991) (13,660)
Cash and cash equivalents at beginning of period 26 6,017 19,677
Cash and cash equivalents at end of period $42,862 $26 $6,017
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized $28,009 $26,673 $22,873
Income taxes ($3,839) $3,392 ($5,310)
See Notes to Financial Statements.
ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31,
2021 2020
(In Thousands)
CURRENT ASSETS
Cash and cash equivalents
Cash $26 $26
Temporary cash investments 42,836 -
Total cash and cash equivalents 42,862 26
Securitization recovery trust account 1,999 3,364
Accounts receivable:
Customer 69,902 70,694
Allowance for doubtful accounts (13,282) (17,430)
Associated companies 74,146 2,381
Other 13,668 4,248
Accrued unbilled revenues 25,550 31,069
Total accounts receivable 169,984 90,962
Deferred fuel costs - 2,130
Fuel inventory - at average cost 2,945 1,978
Materials and supplies - at average cost 19,216 16,550
Prepayments and other 5,428 3,715
TOTAL 242,434 118,725
OTHER PROPERTY AND INVESTMENTS
Non-utility property at cost (less accumulated depreciation) 1,016 1,016
Storm reserve escrow account - 83,038
TOTAL 1,016 84,054
UTILITY PLANT
Electric 1,976,202 1,821,638
Natural gas 373,983 348,024
Construction work in progress 22,199 12,460
TOTAL UTILITY PLANT 2,372,384 2,182,122
Less - accumulated depreciation and amortization 774,309 740,796
UTILITY PLANT - NET 1,598,075 1,441,326
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Deferred fuel costs 4,080 4,080
Other regulatory assets (includes securitization property of $25,761 as of December 31, 2021 and $35,559 as of December 31, 2020)
248,617 266,790
Other 56,101 23,931
TOTAL 308,798 294,801
TOTAL ASSETS $2,150,323 $1,938,906
See Notes to Financial Statements.
ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
December 31,
2021 2020
(In Thousands)
CURRENT LIABILITIES
Payable due to associated company $1,326 $1,618
Accounts payable:
Associated companies 45,057 54,234
Other 146,921 60,766
Customer deposits 28,539 27,912
Taxes accrued 4,385 4,700
Interest accrued 7,991 8,095
Deferred fuel costs 7,607 -
Current portion of unprotected excess accumulated deferred income taxes 1,906 3,296
Other 6,204 5,462
TOTAL CURRENT LIABILITIES 249,936 166,083
NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued 365,384 338,714
Accumulated deferred investment tax credits 16,306 16,095
Regulatory liability for income taxes - net 40,589 55,675
Asset retirement cost liabilities 4,032 3,768
Accumulated provisions 6,329 89,898
Long-term debt (includes securitization bonds of $29,661 as of December 31, 2021 and $41,291 as of December 31, 2020)
777,254 629,704
Long-term payable due to associated company 9,585 10,911
Other 42,193 21,141
TOTAL NON-CURRENT LIABILITIES 1,261,672 1,165,906
Commitments and Contingencies
EQUITY
Member's equity 638,715 606,917
TOTAL 638,715 606,917
TOTAL LIABILITIES AND EQUITY $2,150,323 $1,938,906
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, 2021, 2020, and 2019
Member’s Equity
(In Thousands)
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
See Notes to Financial Statements.
ENTERGY TEXAS, INC. AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
2021 Compared to 2020
Net Income
Net income increased $13.8 million primarily due to higher retail electric price and higher volume/weather. The increase was partially offset by higher depreciation and amortization expenses, lower other income, higher other operation and maintenance expenses, higher taxes other than income taxes, and a higher effective income tax rate.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 2021 to 2020.
Amount
(In Millions)
2020 operating revenues $1,587.1
Fuel, rider, and other revenues that do not significantly affect net income 175.3
Retail electric price 123.2
Volume/weather 16.9
2021 operating revenues $1,902.5
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 retail electric price variance is primarily due to the implementation of the generation cost recovery rider, which includes the first-year revenue requirement for the Montgomery County Power Station, effective January 2021, an increase in the transmission cost recovery factor rider effective March 2021, and an increase in the distribution cost recovery factor rider effective March 2021. See Note 2 to the financial statements for further discussion of the generation cost recovery rider and transmission and distribution cost recovery factor rider filings.
The volume/weather variance is primarily due to an increase of 1,002 GWh, or 5%, in billed electricity usage, including an increase in industrial and commercial usage and the effect of more favorable weather on residential sales, partially offset by a decrease in weather-adjusted residential usage. The increase in industrial usage is primarily due to an increase in demand from expansion projects, primarily in the transportation and chemicals industries, and an increase in demand from cogeneration customers. The increase in commercial usage is primarily due to reduced impacts from the COVID-19 pandemic on businesses as compared to prior year. The decrease in weather-adjusted residential usage is primarily due to the impact that the COVID-19 pandemic had on prior year usage.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Billed electric energy sales for Entergy Texas for the years ended December 31, 2021 and 2020 are as follows:
2021 2020 % Change
(GWh)
Residential 6,201 6,146 1
Commercial 4,494 4,386 2
Industrial 8,729 7,885 11
Governmental 255 260 (2)
Total retail 19,679 18,677 5
Sales for resale:
Associated companies 1,364 1,203 13
Non-associated companies 1,008 810 24
Total 22,051 20,690 7
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 $15.4 million in non-nuclear generation expenses primarily due to higher expenses associated with the Montgomery County Power Station, which began commercial operation in January 2021, and a higher scope of work performed during outages in 2021 as compared to 2020;
•an increase of $4.3 million primarily due to an increase in contract costs related to customer solutions and sustainability initiatives, including customer service center support and enhanced customer billing;
•an increase of $4.2 million in distribution operations expenses primarily due to higher contractor costs and higher reliability costs;
•an increase of $4.1 million in compensation and benefits costs in 2021 primarily due to higher incentive-based compensation accruals in 2021 as compared to prior year, lower healthcare claims activity in 2020 as a result of the COVID-19 pandemic, an increase in healthcare cost rates, and an increase in net periodic pension and other postretirement benefits costs as a result of a decrease in the discount rate used to value the benefit liabilities. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs; and
•an increase of $2.1 million as a result of the amount of transmission costs allocated by MISO.
The increase was partially offset by a decrease of $5.2 million in meter reading expenses as a result of the deployment of advanced metering systems.
Taxes other than income taxes increased primarily due to an increase in ad valorem taxes, a sales tax audit assessment in 2021, and an increase in local franchise taxes. Ad valorem taxes increased as a result of higher assessments, primarily due to the addition of the Montgomery County Power Station. Local franchise taxes increased as a result of higher retail revenues in 2021 as compared to 2020.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including the Montgomery County Power Station, which was placed in service in January 2021.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Other income decreased primarily due to a decrease in the allowance for equity funds used during construction due to higher construction work in progress in 2020, including the Montgomery County Power Station project.
Interest expense increased primarily due to a decrease in the allowance for borrowed funds used during construction due to higher construction work in progress in 2020, including the Montgomery County Power Station project.
The effective income tax rates were 10% for 2021 and 1.4% for 2020. 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.
2020 Compared to 2019
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, 2020, filed with the SEC on February 26, 2021, for discussion of results of operations for 2020 compared to 2019.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2021, 2020, and 2019 were as follows:
2021 2020 2019
(In Thousands)
Cash and cash equivalents at beginning of period $248,596 $12,929 $56
Net cash provided by (used in):
Operating activities 356,933 375,325 286,739
Investing activities (647,271) (848,648) (878,280)
Financing activities 41,770 708,990 604,414
Net increase (decrease) in cash and cash equivalents (248,568) 235,667 12,873
Cash and cash equivalents at end of period $28 $248,596 $12,929
2021 Compared to 2020
Operating Activities
Net cash flow provided by operating activities decreased $18.4 million in 2021 primarily due to:
•increased fuel costs, including those related to Winter Storm Uri, and 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;
•the timing of payments to vendors; and
•an increase of $14.8 million in income taxes paid in 2021. The estimated income tax payments made in 2020 were offset by refunds received in accordance with an intercompany income tax allocation agreement.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
The decrease was offset by higher collections from customers and a decrease of approximately $13 million in storm spending in 2021, primarily due to increased spending on Hurricane Laura restoration efforts in 2020.
Investing Activities
Net cash flow used in investing activities decreased $201.4 million in 2021 primarily due to:
•a decrease of $128.8 million in non-nuclear generation construction expenditures primarily due to higher spending in 2020 on the Montgomery County Power Station project, partially offset by a higher scope of work performed during outages in 2021 as compared to 2020;
•a decrease of $94 million in transmission construction expenditures primarily due to a lower scope of work on projects performed in 2021 as compared to 2020; and
•the sale of a 7.56% partial interest in the Montgomery County Power Station in June 2021 for approximately $67.9 million. See Note 14 to the financial statements for further discussion of the transaction.
The decrease was partially offset by:
•an increase of $27.6 million in distribution construction expenditures primarily due to increased spending on the reliability and infrastructure of the distribution system and higher capital expenditures for storm restoration in 2021, partially offset by lower spending in 2021 on advanced metering infrastructure; and
•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.
Financing Activities
Net cash flow provided by financing activities decreased $667.2 million in 2021 primarily due to:
•the issuances of $175 million of 3.55% Series mortgage bonds in March 2020 and $600 million of 1.75% Series mortgage bonds in October 2020;
•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 2021; and
•capital contributions of $95 million received from Entergy Corporation in 2021 in order to maintain Entergy Texas’s capital structure and in anticipation of various upcoming capital expenditures as compared to a capital contribution of $175 million received from Entergy Corporation in 2020 in anticipation of upcoming expenditures, including Montgomery County Power Station.
The decrease was partially offset by:
•the repayment of $135 million of 5.625% Series mortgage bonds in November 2020;
•the issuance of $130 million of 1.50% Series mortgage bonds in August 2021;
•money pool activity; and
•the payment of $30 million of common stock dividends in 2020. No common stock dividends were paid in 2021 in order to maintain Entergy Texas’s capital structure.
Increases in Entergy Texas’s payable to the money pool are a source of cash flow, and Entergy Texas’s payable to the money pool increased $79.6 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.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
2020 Compared to 2019
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, 2020, filed with the SEC on February 26, 2021, for discussion of operating, investing, and financing cash flow activities for 2020 compared to 2019.
Capital Structure
Entergy Texas’s debt to capital ratio is shown in the following table. The decrease in the debt to capital ratio is primarily due to the net repayment of long-term debt in 2021 and the $95 million in capital contributions received from Entergy Corporation in 2021.
December 31,
2021 December 31,
Debt to capital 48.7 % 53.7 %
Effect of excluding securitization bonds (0.5 %) (1.3 %)
Debt to capital, excluding securitization bonds (a) 48.2 % 52.4 %
Effect of subtracting cash - % (2.7 %)
Net debt to net capital, excluding securitization bonds (a) 48.2 % 49.7 %
(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. 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, 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 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
•dividend and interest payments.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy Texas’s planned construction and other capital investments.
2022 2023 2024
(In Millions)
Planned construction and capital investment:
Generation $90 $195 $470
Transmission 110 180 195
Distribution 260 380 350
Utility Support 70 70 40
Total $530 $825 $1,055
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Texas includes generation projects to modernize, decarbonize, and diversify Entergy Texas’s portfolio, such as the 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, 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).
2022 2023 2024 2025-2026 After 2026
(In Millions)
Long-term debt (a) $133 $133 $77 $284 $3,088
Operating leases (b) $5 $4 $3 $3 $1
Finance leases (b) $2 $2 $1 $2 $1
(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 Texas expects to contribute approximately $1.9 million to its qualified pension plans and approximately $66 thousand to other postretirement health care and life insurance plans in 2022, although the 2022 required pension contributions will be known with more certainty when the January 1, 2022 valuations are completed, which is expected by April 1, 2022. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Entergy Texas has $11.6 million of 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, Entergy Texas enters into fuel and purchased power agreements that contain minimum purchase obligations. Entergy Texas has rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
As a subsidiary, Entergy Texas dividends its earnings to Entergy Corporation at a percentage determined monthly.
Liberty County Solar Facility
In September 2020, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to acquire the 100 MW Liberty County Solar Facility and a determination that Entergy Texas’s acquisition of the facility through a tax equity partnership is in the public interest. In its preliminary order, the PUCT determined that, in considering Entergy Texas’s application, it would not specifically address whether Entergy Texas’s use of a tax equity partnership is in the public interest. In March 2021 intervenors and PUCT staff filed testimony, and Entergy Texas filed rebuttal testimony in April 2021. A hearing on the merits was held in April 2021. In July 2021 the presiding ALJs issued a proposal for decision recommending that the PUCT deny the certification requested in the application. In October 2021 the PUCT issued an order adopting the ALJs’ proposal for decision and denying Entergy Texas’s application. Following review of the order and without receipt of required regulatory approval by the PUCT, Entergy Texas is not proceeding with the acquisition of the Liberty County Solar Facility. Entergy Texas recorded a write-off of $2.5 million in the fourth quarter of 2021 related to the Liberty County Solar Facility project.
Orange County Advanced Power Station
In 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 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. A hearing on the merits is scheduled for April 2022. A final order by the PUCT is expected in September 2022. Subject to receipt of required regulatory approvals and other conditions, the facility is expected to be in-service by May 2026.
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, 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 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 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 for the next twelve months and beyond.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Texas’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
2021 2020 2019 2018
(In Thousands)
($79,594) $4,601 $11,181 ($22,389)
See Note 4 to the financial statements for a description of the money pool.
Entergy Texas has a credit facility in the amount of $150 million scheduled to expire in June 2026. 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, 2021, there were no cash borrowings and $1.3 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, 2021, $79.6 million in letters of credit were outstanding under Entergy Texas’s 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 October 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 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.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
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, a governmental agency, is primarily responsible for approval of the rates charged to customers.
Filings with the PUCT and Texas Cities
2018 Rate Case
In May 2018, Entergy Texas filed a base rate case with the PUCT seeking an increase in base rates and rider rates of approximately $166 million, of which $48 million was associated with moving costs then being collected through riders into base rates such that the total incremental revenue requirement increase was approximately $118 million. The base rate case was based on a 12-month test year ending December 31, 2017. In addition, Entergy Texas included capital additions placed into service for the period of April 1, 2013 through December 31, 2017, as well as a post-test year adjustment to include capital additions placed in service by June 30, 2018.
In October 2018 the parties filed an unopposed settlement resolving all issues in the proceeding and a motion for interim rates effective for usage on and after October 17, 2018. The unopposed settlement reflected 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 were 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 provided 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 provided final resolution of all issues in the matter, including those related to the Tax Cuts and Jobs Act. In October 2018 the ALJ granted the unopposed motion for interim rates to be effective for service rendered on or after October 17, 2018. In December 2018 the PUCT issued an order approving the unopposed settlement.
Distribution Cost Recovery Factor (DCRF) Rider
In March 2019, Entergy Texas filed with the PUCT a request to set a new DCRF rider. The new DCRF rider was designed to collect approximately $3.2 million annually from Entergy Texas’s retail customers based on its capital invested in distribution between January 1, 2018 and December 31, 2018. In September 2019 the PUCT issued an order approving rates, which had been effective on an interim basis since June 2019, at the level proposed in Entergy Texas’s application.
In March 2020, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The 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 invested in distribution between January 1, 2019 and December 31, 2019. In May and June 2020 intervenors filed testimony recommending reductions in Entergy Texas’s annual revenue requirement of approximately $0.3 million and $4.1 million. The parties briefed the contested issues in this matter and a proposal for decision was issued in September 2020 recommending a $4.1 million revenue reduction related to non-advanced metering system meters included in the DCRF calculation. The parties filed exceptions to the proposal for decision and replies to
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
those exceptions in September 2020. In October 2020 the PUCT issued a final order approving a $16.3 million incremental annual DCRF revenue increase.
In October 2020, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The 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. In May 2021 the PUCT issued an order approving the settlement.
In August 2021, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The proposed rider is designed to collect from Entergy Texas’s retail customers approximately $40.2 million annually, or $13.9 million in incremental annual revenues beyond Entergy Texas’s currently 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 Administrative Hearings. A procedural schedule was established with a hearing scheduled in December 2021. In December 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, 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 PUCT to consider the settlement.
Transmission Cost Recovery Factor (TCRF) Rider
In December 2018, Entergy Texas filed with the PUCT a request to set a new TCRF rider. The new TCRF rider was designed to collect approximately $2.7 million annually from Entergy Texas’s retail customers based on its capital invested in transmission between January 1, 2018 and September 30, 2018. In April 2019 parties filed testimony proposing a load growth adjustment, which would fully offset Entergy Texas’s proposed TCRF revenue requirement. In July 2019 the PUCT granted Entergy Texas’s application as filed to begin recovery of the requested $2.7 million annual revenue requirement, rejecting opposing parties’ proposed adjustment; however, the PUCT found that the question of prudence of the actual investment costs should be determined in Entergy Texas’s next rate case similar to the procedure used for the costs recovered through the DCRF rider. In October 2019 the PUCT issued an order on a motion for rehearing, clarifying and affirming its prior order granting Entergy Texas’s application as filed. Also in October 2019 a second motion for rehearing was filed, and Entergy Texas filed a response in opposition to the motion. The second motion for rehearing was overruled by operation of law. In December 2019, Texas Industrial Energy Consumers filed an appeal to the PUCT order in district court alleging that the PUCT erred in declining to apply a load growth adjustment.
In August 2019, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The amended TCRF rider was designed to collect approximately $19.4 million annually from Entergy Texas’s retail customers based on its capital invested in transmission between January 1, 2018 and June 30, 2019, which is $16.7 million in incremental annual revenue above the $2.7 million approved in the prior pending TCRF proceeding. In January 2020 the PUCT issued an order approving an unopposed settlement providing for recovery of the requested revenue requirement. Entergy Texas implemented the amended rider beginning with bills covering usage on and after January 23, 2020.
In October 2020, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $51 million annually, or $31.6 million in incremental annual revenues beyond Entergy Texas’s then-effective TCRF rider based on its capital invested in transmission between July 1, 2019 and August 31, 2020. In March 2021 the parties filed an unopposed
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
settlement recommending that Entergy Texas be allowed to collect its full requested TCRF revenue requirement with interim rates effective March 2021 and resolving all issues in the proceeding. In March 2021 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 2021 the PUCT issued an order approving the settlement.
In October 2021, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The proposed rider is designed to collect from Entergy Texas’s retail customers approximately $66.1 million annually, or $15.1 million in incremental annual revenues beyond Energy Texas’s currently 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.
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. 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 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 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 December 2020, Entergy Texas also filed an application to amend its generation cost recovery rider to reflect its acquisition of the Hardin County Peaking Facility, which closed in June 2021. Because Hardin was to be acquired in the future, the initial generation cost recovery rider rates proposed in the application represented no change from the generation cost recovery rider rates established in Entergy Texas’s previous generation cost recovery rider proceeding. In July 2021 the PUCT issued an order approving the application. In August 2021, Entergy Texas filed an update application to recover its actual investment in the acquisition of the Hardin County Peaking Facility. 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
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
cost recovery rider settlement approved by the PUCT in January 2022. See Note 14 to the financial statements for further discussion of the Hardin County Peaking Facility purchase.
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 resumed disconnections for customers with past-due balances that have not made payment arrangements. As of December 31, 2021, Entergy Texas had a regulatory asset of $11.7 million for costs associated with the COVID-19 pandemic.
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. A fuel reconciliation is required to be filed at least once every three years and outside of a base rate case filing.
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.
In February 2021, Entergy Texas filed an application to implement a fuel refund for a cumulative over-recovery of approximately $75 million that is primarily attributable to settlements received by Entergy Texas from MISO related to Hurricane Laura. Entergy Texas planned to issue the refund over the period of March through August 2021. On February 22, 2021, Entergy Texas filed a motion to abate its fuel refund proceeding to assess how the February 2021 winter storm impacted Entergy Texas’s fuel over-recovery position. In March 2021, Entergy Texas withdrew its application to implement the fuel refund. Entergy Texas is continuing to evaluate its fuel balance and will file a subsequent refund or surcharge application consistent with the requirements of the PUCT’s rules.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
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.
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 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
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.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
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 “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.
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 2022 Qualified Pension Cost Impact on 2021 Qualified Projected Benefit Obligation
Increase/(Decrease)
Discount rate (0.25%) $363 $9,007
Rate of return on plan assets (0.25%) $727 $-
Rate of increase in compensation 0.25% $406 $1,797
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 2022 Postretirement Benefit Cost Impact on 2021 Accumulated Postretirement Benefit Obligation
Increase/(Decrease)
Discount rate (0.25%) $42 $2,067
Health care cost trend 0.25% $74 $1,370
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 2021 was $18.6 million, including $11.8 million in settlement costs. Entergy Texas anticipates 2022 qualified pension cost to be $5.7 million. Entergy Texas contributed $7 million to its qualified pension plans in 2021 and estimates 2022 pension contributions will be approximately $1.9 million, although the 2022 required pension contributions will be known with more certainty when the January 1, 2022 valuations are completed, which is expected by April 1, 2022.
Total postretirement health care and life insurance benefit income for Entergy Texas in 2021 was $10.9 million. Entergy Texas expects 2022 postretirement health care and life insurance benefit income to approximate $11.1 million. Entergy Texas contributed $98 thousand to its other postretirement plans in 2021 and estimates 2022 contributions will be approximately $66 thousand.
Entergy Texas, Inc. 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.
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, 2021 and 2020, the related consolidated statements of income, cash flows, and changes in common equity (pages 418 through 422 and applicable items in pages 49 through 233), for each of the three years in the period ended December 31, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, 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, such as property, plant, and equipment; regulatory assets and liabilities; income taxes; operating revenues; operation and maintenance expense; and depreciation and amortization expense.
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 especially subjective judgment and specialized knowledge of accounting for rate regulation and the rate setting process.
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 and other public utilities, regulatory statutes, interpretations, procedural memorandums, 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 25, 2022
We have served as the Company’s auditor since 2001.
ENTERGY TEXAS, INC. AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENTS
For the Years Ended December 31,
2021 2020 2019
(In Thousands)
OPERATING REVENUES
Electric $1,902,511 $1,587,125 $1,488,955
OPERATING EXPENSES
Operation and Maintenance:
Fuel, fuel-related expenses, and gas purchased for resale 335,742 238,428 162,544
Purchased power 588,941 510,633 602,563
Other operation and maintenance 281,713 250,170 258,924
Taxes other than income taxes 94,989 72,909 76,366
Depreciation and amortization 214,838 177,738 153,286
Other regulatory charges (credits) - net 59,581 90,398 88,770
TOTAL 1,575,804 1,340,276 1,342,453
OPERATING INCOME 326,707 246,849 146,502
OTHER INCOME
Allowance for equity funds used during construction 9,892 44,073 28,445
Interest and investment income 837 1,201 3,072
Miscellaneous - net 721 (28) 546
TOTAL 11,450 45,246 32,063
INTEREST EXPENSE
Interest expense 87,787 92,920 86,333
Allowance for borrowed funds used during construction (3,980) (18,940) (13,269)
TOTAL 83,807 73,980 73,064
INCOME BEFORE INCOME TAXES 254,350 218,115 105,501
Income taxes 25,526 3,042 (53,896)
NET INCOME 228,824 215,073 159,397
Preferred dividend requirements 1,909 1,882 580
EARNINGS APPLICABLE TO COMMON STOCK $226,915 $213,191 $158,817
See Notes to Financial Statements.
ENTERGY TEXAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
2021 2020 2019
(In Thousands)
OPERATING ACTIVITIES
Net income $228,824 $215,073 $159,397
Adjustments to reconcile net income to net cash flow provided by operating activities:
Depreciation and amortization 214,838 177,738 153,286
Deferred income taxes, investment tax credits, and non-current taxes accrued 48,813 36,033 20,143
Changes in assets and liabilities:
Receivables (16,455) (30,082) 58,445
Fuel inventory 10,819 (5,938) (4,926)
Accounts payable (5,718) (23,692) (33,646)
Prepaid taxes and taxes accrued (3,420) 2,730 (3,805)
Interest accrued (1,854) 1,864 (5,363)
Deferred fuel costs (133,636) 72,355 (6,696)
Other working capital accounts (12,105) (11,837) (13,822)
Provisions for estimated losses (140) 274 (5,748)
Other regulatory assets 103,380 (12,065) 85,400
Other regulatory liabilities (28,747) (57,477) (105,517)
Pension and other postretirement liabilities (42,502) (28,825) (7,152)
Other assets and liabilities (5,164) 39,174 (3,257)
Net cash flow provided by operating activities 356,933 375,325 286,739
INVESTING ACTIVITIES
Construction expenditures (702,754) (895,857) (898,090)
Allowance for equity funds used during construction 9,892 44,073 28,526
Proceeds from sale of assets 67,920 - -
Payment for purchase of assets (36,534) (4,931) -
Changes in money pool receivable - net 4,601 6,580 (11,181)
Changes in securitization account 9,604 1,487 2,465
Net cash flow used in investing activities (647,271) (848,648) (878,280)
FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt 127,931 937,725 986,019
Retirement of long-term debt (269,435) (367,565) (578,593)
Capital contributions from parent 95,000 175,000 185,000
Proceeds from the issuance of preferred stock 3,713 - 33,188
Changes in money pool payable - net 79,594 - (22,389)
Dividends paid:
Common stock - (30,000) -
Preferred stock (1,881) (2,064) -
Other 6,848 (4,106) 1,189
Net cash flow provided by financing activities 41,770 708,990 604,414
Net increase (decrease) in cash and cash equivalents (248,568) 235,667 12,873
Cash and cash equivalents at beginning of period 248,596 12,929 56
Cash and cash equivalents at end of period $28 $248,596 $12,929
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest - net of amount capitalized $87,094 $89,077 $89,402
Income taxes $17,594 $2,792 $17,010
See Notes to Financial Statements.
ENTERGY TEXAS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31,
2021 2020
(In Thousands)
CURRENT ASSETS
Cash and cash equivalents:
Cash $28 $26
Temporary cash investments - 248,570
Total cash and cash equivalents 28 248,596
Securitization recovery trust account 26,629 36,233
Accounts receivable:
Customer 83,797 103,221
Allowance for doubtful accounts (5,814) (16,810)
Associated companies 31,720 18,892
Other 13,404 11,780
Accrued unbilled revenues 62,241 56,411
Total accounts receivable 185,348 173,494
Deferred fuel costs 48,280 -
Fuel inventory - at average cost 42,712 53,531
Materials and supplies - at average cost 72,884 56,227
Prepayments and other 17,515 20,165
TOTAL 393,396 588,246
OTHER PROPERTY AND INVESTMENTS
Investments in affiliates - at equity 300 349
Non-utility property - at cost (less accumulated depreciation) 376 376
Other 18,128 19,889
TOTAL 18,804 20,614
UTILITY PLANT
Electric 7,181,567 6,007,687
Construction work in progress 183,965 879,908
TOTAL UTILITY PLANT 7,365,532 6,887,595
Less - accumulated depreciation and amortization 2,049,750 1,864,494
UTILITY PLANT - NET 5,315,782 5,023,101
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Other regulatory assets (includes securitization property of $23,818 as of December 31, 2021 and $78,590 as of December 31, 2020)
421,333 524,713
Other 112,096 70,397
TOTAL 533,429 595,110
TOTAL ASSETS $6,261,411 $6,227,071
See Notes to Financial Statements.
ENTERGY TEXAS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
December 31,
2021 2020
(In Thousands)
CURRENT LIABILITIES
Currently maturing long-term debt $- $200,000
Accounts payable:
Associated companies 142,929 55,944
Other 164,981 350,947
Customer deposits 37,271 36,282
Taxes accrued 49,018 52,438
Interest accrued 19,002 20,856
Current portion of unprotected excess accumulated deferred income taxes 27,188 29,249
Deferred fuel costs - 85,356
Other 16,120 12,370
TOTAL 456,509 843,442
NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued 692,496 639,422
Accumulated deferred investment tax credits 9,325 9,942
Regulatory liability for income taxes - net 144,145 175,594
Other regulatory liabilities 37,060 32,297
Asset retirement cost liabilities 8,520 8,063
Accumulated provisions 8,242 8,382
Long-term debt (includes securitization bonds of $53,979 as of December 31, 2021 and $123,066 as of December 31, 2020)
2,354,148 2,293,708
Other 67,760 58,643
TOTAL 3,321,696 3,226,051
Commitments and Contingencies
EQUITY
Common stock, no par value, authorized 200,000,000 shares; issued and outstanding 46,525,000 shares in 2021 and 2020
49,452 49,452
Paid-in capital 1,050,125 955,162
Retained earnings 1,344,879 1,117,964
Total common shareholder's equity 2,444,456 2,122,578
Preferred stock without sinking fund 38,750 35,000
TOTAL 2,483,206 2,157,578
TOTAL LIABILITIES AND EQUITY $6,261,411 $6,227,071
See Notes to Financial Statements.
ENTERGY TEXAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Years Ended December 31, 2021, 2020, and 2019
Common Equity
Preferred Stock Common Stock Paid-in Capital Retained Earnings Total
(In Thousands)
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
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
See Notes to Financial Statements.
SYSTEM ENERGY RESOURCES, INC.
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
System Energy’s principal asset 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, and the rates it charges under the Unit Power Sales Agreement.
Results of Operations
2021 Compared to 2020
Net Income
Net income increased $7.7 million primarily due to the increase in operating revenues resulting from changes in rate base and due to a provision for rate refund recorded in 2020 to reflect a one-time credit of $25.2 million provided for in the Federal Power Act section 205 filing made by System Energy in December 2020. See “Complaints Against System Energy” below for further discussion of these items and other proceedings involving System Energy at the FERC. The one-time credit is discussed in the Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue part of that section. The return on equity complaint is discussed in the Return on Equity and Capital Structure Complaints part of that section.
Income Taxes
The effective income tax rates were (1.9%) for 2021 and 17.2% for 2020. 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.
2020 Compared to 2019
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, 2020, filed with the SEC on February 26, 2021, for discussion of results of operations for 2020 compared to 2019.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2021, 2020, and 2019 were as follows:
2021 2020 2019
(In Thousands)
Cash and cash equivalents at beginning of period $242,469 $68,534 $95,685
Net cash provided by (used in):
Operating activities 201,211 (145,462) 300,141
Investing activities (193,392) (206,443) (119,553)
Financing activities (161,087) 525,840 (207,739)
Net increase (decrease) in cash and cash equivalents (153,268) 173,935 (27,151)
Cash and cash equivalents at end of period $89,201 $242,469 $68,534
2021 Compared to 2020
Operating Activities
System Energy’s operating activities provided $201.2 million of cash in 2021 compared to using $145.5 million of cash in 2020 primarily due to a decrease of $329.4 million in income taxes paid in 2021 and a decrease in spending of $35.9 million on nuclear refueling outage costs in 2021 as compared to prior year, partially offset by proceeds of $35 million received in December 2020 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed. 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. System Energy made income tax payments of $384.3 million in 2020 in accordance with an intercompany income tax allocation agreement. The 2020 income tax payments are primarily related to the resolution of the 2014-2015 IRS audit regarding the treatment of nuclear decommissioning costs included in cost of goods sold, which is discussed in Note 3 to the financial statements in “Tax Accounting Methods.” See Note 8 to the financial statements for a discussion of the spent nuclear fuel litigation.
Investing Activities
Net cash flow used in investing activities decreased by $13.1 million in 2021 primarily due to:
•a decrease of $100.8 million in nuclear construction expenditures as a result of spending in 2020 on Grand Gulf outage projects and upgrades; and
•a decrease of $45.7 million as a result of fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle.
The decrease was partially offset by money pool activity.
Increases in System Energy’s receivable from the money pool are a use of cash flow and System Energy’s receivable from the money pool increased by $71.7 million in 2021 compared to decreasing by $55.3 million in 2020. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
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Management’s Financial Discussion and Analysis
Financing Activities
System Energy’s financing activities used $161.1 million of cash in 2021 compared to providing $525.8 million of cash in 2020 primarily due to the following activity:
•a $350 million capital contribution from Entergy Corporation in 2020 in order to maintain System Energy’s capital structure in conjunction with the 2020 tax payments discussed above in “Operating Activities”;
•the issuance in December 2020 of $200 million of 2.14% Series mortgage bonds;
•the issuance in October 2020 of $90 million of 2.05% Series K notes by the System Energy nuclear fuel company variable interest entity;
•the repayment in February 2021 of $100 million of 3.42% Series J notes by the System Energy nuclear fuel company variable interest entity; and
•net borrowings of $36.1 million of long-term borrowings in 2021 compared to net repayments of $31.6 million of long-term borrowings in 2020 on the nuclear fuel company variable interest entity’s credit facility.
See Note 5 to the financial statements for additional details of long-term debt.
2020 Compared to 2019
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, 2020, filed with the SEC on February 26, 2021, for discussion of operating, investing, and financing cash flow activities for 2020 compared to 2019.
Capital Structure
System Energy’s debt to capital ratio is shown in the following table. The decrease in the debt to capital ratio is primarily due to the net repayment of long-term debt in 2021.
December 31,
2021 December 31,
Debt to capital 40.4 % 42.7 %
Effect of subtracting cash (3.0 %) (8.5 %)
Net debt to net capital 37.4 % 34.2 %
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. 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 a capital distribution, 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, System Energy may issue incremental debt or reduce
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dividends, or both, to maintain its capital structure. In addition, System Energy may receive equity contributions to maintain its capital structure for certain circumstances that would materially alter the capital structure if financed entirely with debt and reduced dividends.
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 and tax payments; and
•dividend, distribution, and interest payments.
Following are the amounts of System Energy’s planned construction and other capital investments.
2022 2023 2024
(In Millions)
Planned construction and capital investment:
Generation $140 $135 $180
Utility Support 20 20 15
Total $160 $155 $195
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 obligations (includes estimated interest payments).
2022 2023 2024 2025-2026 After 2026
(In Millions)
Long-term debt (a) $87 $314 $25 $246 $381
(a)Long-term debt is discussed in Note 5 to the financial statements.
Other Obligations
System Energy expects to contribute approximately $12.8 million to its qualified pension plans and approximately $22 thousand to other postretirement health care and life insurance plans in 2022, although the 2022 required pension contributions will be known with more certainty when the January 1, 2022 valuations are completed, which is expected by April 1, 2022. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
System Energy has $14.8 million of 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 the financial statements, System Energy recovers these costs through charges under the Unit Power Sales Agreement.
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Management’s Financial Discussion and Analysis
As a wholly-owned subsidiary, System Energy dividends its earnings to Entergy Corporation at a percentage determined monthly.
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, 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 expects to continue, when economically feasible, to retire higher-cost debt and replace it with lower-cost debt if market conditions 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 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.
2021 2020 2019 2018
(In Thousands)
$75,745 $4,004 $59,298 $107,122
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 June 2024. As of December 31, 2021, $36.1 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 October 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; 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.
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Management’s Financial Discussion and Analysis
Complaints Against System Energy
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, Entergy Mississippi, and Entergy New Orleans under separate agreements. The current return on equity under the Unit Power Sales Agreement is 10.94%, which was established in a rate proceeding that became final in July 2001.
The APSC and MPSC complaint alleges that the return on equity is unjust and unreasonable because capital market and other considerations indicate that it is excessive. The complaint requests proceedings to investigate the return on equity and establish a lower return on equity, and also requests that the FERC establish January 23, 2017 as a refund effective date. The complaint includes return on equity analysis that purports to establish that the range of reasonable return on equity for System Energy is between 8.37% and 8.67%. System Energy answered the complaint in February 2017 and disputes that a return on equity of 8.37% to 8.67% is just and reasonable. The LPSC and the City Council intervened in the proceeding expressing support for the complaint. In September 2017 the FERC established a refund effective date of January 23, 2017 and directed the parties to engage in settlement proceedings before an ALJ. The parties were unable to settle the return on equity issue and a FERC hearing judge was assigned in July 2018. The 15-month refund period in connection with the APSC/MPSC complaint expired on April 23, 2018.
In April 2018 the LPSC filed a complaint with the FERC against System Energy seeking an additional 15-month refund period. The LPSC complaint requests similar relief from the FERC with respect to System Energy’s return on equity and also requests the FERC to investigate System Energy’s capital structure. The APSC, MPSC, and City Council intervened in the proceeding, filed an answer expressing support for the complaint, and asked the FERC to consolidate this proceeding with the proceeding initiated by the complaint of the APSC and MPSC in January 2017. System Energy answered the LPSC complaint in May 2018 and also filed a motion to dismiss the complaint. In August 2018 the FERC issued an order dismissing the LPSC’s request to investigate System Energy’s capital structure and setting for hearing the return on equity complaint, with a refund effective date of April 27, 2018. The 15-month refund period in connection with the LPSC return on equity complaint expired on July 26, 2019.
The portion of the LPSC’s complaint dealing with return on equity was subsequently consolidated with the APSC and MPSC complaint for hearing. The parties addressed an order (issued in a separate FERC proceeding involving New England transmission owners) that proposed modifying the FERC’s standard methodology for determining return on equity. In September 2018, System Energy filed a request for rehearing and the LPSC filed a request for rehearing or reconsideration of the FERC’s August 2018 order. The LPSC’s request referenced an amended complaint that it filed on the same day raising the same capital structure claim the FERC had earlier dismissed. The FERC initiated a new proceeding for the amended capital structure complaint, and System Energy submitted a response in October 2018. In January 2019 the FERC set the amended complaint for settlement and
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hearing proceedings. Settlement proceedings in the capital structure proceeding commenced in February 2019. As noted below, in June 2019 settlement discussions were terminated and the amended capital structure complaint was consolidated with the ongoing return on equity proceeding. The 15-month refund period in connection with the capital structure complaint was from September 24, 2018 to December 23, 2019.
In January 2019 the LPSC and the APSC and MPSC filed direct testimony in the return on equity proceeding. For the refund period January 23, 2017 through April 23, 2018, the LPSC argues for an authorized return on equity for System Energy of 7.81% and the APSC and MPSC argue for an authorized return on equity for System Energy of 8.24%. For the refund period April 27, 2018 through July 27, 2019, and for application on a prospective basis, the LPSC argues for an authorized return on equity for System Energy of 7.97% and the APSC and MPSC argue for an authorized return on equity for System Energy of 8.41%. In March 2019, System Energy submitted answering testimony. For the first refund period, System Energy’s testimony argues for a return on equity of 10.10% (median) or 10.70% (midpoint). For the second refund period, System Energy’s testimony shows that the calculated returns on equity for the first period fall within the range of presumptively just and reasonable returns on equity, and thus the second complaint should be dismissed (and the first period return on equity used going forward). If the FERC nonetheless were to set a new return on equity for the second period (and going forward), System Energy argues the return on equity should be either 10.32% (median) or 10.69% (midpoint).
In May 2019 the FERC trial staff filed its direct and answering testimony in the return on equity proceeding. For the first refund period, the FERC trial staff calculates an authorized return on equity for System Energy of 9.89% based on the application of FERC’s proposed methodology. The FERC trial staff’s direct and answering testimony noted that an authorized return on equity of 9.89% for the first refund period was within the range of presumptively just and reasonable returns on equity for the second refund period, as calculated using a study period ending January 31, 2019 for the second refund period.
In June 2019, System Energy filed testimony responding to the testimony filed by the FERC trial staff. Among other things, System Energy’s testimony rebutted arguments raised by the FERC trial staff and provided updated calculations for the second refund period based on the study period ending May 31, 2019. For that refund period, System Energy’s testimony shows that strict application of the return on equity methodology proposed by the FERC staff indicates that the second complaint would not be dismissed, and the new return on equity would be set at 9.65% (median) or 9.74% (midpoint). System Energy’s testimony argues that these results are insufficient in light of benchmarks such as state returns on equity and treasury bond yields, and instead proposes that the calculated returns on equity for the second period should be either 9.91% (median) or 10.3% (midpoint). System Energy’s testimony also argues that, under application of its proposed modified methodology, the 10.10% return on equity calculated for the first refund period would fall within the range of presumptively just and reasonable returns on equity for the second refund period.
Also in June 2019, the FERC’s Chief ALJ issued an order terminating settlement discussions in the amended complaint addressing System Energy’s capital structure. The ALJ consolidated the amended capital structure complaint with the ongoing return on equity proceeding and set new procedural deadlines for the consolidated hearing.
In August 2019 the LPSC and the APSC and MPSC filed rebuttal testimony in the return on equity proceeding and direct and answering testimony relating to System Energy’s capital structure. The LPSC re-argues for an authorized return on equity for System Energy of 7.81% for the first refund period and 7.97% for the second refund period. The APSC and MPSC argue for an authorized return on equity for System Energy of 8.26% for the first refund period and 8.32% for the second refund period. With respect to capital structure, the LPSC proposes that the FERC establish a hypothetical capital structure for System Energy for ratemaking purposes. Specifically, the LPSC proposes that System Energy’s common equity ratio be set to Entergy Corporation’s equity ratio of 37% equity and 63% debt. In the alternative, the LPSC argues that the equity ratio should be no higher than 49%, the composite equity ratio of System Energy and the other Entergy operating companies who purchase under the Unit Power Sales Agreement. The APSC and MPSC recommend that 35.98% be set as the common equity ratio for
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System Energy. As an alternative, the APSC and MPSC propose that System Energy’s common equity be set at 46.75% based on the median equity ratio of the proxy group for setting the return on equity.
In September 2019 the FERC trial staff filed its rebuttal testimony in the return on equity proceeding. For the first refund period, the FERC trial staff calculates an authorized return on equity for System Energy of 9.40% based on the application of the FERC’s proposed methodology and an updated proxy group. For the second refund period, based on the study period ending May 31, 2019, the FERC trial staff rebuttal testimony argues for a return on equity of 9.63%. In September 2019 the FERC trial staff also filed direct and answering testimony relating to System Energy’s capital structure. The FERC trial staff argues that the average capital structure of the proxy group used to develop System Energy’s return on equity should be used to establish the capital structure. Using this approach, the FERC trial staff calculates the average capital structure for its proposed proxy group of 46.74% common equity, and 53.26% debt.
In October 2019, System Energy filed answering testimony disputing the FERC trial staff’s, the LPSC’s, and the APSC’s and MPSC’s arguments for the use of a hypothetical capital structure and arguing that the use of System Energy’s actual capital structure is just and reasonable.
In November 2019, in a proceeding that did not involve System Energy, the FERC issued an order addressing the methodology for determining the return on equity applicable to transmission owners in MISO. Thereafter, the procedural schedule in the System Energy proceeding was amended to allow the participants to file supplemental testimony addressing the order in the MISO transmission owner proceeding (Opinion No. 569).
In February 2020 the LPSC, the MPSC and APSC, and the FERC trial staff filed supplemental testimony addressing Opinion No. 569 and how it would affect the return on equity evaluation for the two complaint periods concerning System Energy. For the first refund period, based on their respective interpretations and applications of the Opinion No. 569 methodology, the LPSC argues for an authorized return on equity for System Energy of 8.44%; the MPSC and APSC argue for an authorized return on equity of 8.41%; and the FERC trial staff argues for an authorized return on equity of 9.22%. For the second refund period and on a prospective basis, based on their respective interpretations and applications of the Opinion No. 569 methodology, the LPSC argues for an authorized return on equity for System Energy of 7.89%; the MPSC and APSC argue that an authorized return on equity of 8.01% may be appropriate; and the FERC trial staff argues for an authorized return on equity of 8.66%.
In April 2020, System Energy filed supplemental answering testimony addressing Opinion No. 569. System Energy argues that the Opinion No. 569 methodology is conceptually and analytically defective for purposes of establishing just and reasonable authorized return on equity determinations and proposes an alternative approach. As its primary recommendation, System Energy continues to support the return on equity determinations in its March 2019 testimony for the first refund period and its June 2019 testimony for the second refund period. Under the Opinion No. 569 methodology, System Energy calculates a “presumptively just and reasonable range” for the authorized return on equity for the first refund period of 8.57% to 9.52%, and for the second refund period of 8.28% to 9.11%. System Energy argues that these ranges are not just and reasonable results. Under its proposed alternative methodology, System Energy calculates an authorized return on equity of 10.26% for the first refund period, which also falls within the presumptively just and reasonable range calculated for the second refund period and prospectively.
In May 2020 the FERC issued an order on rehearing of Opinion No. 569 (Opinion No. 569-A). In June 2020 the procedural schedule in the System Energy proceeding was further revised in order to allow parties to address the Opinion No. 569-A methodology. Pursuant to the revised schedule, in June 2020, the LPSC, MPSC and APSC, and the FERC trial staff filed supplemental testimony addressing Opinion No. 569-A and how it would affect the return on equity evaluation for the two complaint periods concerning System Energy. For the first refund period, based on their respective interpretations and applications of the Opinion No. 569-A methodology, the LPSC argues for an authorized return on equity for System Energy of 7.97%; the MPSC and APSC argue for an authorized return on equity of 9.24%; and the FERC trial staff argues for an authorized return on equity of 9.49%. For the
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second refund period and on a prospective basis, based on their respective interpretations and applications of the Opinion No. 569-A methodology, the LPSC argues for an authorized return on equity for System Energy of 7.78%; the MPSC and APSC argue that an authorized return on equity of 9.15% may be appropriate if the second complaint is not dismissed; and the FERC trial staff argues for an authorized return on equity of 9.09% if the second complaint is not dismissed.
Pursuant to the revised procedural schedule, in July 2020, System Energy filed supplemental testimony addressing Opinion No. 569-A. System Energy argues that strict application of the Opinion No. 569-A methodology produces results inconsistent with investor requirements and does not provide a sound basis on which to evaluate System Energy’s authorized return on equity. As its primary recommendation, System Energy argues for the use of a methodology that incorporates four separate financial models, including the constant growth form of the discounted cash flow model and the empirical capital asset pricing model. Based on application of its recommended methodology, System Energy argues for an authorized return on equity of 10.12% for the first refund period, which also falls within the presumptively just and reasonable range calculated for the second refund period and prospectively. Under the Opinion No. 569-A methodology, System Energy calculates an authorized return on equity of 9.44% for the first refund period, which also falls within the presumptively just and reasonable range calculated for the second refund period and prospectively.
The parties and FERC trial staff filed final rounds of testimony in August 2020. The hearing before a FERC ALJ occurred in late-September through early-October 2020, post-hearing briefing took place in November and December 2020.
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 $60 million, which includes interest through December 31, 2021, and the estimated resulting annual rate reduction would be approximately $45 million. The estimated refund will continue to accrue interest until a final FERC decision is issued. Based on the course of the proceeding to date, System Energy has recorded a provision of $37 million, including interest, as of December 31, 2021.
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.
Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue
In May 2018 the LPSC filed a complaint against System Energy and Entergy Services related to System Energy’s renewal of a sale-leaseback transaction originally entered into in December 1988 for an 11.5% undivided interest in Grand Gulf Unit 1. The complaint alleges that System Energy violated the filed rate and the FERC’s
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Management’s Financial Discussion and Analysis
ratemaking and accounting requirements when it included in Unit Power Sales Agreement billings the cost of capital additions associated with the sale-leaseback interest, and that System Energy is double-recovering costs by including both the lease payments and the capital additions in Unit Power Sales Agreement billings. The complaint also claims that System Energy was imprudent in entering into the sale-leaseback renewal because the Utility operating companies that purchase Grand Gulf’s output from System Energy could have obtained cheaper capacity and energy in the MISO markets. The complaint further alleges that System Energy violated various other reporting and accounting requirements and should have sought prior FERC approval of the lease renewal. The complaint seeks various forms of relief from the FERC. The complaint seeks refunds for capital addition costs for all years in which they were recorded in allegedly non-formula accounts or, alternatively, the disallowance of the return on equity for the capital additions in those years plus interest. The complaint also asks that the FERC disallow and refund the lease costs of the sale-leaseback renewal on grounds of imprudence, investigate System Energy’s treatment of a DOE litigation payment, and impose certain forward-looking procedural protections, including audit rights for retail regulators of the Unit Power Sales Agreement formula rates. The APSC, MPSC, and City Council intervened in the proceeding.
In June 2018, System Energy and Entergy Services filed a motion to dismiss and an answer to the LPSC complaint denying that System Energy’s treatment of the sale-leaseback renewal and capital additions violated the terms of the filed rate or any other FERC ratemaking, accounting, or legal requirements or otherwise constituted double recovery. The response also argued that the complaint is inconsistent with a FERC-approved settlement to which the LPSC is a party and that explicitly authorizes System Energy to recover its lease payments. Finally, the response argued that both the capital additions and the sale-leaseback renewal were prudent investments and the LPSC complaint fails to justify any disallowance or refunds. The response also offered to submit formula rate protocols for the Unit Power Sales Agreement similar to the procedures used for reviewing transmission rates under the MISO tariff. In September 2018 the FERC issued an order setting the complaint for hearing and settlement proceedings. The FERC established a refund effective date of May 18, 2018.
In February 2019 the presiding ALJ ruled that the hearing ordered by the FERC includes the issue of whether specific subcategories of accumulated deferred income tax should be included in, or excluded from, System Energy’s formula rate. In March 2019 the LPSC, MPSC, APSC and City Council filed direct testimony. The LPSC testimony sought refunds that include the renewal lease payments (approximately $17.2 million per year since July 2015), rate base reductions for accumulated deferred income tax associated with uncertain tax positions, and the cost of capital additions associated with the sale-leaseback interest, as well as interest on those amounts.
In June 2019 System Energy filed answering testimony arguing that the FERC should reject all claims for refunds. Among other things, System Energy argued that claims for refunds of the costs of lease renewal payments and capital additions should be rejected because those costs were recovered consistent with the Unit Power Sales Agreement formula rate, System Energy was not over or double recovering any costs, and ratepayers will save costs over the initial and renewal terms of the leases. System Energy argued that claims for refunds associated with liabilities arising from uncertain tax positions should be rejected because the liabilities do not provide cost-free capital, the repayment timing of the liabilities is uncertain, and the outcome of the underlying tax positions is uncertain. System Energy’s testimony also challenged the refund calculations supplied by the other parties.
In August 2019 the FERC trial staff filed direct and answering testimony seeking refunds for rate base reductions for liabilities associated with uncertain tax positions. The FERC trial staff also argued that System Energy recovered $32 million more than it should have in depreciation expense for capital additions. In September 2019, System Energy filed cross-answering testimony disputing the FERC trial staff’s arguments for refunds, stating that the FERC trial staff’s position regarding depreciation rates for capital additions is not unreasonable, but explaining that any change in depreciation expense is only one element of a Unit Power Sales Agreement re-billing calculation. Adjustments to depreciation expense in any re-billing under the Unit Power Sales Agreement formula rate will also involve changes to accumulated depreciation, accumulated deferred income taxes, and other formula elements as needed. In October 2019 the LPSC filed rebuttal testimony increasing the amount of refunds sought for liabilities associated with uncertain tax positions. The LPSC seeks approximately $512 million plus interest, which
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is approximately $216 million through December 31, 2021. The FERC trial staff also filed rebuttal testimony in which it seeks refunds of a similar amount as the LPSC for the liabilities associated with uncertain tax positions. The LPSC testimony also argued that adjustments to depreciation rates should affect rate base on a prospective basis only.
A hearing was held before a FERC ALJ in November 2019. In April 2020 the ALJ issued 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. If the ALJ’s initial decision is upheld, the estimated refund for this issue through December 31, 2021, is approximately $422 million, plus interest, which is approximately $128 million through December 31, 2021. The ALJ also found that System Energy should include liabilities associated with uncertain tax positions as a rate base reduction going forward. Third, with regard to the depreciation expense adjustments, the ALJ found that System Energy should correct for the error in re-billings retroactively and prospectively, but that System Energy should not be permitted to recover interest on any retroactive return on enhanced rate base resulting from such corrections. If the initial decision is affirmed on this issue, System Energy estimates refunds of approximately $19 million, which includes interest through December 31, 2021.
The ALJ initial decision is an interim step in the FERC litigation process, and an ALJ’s determinations made in an initial decision are not controlling on the FERC. The ALJ in the initial decision acknowledges that these are issues of first impression before the FERC. In June 2020, System Energy, the LPSC, and the FERC trial staff filed briefs on exceptions, challenging several of the initial decision’s findings. System Energy’s brief on exceptions challenged the initial decision’s limitations on recovery of the lease renewal payments, its proposed rate base refund for the liabilities associated with uncertain tax positions, and its proposal to asymmetrically treat interest on bill corrections for depreciation expense adjustments. The LPSC’s and the FERC trial staff’s briefs on exceptions each challenged the initial decision’s allowance for recovery of the cost of service associated with the lease renewal based on the remaining net book value of the leased assets, its calculation of the remaining net book value of the leased assets, and the amount of the initial decision’s proposed rate base refund for the liabilities associated with uncertain tax positions. The LPSC’s brief on exceptions also challenged the initial decision’s proposal that depreciation expense adjustments include retroactive adjustments to rate base and its finding that section 203 of the Federal Power Act did not apply to the lease renewal. The FERC trial staff’s brief on exceptions also challenged the initial decision’s finding that the FERC need not institute a formal investigation into System Energy’s tariff. In October 2020, System Energy, the LPSC, the MPSC, the APSC, and the City Council filed briefs opposing exceptions. System Energy opposed the exceptions filed by the LPSC and the FERC trial staff. The LPSC, MPSC, APSC, City Council, and the FERC trial staff opposed the exceptions filed by System Energy. Also in October 2020 the MPSC, APSC, and the City Council filed briefs adopting the exceptions of the LPSC and the FERC trial staff. The case is pending before the FERC, which will review the case and issue an order on the proceeding, and the FERC may accept, reject, or modify the ALJ’s initial decision in whole or in part. Refunds, if any, that might be required will only become due after the FERC issues its order reviewing the initial decision.
In addition, in September 2020, the IRS issued a Notice of Proposed Adjustment (NOPA) and Entergy executed it. The NOPA memorializes the IRS’s decision to adjust the 2015 consolidated federal income tax return of Entergy Corporation and certain of its subsidiaries, including System Energy, with regard to the uncertain decommissioning tax position. Pursuant to the audit resolution documented in the NOPA, the IRS allowed System
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
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.
LPSC Authorization of Additional Complaints
In May 2020 the LPSC authorized its staff to file additional complaints at the FERC related to the rates charged by System Energy for Grand Gulf energy and capacity supplied to Entergy Louisiana under the Unit Power Sales Agreement. The LPSC directive notes that the initial decision issued by the presiding ALJ in the Grand Gulf sale-leaseback complaint proceeding did not address, for procedural reasons, certain rate issues raised by the LPSC and declined to order further investigation of rates charged by System Energy. The LPSC directive authorizes its staff to file complaints at the FERC “necessary to address these rate issues, to request a full investigation into the rates charged by System Energy for Grand Gulf power, and to seek rate refund, rate reduction, and such other remedies as may be necessary and appropriate to protect Louisiana ratepayers.” The LPSC directive further stated that the LPSC has seen “information suggesting that the Grand Gulf plant has been significantly underperforming compared to other nuclear plants in the United States, has had several extended and unexplained outages, and has been plagued with serious safety concerns.” The LPSC expressed concern that the costs paid by Entergy Louisiana's retail customers may have been detrimentally impacted, and authorized “the filing of a FERC complaint to address these performance issues and to seek appropriate refund, rate reduction, and other remedies as may be appropriate.”
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
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 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. A procedural schedule was established, with the hearing scheduled for June 2022 and the ALJ’s initial decision scheduled for November 2022. Discovery is ongoing.
In November 2021 the LPSC, APSC, and 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
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
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 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.
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
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
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 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 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. The pleadings are pending FERC action.
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 Grand Gulf to meet its operational 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; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license renewal and 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 the 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 required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. Grand Gulf’s operating license expires in 2044.
In March 2021 the NRC placed Grand Gulf in Column 3 based on the incidence of five unplanned plant scrams during calendar year 2020, some of which were related to upgrades made to the plant’s turbine control system during the spring 2020 refueling outage. The NRC conducted a supplemental inspection of Grand Gulf in accordance with its inspection procedures for nuclear plants in Column 3 and, in October 2021, notified Entergy that all inspection objectives were met. The NRC issued its report in November 2021 and Grand Gulf was returned to Column 1.
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
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
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
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
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 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.
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 2022 Qualified Pension Cost Impact on 2021 Projected Qualified Benefit Obligation
Increase/(Decrease)
Discount rate (0.25%) $483 $10,885
Rate of return on plan assets (0.25%) $685 $-
Rate of increase in compensation 0.25% $464 $1,952
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
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 2022 Postretirement Benefit Cost Impact on 2021 Accumulated Postretirement Benefit Obligation
Increase/(Decrease)
Discount rate (0.25%) $50 $1,591
Health care cost trend 0.25% $69 $1,132
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 2021 was $29.3 million, including $12.3 million in settlement costs. System Energy anticipates 2022 qualified pension cost to be $12.1 million. System Energy contributed $18.7 million to its qualified pension plans in 2021 and estimates 2022 pension contributions will approximate $12.8 million, although the 2022 required pension contributions will be known with more certainty when the January 1, 2022 valuations are completed, which is expected by April 1, 2022.
Total postretirement health care and life insurance benefit income for System Energy in 2021 was $1.3 million. System Energy expects 2022 postretirement health care and life insurance benefit income to approximate $1 million. System Energy contributed $1.2 million to its other postretirement plans in 2021 and expects 2022 contributions to approximate $22 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 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, 2021 and 2020, the related statements of income, cash flows, and changes in common equity (pages 442 through 446 and applicable items in pages 49 through 233), for each of the three years in the period ended December 31, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, 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 Notes 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, such as property, plant, and equipment; regulatory assets and liabilities; operating revenues; operation and maintenance expense; income taxes; and depreciation and amortization expense.
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 which include aggregate claims for refunds that substantially exceed the net book value of the Company. Auditing management’s judgments regarding the outcome of future decisions by the FERC, involved especially subjective judgment and specialized knowledge of accounting for rate regulation and the rate setting process.
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 and other public utilities, regulatory statutes, interpretations, procedural memorandums, 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, we inspected the Company’s filings and ongoing complaints filed with the FERC, including the Return on Equity, Capital Structure, Grand Gulf Sale-Leaseback Renewal, Unit Power Sales Agreement and Prudence complaints, and considered the filings with 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 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 25, 2022
We have served as the Company’s auditor since 2001.
SYSTEM ENERGY RESOURCES, INC.
INCOME STATEMENTS
For the Years Ended December 31,
2021 2020 2019
(In Thousands)
OPERATING REVENUES
Electric $570,848 $495,458 $573,410
OPERATING EXPENSES
Operation and Maintenance:
Fuel, fuel-related expenses, and gas purchased for resale 58,313 23,026 82,438
Nuclear refueling outage expenses 27,244 27,737 33,376
Other operation and maintenance 214,322 178,249 206,444
Decommissioning 38,693 37,181 35,729
Taxes other than income taxes 27,842 28,657 29,018
Depreciation and amortization 105,978 110,395 106,630
Other regulatory charges (credits) - net 26,214 (26,531) (35,210)
TOTAL 498,606 378,714 458,425
OPERATING INCOME 72,242 116,744 114,985
OTHER INCOME
Allowance for equity funds used during construction 6,188 9,122 8,709
Interest and investment income 82,744 36,478 29,488
Miscellaneous - net (18,991) (10,012) (5,516)
TOTAL 69,941 35,588 32,681
INTEREST EXPENSE
Interest expense 38,393 34,467 35,328
Allowance for borrowed funds used during construction (1,047) (1,809) (2,131)
TOTAL 37,346 32,658 33,197
INCOME BEFORE INCOME TAXES 104,837 119,674 114,469
Income taxes (1,977) 20,543 15,349
NET INCOME $106,814 $99,131 $99,120
See Notes to Financial Statements.
SYSTEM ENERGY RESOURCES, INC.
STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
2021 2020 2019
(In Thousands)
OPERATING ACTIVITIES
Net income $106,814 $99,131 $99,120
Adjustments to reconcile net income to net cash flow provided by (used in) operating activities:
Depreciation, amortization, and decommissioning, including nuclear fuel amortization 198,067 184,429 212,170
Deferred income taxes, investment tax credits, and non-current taxes accrued 11,191 (455,732) 95
Changes in assets and liabilities:
Receivables 6,054 13,932 (23,382)
Accounts payable 23,973 (11,587) 18,204
Prepaid taxes and taxes accrued (50,059) 69,145 19,247
Interest accrued (1,008) 729 (1,302)
Other working capital accounts 25,096 (34,158) 15,879
Other regulatory assets 143,417 (48,880) (43,712)
Other regulatory liabilities 40,884 140,965 130,949
Pension and other postretirement liabilities (49,308) 15,596 11,177
Other assets and liabilities (253,910) (119,032) (138,304)
Net cash flow provided by (used in) operating activities 201,211 (145,462) 300,141
INVESTING ACTIVITIES
Construction expenditures (100,474) (193,857) (166,695)
Allowance for equity funds used during construction 6,188 9,122 8,709
Nuclear fuel purchases (45,180) (94,991) (18,170)
Proceeds from the sale of nuclear fuel 21,724 25,836 26,223
Decrease (increase) in other investments (300) - -
Proceeds from nuclear decommissioning trust fund sales 1,022,170 418,943 500,384
Investment in nuclear decommissioning trust funds (1,025,779) (432,249) (517,828)
Changes in money pool receivable - net (71,741) 55,294 47,824
Litigation proceeds for reimbursement of spent nuclear fuel storage costs - 5,459 -
Net cash flow used in investing activities (193,392) (206,443) (119,553)
FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt 662,423 1,147,903 1,103,917
Retirement of long-term debt (727,510) (891,410) (1,187,406)
Capital contribution from parent - 350,000 -
Common stock dividends and distributions (96,000) (80,653) (124,250)
Net cash flow provided by (used in) financing activities (161,087) 525,840 (207,739)
Net increase (decrease) in cash and cash equivalents (153,268) 173,935 (27,151)
Cash and cash equivalents at beginning of period 242,469 68,534 95,685
Cash and cash equivalents at end of period $89,201 $242,469 $68,534
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest - net of amount capitalized $39,340 $35,061 $21,052
Income taxes $54,959 $384,329 $2,284
See Notes to Financial Statements.
SYSTEM ENERGY RESOURCES, INC.
BALANCE SHEETS
ASSETS
December 31,
2021 2020
(In Thousands)
CURRENT ASSETS
Cash and cash equivalents:
Cash $87 $26,086
Temporary cash investments 89,114 216,383
Total cash and cash equivalents 89,201 242,469
Accounts receivable:
Associated companies 118,977 57,743
Other 7,003 2,550
Total accounts receivable 125,980 60,293
Materials and supplies - at average cost 127,093 123,006
Deferred nuclear refueling outage costs 10,123 34,459
Prepayments and other 1,870 6,864
TOTAL 354,267 467,091
OTHER PROPERTY AND INVESTMENTS
Decommissioning trust funds 1,385,254 1,215,868
TOTAL 1,385,254 1,215,868
UTILITY PLANT
Electric 5,362,494 5,309,458
Construction work in progress 97,968 59,831
Nuclear fuel 171,438 175,005
TOTAL UTILITY PLANT 5,631,900 5,544,294
Less - accumulated depreciation and amortization 3,396,136 3,355,367
UTILITY PLANT - NET 2,235,764 2,188,927
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Other regulatory assets 395,546 538,963
Other 1,793 3,119
TOTAL 397,339 542,082
TOTAL ASSETS $4,372,624 $4,413,968
See Notes to Financial Statements.
SYSTEM ENERGY RESOURCES, INC.
BALANCE SHEETS
LIABILITIES AND EQUITY
December 31,
2021 2020
(In Thousands)
CURRENT LIABILITIES
Currently maturing long-term debt $50,329 $100,015
Accounts payable:
Associated companies 23,682 15,309
Other 62,573 41,313
Taxes accrued 32,918 82,977
Interest accrued 11,714 12,722
Other 4,101 4,248
TOTAL 185,317 256,584
NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued 382,931 359,835
Accumulated deferred investment tax credits 43,003 38,902
Regulatory liability for income taxes - net 113,165 151,829
Other regulatory liabilities 744,944 665,396
Decommissioning 1,007,603 968,910
Pension and other postretirement liabilities 76,104 125,412
Long-term debt 690,967 705,259
Other 37,230 61,295
TOTAL 3,095,947 3,076,838
Commitments and Contingencies
COMMON EQUITY
Common stock, no par value, authorized 1,000,000 shares; issued and outstanding 789,350 shares in 2021 and 2020
951,850 951,850
Retained earnings 139,510 128,696
TOTAL 1,091,360 1,080,546
TOTAL LIABILITIES AND EQUITY $4,372,624 $4,413,968
See Notes to Financial Statements.
SYSTEM ENERGY RESOURCES, INC.
STATEMENTS OF CHANGES IN COMMON EQUITY
For the Years Ended December 31, 2021, 2020, and 2019
Common Equity
Common Stock Retained Earnings Total
(In Thousands)
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
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
See Notes to Financial Statements.

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ITEM 2. PROPERTIES
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.

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ITEM 3. LEGAL PROCEEDINGS
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 2021 are discussed in Part I. Item 1. - Entergy’s Business under the sections titled “Retail Rate Regulation,” “Environmental Regulation,” and “Litigation.”

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures
Not applicable.
INFORMATION ABOUT EXECUTIVE OFFICERS OF ENTERGY CORPORATION
Executive Officers
Name Age Position Period
Leo P. Denault (a)
62 Chairman of the Board and Chief Executive Officer of Entergy Corporation
2013-Present
A. Christopher Bakken, III (a)
60 Executive Vice President and Chief Nuclear Officer of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy
2016-Present
Marcus V. Brown (a)
60 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. Marsh (a)
50 Executive Vice President and Chief Financial Officer of Entergy Corporation
2013-Present
Director of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy
2013-Present
Chief Financial Officer of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy
2014-Present
Name Age Position Period
Roderick K. West (a)
53 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
Executive Vice President of Entergy Corporation
2010-2017
Paul D. Hinnenkamp (a)
60 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
Kathryn A. Collins 58 Senior Vice President and Chief Human Resources Officer, Entergy Corporation 2020-Present
Chief Human Resources Officer, Arcosa, Inc. 2018-2020
Vice President, Human Resources, Trinity, Inc. 2014-2018
Julie E. Harbert (a)
48 Senior Vice President, Corporate Business Services of Entergy Corporation
2019-Present
Vice President, Shared Services of Entergy Services, Inc.
2017-2019
Senior Vice President, Global Business Services of Philips Health Tech
2015-2017
Kimberly A. Fontan (a)
48 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-Present
Vice President, System Planning of Entergy Services, Inc.
2017-2019
Vice President, Regulatory Services of Entergy Services, Inc.
2015-2017
Peter S. Norgeot, Jr. (a)
56 Senior Vice President, Transformation of Entergy Corporation
2018-Present
Senior Vice President, Power Generation of Entergy Services
2017-2018
Vice President, Fossil Generation of Entergy Services
2015-2017
(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, 2021.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
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, 2022, there were 21,707 stockholders of record of Entergy Corporation.
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)
10/01/2021 - 10/31/2021 - $- - $350,052,918
11/01/2021 - 11/30/2021 - $- - $350,052,918
12/01/2021 - 12/31/2021 - $- - $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 2021, Entergy withheld 81,434 shares of its common stock at $95.12 per share, 40,476 shares of its common stock at $95.15 per share, 36,804 shares of its common stock at $94.75 per share, 36,347 shares of its common stock at $95.33 per share, 1,188 shares of its common stock at $91.16 per share, 853 shares of its common stock at $96.47 per share, 719 shares of its common stock at $98.01 per share, 678 shares of its common stock at $92.70 per share, 584 shares of its common stock at $94.69 per share, 118 shares of its common stock at $95 per share, and 10 shares of its common stock at $95.25 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 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.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. Reserved

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
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, ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES, ENTERGY TEXAS, INC. AND SUBSIDIARIES, and SYSTEM ENERGY RESOURCES, INC.”

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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.”

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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, Entergy New Orleans, LLC and Subsidiaries, Entergy Texas, Inc. and Subsidiaries, and System Energy Resources, Inc.”

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes In and Disagreements With Accountants On 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.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
As of December 31, 2021, 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 “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 “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, 2021. 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, 2021.
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, 2021 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, 2021, based on criteria established in Internal Control -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, 2021, 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, 2021 of the Corporation and our report dated February 25, 2022 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 25, 2022

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
None.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
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 6, 2022, 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
Directors
Laura R. Landreaux
48 President and Chief Executive Officer of Entergy Arkansas
2018-Present
Director of Entergy Arkansas
2018-Present
Operational Finance Director of Entergy Arkansas
2017-2018
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.
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.
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. Denault
See information under the Information about Executive Officers of Entergy Corporation in Part I.
Laura 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.
Kimberly A. Fontan
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.
59 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.
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.
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. Denault
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.
Phillip R. May, Jr.
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.
Roderick K. West
See information under the Information about Executive Officers of Entergy Corporation in Part I.
ENTERGY MISSISSIPPI, LLC
Directors
Haley R. Fisackerly
56 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.
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.
Officers
Marcus V. Brown
See information under the Information about Executive Officers of Entergy Corporation in Part I.
Leo P. Denault
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.
Andrew S. Marsh
See information under the Information about Executive Officers of Entergy Corporation in Part I.
Kimberly A. Fontan
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 57 President and Chief Executive Officer of Entergy New Orleans 2021-Present
Director of Entergy New Orleans 2021-Present
Vice President, Regulatory and Public Affairs, Entergy Texas 2014-2021
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.
Roderick K. West
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. Denault
See information under the Information about Executive Officers of Entergy Corporation in Part I.
Deanna D. Rodriguez See information under the Entergy New Orleans Directors Section above.
Andrew S. Marsh
See information under the Information about Executive Officers of Entergy Corporation in Part I.
Kimberly A. Fontan
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 TEXAS, INC.
Directors
Eliecer Viamontes 39 President and Chief Executive Officer of Entergy Texas 2021-Present
Director of Entergy Texas 2021-Present
Vice President, Utility Distribution Operations, Entergy Services, Inc. 2020-2021
Senior Director of Labor Relations and Corporate Safety, Florida Power and Light Corporation 2018-2020
Director, Major and Governmental Accounts,
Florida Power and Light Corporation 2017-2018
Senior Manager, Customer and Employee Experience, Florida Power and Light Corporation 2016-2017
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.
Roderick K. West
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. Denault
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. Fontan
See information under the Information about Executive Officers of Entergy Corporation in Part I.
Eliecer 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.
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, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans 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 a meeting of its 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, 2021.
Directors, Director Nomination Process and Audit Committee
The 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)), the audit committee (Item 407(d)(4) and (d)(5)), and the beneficial reporting compliance (Sec. 16(a)) is incorporated herein by reference to information to be contained in Entergy’s definitive 2022 proxy statement (“2022 Entergy Proxy Statement”) to be filed with the SEC on or before March 31, 2022 pursuant to Regulation 14A under the Securities Exchange Act of 1934.
Code of Ethics
Entergy Corporation’s Code of Business Conduct and Ethics (Code of Business Conduct) is the code of ethics that applies to Entergy’s Chief Executive Officer and other senior financial officers, including those of the Registrant Subsidiaries. The Code of Business Conduct is filed as Exhibit 14 to this report and is available on Entergy Corporation’s website at www.entergy.com. The Code of Business Conduct will 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 90013.
If any substantive amendments to the Code of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Code of Business Conduct, for any director or executive officer of Entergy Corporation, Entergy will disclose the nature of such amendment or waiver on Entergy’s website, www.entergy.com, or in a report on Form 8-K.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation
ENTERGY CORPORATION
Information concerning compensation earned by the directors and officers of Entergy Corporation is set forth in its 2022 Entergy Proxy Statement, to be filed in connection with the Annual Meeting of Shareholders to be held May 6, 2022, under the headings “Compensation Discussion and Analysis,” “Annual Compensation Programs Risk Assessment,” “Compensation Tables,” “Pay Ratio Disclosure,” and “2021 Non-Employee Director Compensation,” all of which information is incorporated herein by reference. In this section Entergy Corporation is also referred to as “Entergy” or the “Company.”
ENTERGY ARKANSAS, ENTERGY LOUISIANA, ENTERGY MISSISSIPPI, ENTERGY NEW ORLEANS, AND ENTERGY TEXAS
COMPENSATION DISCUSSION AND ANALYSIS
This Compensation Discussion and Analysis (“CD&A”) describes the executive compensation policies, programs, philosophy and decisions regarding the Named Executive Officers (“NEOs”) for 2021. It also explains how and why the Personnel Committee of Entergy Corporation’s Board of Directors arrived at the specific compensation decisions involving the NEOs in 2021 who were:
Name(1)
Title
Marcus V. Brown Executive Vice President and General Counsel, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas
Leo P. Denault Chairman of the Board and Chief Executive Officer
David D. Ellis(2)
Former President and Chief Executive Officer, Entergy New Orleans
Haley R. Fisackerly President and Chief Executive Officer, Entergy Mississippi
Laura R. Landreaux 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
Phillip R. May, Jr. President and Chief Executive Officer, Entergy Louisiana
Sallie T. Rainer(3)
Former President and Chief Executive Officer, Entergy Texas
Deanna D. Rodriguez(2)
President and Chief Executive Officer, Entergy New Orleans
Eliecer Viamontes(3)
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
(1)Messrs. Brown, Denault, Marsh, and West hold the positions referenced above as executive officers of Entergy Corporation and are members of Entergy Corporation’s Office of the Chief Executive (“OCE”). No additional compensation was paid in 2021 to any of these officers for their service as NEOs of the Utility operating companies.
(2)Mr. Ellis is included in the Executive Compensation section of this Form 10-K because he served as President and Chief Executive Officer, Entergy New Orleans for a portion of 2021. Mr. Ellis currently serves as Entergy Services, Senior Vice President, Chief Customer Officer. Ms. Rodriguez became President and Chief Executive Officer, Entergy New Orleans in May 2021.
(3)Ms. Rainer is included in the Executive Compensation section of this Form 10-K because she served as President and Chief Executive Officer, Entergy Texas for a portion of 2021. Ms. Rainer retired in November 2021. Mr. Viamontes became President and Chief Executive Officer, Entergy Texas in November 2021 upon Ms. Rainer’s retirement.
Entergy Corporation’s Compensation Principles and Philosophy
Entergy Corporation’s executive compensation programs are based on a philosophy of pay for performance that supports its strategy and business objectives. It believes the executive pay programs:
•Motivate its management team to drive strong financial and operational results by linking pay to performance.
•Attract and retain a highly experienced, diverse and successful management team.
•Incentivize and reward the achievement of results that are deemed by the Personnel Committee to be consistent with the overall goals and strategic direction that the Entergy Corporation Board has approved.
•Create sustainable value for the benefit of all of Entergy Corporation’s stakeholders, including its customers, employees, communities and owners.
•Align the interests of the executives and Entergy Corporation’s investors in its long-term business strategy by directly tying the value of equity-based awards to Entergy Corporation’s stock price performance and relative total shareholder return (“TSR”).
Compensation Best Practices
Practice Description
Pay for Performance The executive compensation programs yield pay outcomes that are highly correlated with performance and drive long-term value creation.
Short and Long-Term Incentive Measures Drive Desired Employee Behaviors
Performance measures for the Short-Term Incentive (STI) and Long-Term Incentive programs 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 - Earnings Per Share, Credit, TSR.
Double Trigger 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 vesting of equity awards.
Long-Term Incentives Paid in Stock All long-term incentives are settled in shares of Entergy common stock.
Robust Stock Ownership Guidelines The 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 opportunity for the STI and Long-Term Performance Unit Program (PUP) awards.
Rigorous Goals We set financial goals based on externally disclosed annual and multi-year guidance and outlooks, and non-financial goals based on rigorous internal review.
Clawback Policy This policy allows recovery of incentive cash, equity compensation and severance payments where a payment was based on financial results that were the subject of a material restatement, a material miscalculation of a performance award or an executive officer engaged in fraud that caused or partially caused the need for a restatement or a material miscalculation of a performance award.
No Hedging of Company Stock Entergy’s directors, executive officers and employees may not directly or indirectly engage in transactions intended to hedge or offset the market value of the Company’s common stock owned by them.
No Pledging of Company Stock Entergy’s directors and executive officers may not directly or indirectly pledge Entergy common stock as collateral for any obligation.
Practice Description
No Tax Gross-Ups The Company does not provide tax gross ups to OCE members, other than relocation benefits.
No Dividends on Unearned Performance Awards The Company does not pay dividends on unearned performance awards.
No Repricing or Exchange of Underwater Stock Options The Company’s equity incentive plan does not permit repricing or the exchange of underwater stock options without the approval of its shareholders.
No Employment Agreements The Company does not have employment contracts with its executive officers.
Independent Compensation Consultant The Personnel 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 risk-taking behavior.
2021 Incentive Payouts
Performance measures and targets for the 2021 STI awards were determined by the Personnel Committee in January 2021. Targets and measures for the 2019 - 2021 performance cycle for the long-term performance units were established in January 2019. In January 2022, the Personnel Committee certified the results for the Entergy Achievement Multiplier (“EAM”) for the 2021 STI awards and the 2019 - 2021 long-term performance period.
STI Awards
In January 2021, the Personnel Committee determined that the EAM that would determine the overall funding level for the 2021 STI awards would be based on financial and ESG measures with the financial measure weighted 60% and the ESG measures collectively accounting for the remaining 40%.
Financial Measure: Keeping with the Personnel Committee’s goal of aligning performance measures with financial results that link to externally communicated investor guidance, Entergy Tax Adjusted Earnings Per Share (“ETR Tax Adjusted EPS”) was used as the financial measure to determine the EAM.
ESG Measures: To demonstrate Entergy’s strong commitment to its ESG goals and link executive compensation more directly to the achievement of those objectives, the Personnel 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 2021 STI targets and results determined by the Personnel Committee were:
STI Performance Goals(1)
2021 Percentage of EAM Target 2021 Results Level of Achievement
ETR Tax Adjusted EPS ($) 60% 5.95 6.22 144%
Safety (SIF Rate) 10% 0.03 ___(2)
0%
Diversity, Inclusion and Belonging 10% Qualitative 110%
Environmental Stewardship 10% Qualitative 140%
Customer NPS 10% 9 11.2 131%
EAM as a percentage of target 100% 125%(3)
(1) See “What Entergy Corporation Pays and Why - 2021 Compensation Decisions - STI Compensation - ESG Measures and Targets” for a discussion of the performance assessment of the Diversity, Inclusion and Belonging and Environmental Stewardship performance measures.
(2) Measure defaulted to achievement level of 0% due to one employee and two contractor fatalities in 2021. 2021 SIF results were 0.05 for employees and 0.15 for contractors.
(3) After consideration of individual performance, NEO payouts averaged 124% of target.
Long-Term Performance Unit Program
In January 2019, the Personnel Committee chose relative TSR and Cumulative ETR Adjusted Earnings Per Share (“Cumulative ETR Adjusted EPS”) as the performance measures for the 2019 - 2021 performance period, with relative TSR weighted 80% and Cumulative ETR Adjusted EPS weighted 20%. Cumulative ETR Adjusted EPS adjusts Entergy’s as reported (GAAP) results to eliminate the impact of the Entergy Wholesale Commodities (“EWC”) business and other non-routine items, consistent with the manner in which we communicated earnings guidance and outlooks to investors at the time the measure was chosen.
The targets and results for the 2019 - 2021 performance period as determined by the Personnel Committee were:
Long-Term PUP Results 2019-2021 PUP Target 2019-2021 PUP Results
Relative TSR Median 2nd Quartile
Cumulative ETR Adjusted EPS($) 16.60 17.44
Payout (as a percentage of target) 100% 120%
What Entergy Corporation Pays and Why
How Entergy Corporation Makes Compensation Decisions
Role of the Personnel Committee
The Personnel Committee, comprised 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 Personnel 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 Personnel Committee also considers input and recommendations from management, including Mr. Denault and Ms. Collins, Entergy’s Chief Human Resource Officer, who attend the Personnel Committee meetings.
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 2021, the Personnel Committee continued to retain Pay Governance, LLC (“Pay Governance”) as its independent compensation consultant. Pay Governance attended each of the 2021 Personnel Committee meetings and provides 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 Personnel Committee members without management present.
Competitive Positioning
➢ Market Data for Compensation Comparison
Annually, the Personnel Committee reviews:
•published and private compensation survey data compiled by Pay Governance;
•both utility and general industry data to determine total cash compensation (base salary and annual incentive) for non-industry specific roles;
•data from utility companies to determine total cash compensation for management roles that are utility-specific, such as Group President, Utility Operations; and
•utility market data to determine long-term incentives for all positions.
➢ How the Personnel Committee Uses Market Data
The Personnel Committee uses this survey data to develop compensation opportunities that are designed to deliver total direct compensation (“TDC”) 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 the Company’s Chief Executive Officer and the eight other executive officers who constitute the OCE each has a TDC 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 at the lower end of the competitive range, while seasoned executive officers whose experience and skillset are viewed as critical to retain may be positioned at the higher end of the competitive range.
➢ Proxy Peer Group
Although the survey data described above are the primary data used in benchmarking compensation, the Personnel Committee uses compensation information from the companies included in the Philadelphia Utility Index to evaluate the overall reasonableness of the Company’s compensation programs and to determine relative TSR for the 2021 - 2023 PUP performance period. The Personnel Committee identified the Philadelphia Utility Index as the appropriate industry peer group for determining relative TSR because the companies included in this index, in the aggregate, are viewed as comparable to the Company in terms of business and scale.
The companies included in the Philadelphia Utility Index at the time the Personnel Committee approved the 2021 compensation model and framework were:
AES Corporation Consolidated Edison Inc. Eversource Energy Public Service Enterprise Group, Inc.
Ameren Corporation Dominion Energy Exelon Corporation Southern Company
American Electric Power Co. Inc. DTE Energy Company FirstEnergy Corporation WEC Energy, Inc.
American Water Works Company, Inc. Duke Energy Corporation NextEra Energy, Inc. Xcel Energy, Inc.
CenterPoint Energy Inc. Edison International Pinnacle West Capital Corporation
2021 Compensation Structure and Incentive Metrics
In 2021, the compensation programs consisted of base salary and short and long-term incentives as outlined in the table below:
Compensation Element Form Objective Metrics/Performance Period Subject to Clawback
Base Salary Cash Provides a base level of competitive cash compensation for executive talent. N/A
Short-Term Incentive Cash Motivates and rewards executives for performance on key financial and ESG measures during the year; incentivizes behaviors that serve the Company’s four stakeholders - customers, employees, communities and owners.
•
ETR Tax Adjusted EPS ü
•
Safety
•
DIB
•
Environmental Stewardship
•
Customer NPS
Measured over a one-year period
Long-Term Performance Units Equity Focuses the executives on driving utility growth, building long-term shareholder value, and growing earnings. 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. •
Relative TSR ü
•
Adjusted FFO/Debt Ratio
Measured over a 3-year performance period
Stock Options Equity Align interests of executives with long-term shareholder value, provide market competitive compensation, and increase executives’ ownership in the Company further enhancing their focus on driving continuous improvement in operational results. Service-based with 3-year pro rata vesting ü
Restricted Stock Equity Aligns interests of executives with long-term shareholder value, provides market competitive compensation, retains executive talent and increases executives’ ownership in the Company further enhancing their focus on driving continuous improvement in operational results. Service-based with 3-year pro rata vesting ü
2021 Compensation Decisions
Base Salary
The salary for each NEO is based on the outcome of the annual merit review, the need 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 OCE, the Personnel Committee also considers the results of the annual market assessment of OCE compensation as provided by its independent compensation consultant described above. In 2021, all of the NEOs received increases in their base salaries ranging from approximately 3% to 6% effective April 1, 2021.
The following table sets forth the 2020 and 2021 base salaries for the Named Executive Officers. Except as indicated below, changes in base salaries for 2021 were effective in April.
Named Executive Officer 2020 Base Salary 2021 Base Salary
Marcus V. Brown $690,000 $710,700
Leo P. Denault $1,260,000 $1,300,000
David D. Ellis(1)
$321,849 $415,000
Haley R. Fisackerly $388,244 $399,891
Laura R. Landreaux (2)
$326,755 $380,000
Andrew S. Marsh $690,000 $710,700
Phillip R. May, Jr. $404,784 $416,928
Sallie T. Rainer $358,713 $369,474
Deanna D. Rodriguez(1)
$284,480 $330,000
Eliecer Viamontes(1)
$315,000 $340,000
Roderick K. West $731,863 $753,819
(1) Mr. Ellis’s and Ms. Rodriguez’s salaries were increased in May 2021, and Mr. Viamontes’s salary was increased in November 2021. Each of their salaries was increased in conjunction with their promotion to the new positions they assumed in 2021. The compensation levels for each of these officers were determined using competitive compensation data provided by Pay Governance. For Ms. Rodriguez and Mr. Viamontes, their previous compensation levels and the compensation paid to their predecessors at Entergy New Orleans and Entergy Texas, respectively, were also considered. Mr. Ellis’s salary was established, in consultation with Pay Governance, to reflect his unique responsibilities and accountability as the Company’s first Chief Customer Officer.
(2) Ms. Landreaux’s base salary was further adjusted in 2021 following an external market competitive pay analysis.
STI Compensation
The NEOs are eligible for STI awards under our 2019 Omnibus Incentive Plan (“2019 OIP”). Maximum funding for the STI awards is determined by the EAM performance measure. Annually, after a review of the Company’s strategic plan, the Personnel 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 Personnel 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. At December 31, 2021, Mr. Ellis and Mr. May held a Level 3 position, and Mr. Fisackerly, Ms. Landreaux, Ms. Rodriguez and Mr. Viamontes held Level 4 positions. Ms. Rainer held a Level 4 position when she retired in November 2021. 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. In 2021, the target opportunities for Mr. Ellis and Ms. Rodriguez were increased in conjunction with their promotions during the year. The target opportunities for the other NEOs in 2021 remained at the same level as those established for 2020.
In January, after the end of the fiscal year, the Finance and Personnel Committees jointly review the Company’s results, and the Personnel Committee determines the EAM based on the level of achievement of the performance measures established. The Personnel Committee retains discretion to modify the EAM based on its assessment of the degree of management’s achievement of various operational and regulatory goals and overcoming any challenges that occurred during the year.
Individual executive officer awards are determined based on the Personnel Committee’s consideration of each executive’s role in executing the Company’s strategies and delivering the financial performance achieved, but also the individual’s accountability for any challenges and achievements the Company experienced during the year.
2021 Performance Measures and Methodology
For 2021, the Personnel Committee decided that the EAM would be based on both financial and ESG measures, with the financial measure weighted 60% and four ESG 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 target and between target and the maximum 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 measures.
Financial Measure and Target
For the EAM financial measure, the Personnel Committee decided to use ETR Tax Adjusted EPS. This measure is based on the Company’s Adjusted EPS, the measure by which the Company provides external guidance, which is then adjusted to add back the effect of significant tax items and to eliminate the effect of: (i) major storms, including the impact on total debt of pending securitizations; (ii) any resolution during the year of certain unresolved regulatory litigation matters, (iii) unrealized gains or losses on equity securities, (iv) effects of federal income tax law changes: and (v) any adjustments 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”). The Personnel Committee determined that target performance for this metric would equal management’s expectation for the Company’s Adjusted EPS as reflected in its financial plan, or $5.95 per share, with minimum performance determined to be $5.35 per share and maximum performance being $6.55 per share.
ETR Tax Adjusted EPS was used as the financial measure for the EAM because:
•It is based on an objective financial measure that the Company and their investors consider to be important in evaluating financial performance.
•It is based on the same metrics used for internal and external financial reporting.
•It provides both discipline and transparency.
The Personnel Committee considered it appropriate to use ETR Tax Adjusted EPS, which adds back the effect of significant tax items that may have been excluded from ETR Adjusted EPS, as the earnings measure because of the significant financial benefits to the Company resulting from such tax items and the management effort required to achieve them.
The committee 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 the financial measure. It viewed the exclusion of major storms as appropriate because although the Company includes estimates for storm costs in its financial plan, it does not include estimates for a major storm event, such as a hurricane. The Personnel Committee considered the exclusion of the effects of any unanticipated changes in federal income tax law to be appropriate because of 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 Personnel Committee approved the other exclusions from reported results - for the impact of certain legacy unresolved regulatory litigation and unanticipated unrealized gains and losses on securities - primarily because of management’s inability to influence either of the related outcomes.
ESG Measures and Targets
To demonstrate Entergy’s strong commitment to its ESG goals and to more directly link executive compensation to successful execution on its strategies to achieve those objectives, the Personnel Committee decided to use the ESG measures described below to determine 40% of the EAM, with each of the measures weighted at 10%. These measures were selected because the committee considered them to represent keyways that the Company creates 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 the ESG measures, including the metric or methodology used for determining the level of achievement and the rationale for each of the selected measures:
Measure Metrics and Targets Objective
Safety Rate of serious injuries and fatalities per 100 employees or contractors (SIF rate). Minimum performance = 50th percentile, target = 75th percentile, and maximum performance = 90th percentile of published Edison Electric Institute member SIF rate data as published in 2021, with no payout if any fatalities. Ensures Entergy maintains a safe and incident-free workplace for all of its employees and contractors.
Diversity, Inclusion & Belonging (DIB) Overall qualitative assessment of DIB key performance indicators assessed in the workforce, workplace and marketplace, informed by quantitative measures; 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 key initiatives and Utility CO2 emission rate outcomes.
•
Reinforces Entergy’s commitment to long-term sustainability and a reduced impact on the environment.
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Ensures accountability for achieving the Company’s significant external commitments to reduce carbon emissions.
Customer Net Promoter Score (NPS) Customer NPS 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 = 2, target = 9, and maximum performance = 16.
•
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.
In determining the targets to set for 2021, the Personnel Committee reviewed anticipated drivers and risks to the Company’s expectations for its adjusted earnings for 2021 as set forth in the Company’s financial plan, as well as factors driving the strong financial performance achieved in 2020. The Personnel Committee confirmed that the proposed plan targets for ETR Tax Adjusted EPS reflected significant growth in the core earnings measure
underlying the STI target. The Personnel Committee also considered the potential impact of a wide range of identified risks and opportunities and confirmed that both the financial and ESG STI 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.
2021 Performance Assessment
In January 2022, the Finance and Personnel Committees jointly reviewed the Company’s financial and operational results and assessed management’s performance against the performance objectives and targets described above in order to determine the EAM. The following table summarizes the STI targets and performance results for 2021, resulting in an EAM of 125%:
Performance Measure Targets and Results
Weighting Minimum Target Maximum 2021 Results Level of Achievement
ETR Tax Adjusted EPS ($) 60% 5.35 5.95 6.55 6.22 144%
Safety (SIF Rate) 10% 0.07 0.03 0.00 ___(1)
0%
Diversity, Inclusion & Belonging 10% Qualitative assessment (see below) 110%
Environmental Stewardship 10% Qualitative assessment (see below) 140%
Customer Net Promoter Score 10% 2 9 16 11.2 131%
EAM 100% 25% 100% 200% 125%
(1) Measure defaulted to achievement level of 0% due to one employee and two contractor fatalities in 2021. 2021 SIF results were 0.05 for employees and 0.15 for contractors.
In assessing 2021 financial performance, the Finance and Personnel Committees reviewed various factors explaining how the 2021 ETR Tax Adjusted EPS result compared to the 2021 business plan and STI target set in January 2021. ETR Tax Adjusted EPS exceeded the ETR Tax Adjusted EPS target of $5.95 per share by $0.27. This outperformance resulted in part from the fact that ETR Adjusted EPS exceeded the midpoint of the guidance set at the beginning of the year by $0.07 per share. The ETR Tax Adjusted EPS result also reflected a positive adjustment of $0.26 to ETR Adjusted EPS for the net effects on earnings of major storms impacting the Company’s service area during 2021, consistent with the Pre-Determined Exclusions approved when the target was set at the beginning of the year. The results also reflected a negative adjustment of $0.06 for the effect on 2021 ETR Adjusted EPS of certain changes in tax law, also consistent with the Pre-Determined Exclusions.
In assessing management’s 2021 performance on the new ESG 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 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:
Performance Measure 2021 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 2020
Level of Achievement •
Established Diversity & Workforce Strategies Center of Excellence led by Vice President, Diversity & Workforce Strategies
•
110% •
Developed and deployed targeted DIB interventions designed to engage a diverse workforce, including in mentoring, unconscious bias, inclusive leadership and psychological safety
•
Infused DIB into hiring policies, practices and procedures and hiring manager/recruiter training
•
Integrated DIB skill building in leadership development programs for diverse group of participants
•
Engaged with partners in the utility industry and education to support mentoring programs to connect diverse students with industry mentors and expanded educational opportunity pipeline to non-traditional education partners to attract diverse students
•
Organizational health and inclusive climate survey scores declined from 2020
•
Increased diverse supplier managed spend from 2020 levels
Environmental Stewardship •
Integration of substantially higher levels of renewable power generation into planned generation mix, leading to expected achievement of 2030 climate goal ahead of schedule
Level of Achievement •
Utility equity CO2 emission rate initially projected at slightly below target of 659 lbs./MWh; subsequently determined to be above target for 2021, due in part to higher
•
140% natural gas prices resulting in more dispatch of our coal generation by the Midcontinent Independence System Operator (MISO) as compared to 2020
•
Completed Orange County Advanced Power Station hydrogen design, project investment plan and hydrogen supply plan
•
Arkansas and Louisiana coal plant retirement plan refined and integrated into business plan
•
Regulatory progress advancing customer solutions, including filings focused on green tariffs, PowerThrough backup power solutions, electric vehicles, energy efficiency and distributed resources
•
Progress on electrification of Entergy vehicle fleet
•
Progress advancing eTech offerings to promote adoption of electric-powered alternatives to fossil fuel applications
•
Progress on transmission and distribution system and water resilience planning and investment in reforestation and wetland restoration
In addition to the foregoing financial and operational results, the Personnel Committee considered management’s degree of success in achieving various operational and regulatory goals set out at the beginning of the year and in overcoming certain challenges that arose in the business during the course of the year. The committee took note of not only various ways management had created value for all the Company’s key stakeholders during 2021, but also major external challenges that were overcome in the process, including particularly Winter Storm Uri and Hurricane Ida, as well as the continuing COVID-19 pandemic, inflationary pressure on customer bills, supply chain constraints and labor market shortages. The committee also noted that despite these challenges, management had remained focused on achieving strong financial results for the benefit of all of its stakeholders while at the same time driving positive outcomes in areas that would contribute to the long-term sustainability of the Company.
Under the STI program, NEOs who are members of the OCE could earn a payout ranging from 0% to 200% of the NEO’s target opportunity while NEOs who are not members of the OCE could earn a payout ranging from 0% to 300% of the NEO’s target opportunity, subject to the overall funding limitation determined by the EAM. To determine individual NEO STI awards for members of the OCE, the Personnel Committee considered individual performance in executing on the Company’s strategies and delivering the strong financial performance achieved in 2021, as well as the executive’s success in achieving individual goals within the executive’s scope of responsibilities. In addition, the Personnel Committee considered the individual’s key accountabilities and accomplishments in relation to major external challenges the Company experienced during the year, including those referenced above. With these considerations in mind, the Personnel Committee approved payouts to each of the NEOs, who are members of the OCE, that were modestly higher than the EAM, ranging from 135% to 150% of target.
After the EAM was established to determine overall funding for the STI 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 NEOs who are not members of the OCE by their immediate supervisor based on the individual officer’s key accountabilities, accomplishments, and performance. This resulted in payouts that ranged from 87% of target to 145% of target for the NEOs who are not members of the OCE.
Based on the foregoing evaluation of management performance, the NEOs received the following STI payouts:
Named Executive Officer Base Salary Target as Percentage of Base Salary(1)
Payout as Percentage of Target 2021 Annual
Incentive Award
Marcus V. Brown $710,700 80% 135% $852,840
Leo P. Denault $1,300,000 140% 135% $2,457,000
David D. Ellis $415,000 60% 92% $228,225
Haley R. Fisackerly $399,891 40% 135% $216,186
Laura R. Landreaux $380,000 40% 145% $220,093
Andrew S. Marsh $710,700 85% 150% $906,143
Phillip R. May, Jr. $416,928 60% 133% $333,205
Sallie T. Rainer(2)
$369,474 40% 87% $127,949
Deanna D. Rodriguez $330,000 40% 110% $144,662
Eliecer Viamontes $340,000 40% 99% $134,793
Roderick K. West $753,819 80% 140% $844,277
(1) The target opportunities, as a percentage of salary, were determined based on the individual’s position and salary at the end of 2021.
(2) Ms. Rainer received a pro-rated STI award since she retired prior to the end of the performance year.
Long-Term Incentive Compensation
Overview
Long-term incentive compensation delivered in shares of Entergy common stock represents the largest portion of executive officer compensation. The Company believes the combination of long-term incentives it employs provides a compelling performance-based compensation opportunity, is effective at retaining a strong senior management team, and aligns the interests of the executive officers with the interests of Entergy’s customers and shareholders by enhancing executives’ focus on the Company’s long-term goals.
For each NEO, a dollar value is established to determine that NEO’s long-term incentive awards. The award value for each NEO is determined based on market median compensation data for the officer’s role, adjusted to reflect individual performance and internal equity. In January 2021, the Personnel Committee approved the 2021
long-term incentive award target amounts for each NEO. Mr. Denault’s target opportunity was increased in recognition of his strong performance and the Company’s significant achievements in 2020. This amount for each NEO was then converted into the number of performance units, stock options and shares of restricted stock granted to each NEO based on an allocation of 60% PUP, 20% stock options and 20% restricted stock.
NEO Long-Term Incentive
Grant Date Value
Marcus V. Brown $1,507,328
Leo P. Denault $8,986,053
David D. Ellis $310,982
Haley R. Fisackerly $282,240
Laura R. Landreaux $266,557
Andrew S. Marsh $2,008,880
Phillip R. May, Jr. $371,053
Sallie T. Rainer $47,522
Deanna D. Rodriguez $258,603
Eliecer Viamontes $298,154
Roderick K. West $1,840,794
2021 Long-Term Incentive Award Mix
Long-Term Performance Units
The NEOs are issued performance unit awards under the PUP with payout opportunities established by the Personnel Committee at the beginning of each three-year performance period.
The PUP specifies a minimum, target and maximum achievement level, the achievement of which determines the number of performance units that may be earned by each participant. For the 2021 - 2023 PUP performance period, the Personnel Committee chose the performance measures and targets set forth below.
2021-2023 PUP Performance Period: Measures and Goals
Performance Measures(1)
PUP
Measure Weight Goals(2)
Relative TSR 80% Minimum (25%) - Bottom of 3rd Quartile
Target (100%) - Median Percentile
Maximum (200%) - Top Quartile
Adjusted FFO/Debt Ratio(3)
20% Minimum (25%) - 14.5%
Target (100%) - 15.5%
Maximum (200%) - 17.0%
(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 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 be adjusted to exclude the Pre-Determined Exclusions.
Performance Measures
Relative TSR:
•The Personnel Committee chose relative TSR as a performance measure because it reflects the 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’s TSR in relation to the TSR of the companies in the Philadelphia Utility Index. The Personnel Committee identified the Philadelphia Utility Index as the appropriate industry peer group for determining relative TSR because the companies included in this index, in the aggregate, are viewed as comparable to the Company in terms of business and scale.
Adjusted FFO/Debt Ratio:
•In recent years, we have used two financial measures to determine awards under the PUP - a cumulative EPS measure and relative TSR. To emphasize the importance of strong credit for the long-term health of our business, for the 2021 - 2023 PUP performance period we replaced the EPS measure with a credit measure - Adjusted FFO/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 Personnel 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.
Stock Options and Restricted Stock
The Company grants stock options and shares of restricted stock as part of its long-term incentive award mix because it aligns the interests of the executive officers with long-term shareholder value, provides competitive compensation, and increases the executives’ ownership in Entergy’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 January 2021 was $95.87, 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 full voting rights. The dividend reinvestment shares are subject to forfeiture similar to the terms of the original grant.
2021 Long-Term Incentive Awards
In January 2021, the Personnel Committee granted the following PUP performance units, stock options and shares of restricted stock to each NEO. The number of performance units, options and shares of restricted stock were determined as discussed above under “Long-Term Incentive Compensation - Overview.”
Named Executive Officer
2021 - 2023
Target PUP Units
Stock Options Shares of
Restricted Stock
Marcus V. Brown 8,784 21,906 3,045
Leo P. Denault 52,365 130,600 18,154
David D. Ellis(1)
2,056 3,490 486
Haley R. Fisackerly 1,645 4,101 570
Laura R. Landreaux 1,553 3,873 539
Andrew S. Marsh 11,706 29,196 4,059
Phillip R. May, Jr.
2,162 5,392 750
Sallie T. Rainer(2)
1,553 3,873 539
Deanna D. Rodriguez(3)
1,301 - 1,235
Eliecer Viamontes 1,737 4,332 603
Roderick K. West 10,727 26,752 3,719
(1)Mr. Ellis’s target PUP units were increased in connection with his promotion in 2021.
(2)Ms. Rainer retired in 2021, and forfeited the 2021 - 2023 PUP units and shares of restricted stock granted to her in January 2021.
(3)As a new officer in 2021, Ms. Rodriguez received a pro-rated target PUP award for the 2021 - 2023 performance period. Stock options are only awarded to individuals who are officers at the time of grant. Ms. Rodriguez did not receive stock options in 2021 as she was not an officer at the time of grant.
All of the performance units, the shares of restricted stock and stock options granted to our NEOs in 2021 were granted pursuant to the 2019 OIP. The 2019 OIP requires both a change in control and an involuntary job loss without cause or a 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.
Payouts for the 2019 - 2021 PUP Performance Period
In January 2019, the Personnel Committee chose relative TSR and Cumulative ETR Adjusted EPS as the performance measures for the 2019 - 2021 PUP performance period, with relative TSR weighted 80% and Cumulative ETR Adjusted EPS weighted 20%. Cumulative ETR Adjusted EPS, which adjusts Entergy’s as reported (GAAP) results to eliminate the impact of EWC 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 earnings measure used to communicate the Company’s earnings expectations externally to investors. Similar to the way targets are established for the STI awards, targets for the Cumulative ETR Adjusted EPS performance measure were established by the Personnel 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 was determined based on the achievement of the following performance goals established for both performance measures by the committee at the beginning of the performance period:
2019 - 2021 PUP Performance Period: Measure and Goals
Performance Measure(1)
PUP
Measure Weight Payout
Relative TSR 80% Minimum (25%) - Bottom of 3rd Quartile
Target (100%) - Median Percentile
Maximum (200%) - Top Quartile
Cumulative ETR Adjusted EPS ($)(2)
20% Minimum (25%) - 14.94
Target (100%) - 16.60
Maximum (200%) - 18.26
(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 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.
In January 2022, the Personnel Committee reviewed the Company’s TSR and the Cumulative ETR Adjusted EPS for the 2019 - 2021 PUP performance period in order to determine the payout to participants based upon the performance measures and range of potential payouts for the 2019 - 2021 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 throughout 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 Personnel Committee concluded that Entergy Corporation’s relative TSR for the 2019 - 2021 PUP performance period was in the second quartile, and that Cumulative ETR Adjusted EPS was $17.44, yielding a payout of 120% of target for the NEOs.
Named Executive Officer
2019 - 2021 Target Number of Shares Issued(1)
Value of Shares Actually Issued(2)
Grant Date Fair Value(3)
Marcus V. Brown 9,383 12,385 $1,366,685 $933,552
Leo P. Denault 40,508 53,648 $5,900,194 $4,030,303
David D. Ellis(4)
1,586 2,078 $229,307 $157,797
Haley R. Fisackerly 1,450 1,913 $211,100 $144,266
Laura R. Landreaux 1,450 1,913 $211,100 $144,266
Andrew S. Marsh 11,869 15,666 $1,728,743 $1,180,894
Phillip R. May, Jr.
2,150 2,837 $313,063 $213,912
Sallie T. Rainer(5)
1,369 1,792 $197,747 $136,207
Deanna D. Rodriguez(6)
- - $- $-
Eliecer Viamontes(7)
926 1,185 $130,765 $92,131
Roderick K. West 10,073 13,296 $1,467,214 $1,002,203
(1)Includes accrued dividends.
(2)Value determined based on the closing price of Entergy Corporation common stock on January 19, 2022 ($110.35), the date the Personnel Committee certified the 2019 - 2021 performance period results.
(3)Represents the aggregate grant date fair value calculated in accordance with applicable accounting rules as reflected in the 2019 Summary Compensation Table.
(4)Mr. Ellis experienced a change in officer status in 2021, and accordingly, his target opportunity was increased for the 2019 - 2021 performance period.
(5)Ms. Rainer retired in 2021, and accordingly, received a pro-rated award opportunity for the 2019 - 2021 performance period.
(6)As a new officer in 2021, Ms. Rodriguez was not eligible to participate in the 2019 - 2021 performance period.
(7)As a new hire in 2020, Mr. Viamontes received a pro-rata target award opportunity for the 2019 - 2021 performance period.
Benefits and Perquisites
Entergy Corporation’s 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 and before January 1, 2021.
Pension Equalization Plan - a non-qualified pension restoration plan for a select group of management or highly compensated employees who participate in the Entergy Retirement Plan.
Cash Balance Equalization Plan - a non-qualified restoration plan for a select group of management or highly compensated employees who participate in the Cash Balance Plan.
System Executive Retirement Plan - a non-qualified supplemental retirement plan for individuals who became executive officers before July 1, 2014.
See “2021 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.
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 long-term disability insurance.
Eligibility, coverage levels, potential employee contributions, and other plan design features are the same for the NEOs as for the broad employee population.
2021 Perquisites Corporate aircraft usage and annual mandatory physical exams. The NEOs who are members of the OCE do not receive tax gross ups on any benefits, except for relocation assistance.
In 2021, the NEOs who are not members of the OCE also were provided with club dues, relocation assistance and tax gross up payments on these perquisites.
For additional information regarding perquisites, see the “All Other Compensation” column in the 2021 Summary Compensation Table.
Deferred Compensation The NEOs are eligible to defer up to 100% of their base salary and STI awards into the Entergy Corporation sponsored Executive Deferred Compensation Plan.
Executive Disability Plan Eligible individuals who become disabled under the terms of the plan are eligible for 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).
Entergy Corporation provides these benefits to the NEOs 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 Retention Arrangements
System Executive Continuity Plan
The Personnel 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 NEOs, notwithstanding any concern that they might have at the time of a change in control regarding their own continued employment. In addition, the Personnel 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 under which each of our NEOs 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. Entergy strives to ensure that the benefits and payment levels under the System Executive Continuity Plan are consistent with market practices. Entergy’s executive officers, including the NEOs, are not entitled to any tax gross up payments on any severance benefits received under this plan. For more information regarding our severance arrangements, see “Potential Payments Upon Termination or Change in Control.”
Restricted Stock Units
Restricted stock units granted under our 2019 OIP represent phantom shares of our common stock that have an economic value equivalent to one share of our common stock. Entergy Corporation occasionally grants restricted 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 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 lift, subject to continued employment, generally over a two- to five-year period.
In May 2021, the Personnel Committee granted Mr. Brown 14,216 restricted stock units. Mr. Brown’s award was made in recognition of Mr. Brown’s senior leadership role and direction as the Company’s Executive Vice President and General Counsel and to encourage retention of his leadership in light of his marketability as the Company’s General Counsel. The committee noted, based on the advice of its independent consultant, that such grants are an effective means for retention. Mr. Brown’s restricted stock units will vest in one installment on May 17, 2024 if he satisfies the vesting requirements. Mr. Brown will vest in a pro rata portion of his restricted stock units if his employment is terminated without cause or due to a disability or death prior to May 17, 2024. If during a change in control period (as defined in the 2019 OIP), Mr. Brown’s employment is terminated without cause or by Mr. Brown for good reason his restricted stock units will vest immediately.
Mr. Denault’s 2006 Retention Agreement
Entergy Corporation currently has a retention agreement with Leo Denault, Entergy’s Chief Executive Officer. In general, Mr. Denault’s retention agreement provides for certain payments and benefits in the event of his termination of employment by his Entergy employer other than for cause, by Mr. Denault for good reason (as defined in the retention agreement), or on account of his death or disability. For additional information about Mr. Denault’s retention agreement, see “Potential Payments Upon Termination or Change in Control - Mr. Denault’s 2006 Retention Agreement.” Mr. Denault’s retention agreement provided him additional years of service and permission to retire under the System Executive Retirement Plan (“SERP”) 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, or on account of his death or disability. His retention agreement also provided that if he terminates employment for any other reason, he is entitled to up to an additional 15 years of service under the SERP only if his Entergy employer grants him permission to retire, subject to the overall 30-year cap on service credit under the
SERP. Mr. Denault’s retention agreement was entered into in 2006 when he was Entergy’s Chief Financial Officer and was designed to reflect the competition for chief financial officer talent in the marketplace at that time and the Personnel Committee’s assessment of the critical role this position played in executing the Company’s long-term financial and other strategic objectives. Based on the market data provided by the Company’s former independent compensation consultant, the committee, at the time the agreement was entered into, believed the benefits and payment levels under Mr. Denault’s retention agreement were consistent with market practices.
On May 7, 2021, Mr. Denault’s retention agreement was amended to align the permission requirements of his retention agreement with those of the SERP. Generally, SERP participants who separate from employment with an Entergy system company prior to age 65 are required to obtain permission to retire to receive their benefits. Permission is not required after age 65. Prior to the amendment, Mr. Denault’s retention agreement required him to obtain permission to retire even after age 65 to receive the 15 additional years of service under the SERP provided by the retention agreement. With the amendment, Mr. Denault no longer needs such post-age-65 permission to retire to receive the 15 additional years of service under the SERP. The amendment does not change the requirement that Mr. Denault obtain permission to retire before age 65 to receive his SERP benefits.
Non-Qualified Pension Plan Modifications
On November 2, 2021, we entered into an agreement with Leo Denault that: (i) amends the Pension Equalization Plan (“PEP”) to terminate his participation in that plan; and (ii) provides that when he terminates employment with the Company the benefit payable to him or his surviving spouse under the SERP will be frozen and determined as if Mr. Denault separated from the Company as of November 30, 2021 (including the use of compensation, service and actuarial assumptions applicable to separations as of such date). As a result of the agreement and the amendment to the SERP, the SERP benefits payable to Mr. Denault are fixed at $37,025,593 and will not change due to any changes in his compensation, service or actuarial assumptions. Except as amended, benefits payable to Mr. Denault (or his surviving spouse, if applicable) under the SERP will otherwise generally continue to be subject to the provisions of the SERP (including applicable forfeiture conditions) and Mr. Denault’s retention agreement. Based on the advice of its independent compensation consultant, the Personnel Committee approved these modifications to the PEP and SERP to ensure the SERP remains an important retention tool for Entergy’s Chief Executive Officer while mitigating future risk of cost volatility of the SERP benefit through a freeze.
Risk 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:
Clawback Provisions
Under the clawback policy, all incentives paid to all individuals subject to Section 16 of the Exchange Act, including all of the NEOs, are required to be reimbursed where:
•the payment was based on the achievement of certain financial results that were subsequently determined to be the subject of a material restatement other than a restatement due to changes in accounting policy; or a material miscalculation of a performance award occurs, whether or not the financial statements were restated and, in either case, a lower payment would have been made to the executive officer based upon the restated financial results or correct calculation; or
•in the Entergy Board of Directors’ view, the executive officer engaged in fraud that caused or partially caused the need for a restatement or caused a material miscalculation of a performance award, in each case, whether or not the financial statements were restated.
The amount required to be reimbursed is equal to the excess of the gross incentive payment 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. In addition, Entergy Corporation will seek to recover any compensation received by its Chief Executive Officer and Chief Financial Officer that is required to be reimbursed under Sarbanes-Oxley following a material restatement of Entergy Corporation’s financial statements.
Stock Ownership Guidelines and Share Retention Requirements
Entergy Corporation requires their NEOs to own Entergy stock to further align their interests with Entergy’s shareholders’ interests. Annually, the Personnel Committee monitors the executive officers’ compliance with these guidelines with all of the NEOs satisfying the applicable ownership guidelines at that time. The ownership guidelines are as follows:
The ownership guidelines are as follows:
Role Value of Common Stock to be Owned
Chief Executive Officer 6 x base salary
Executive Vice Presidents 3 x base salary
Senior Vice Presidents 2 x base salary
Vice Presidents 1 x 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 PUP;
•all net after-tax shares of our restricted stock and all net after-tax shares received upon the vesting of restricted stock 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 NEOs, are required to receive permission from the Company’s General Counsel or his designee prior to entering into any transaction involving Company securities, including gifts, other than an exercise of employee stock 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 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 the Company. An NEO bears full responsibility if he or she violates Company policy by buying or selling shares without pre-approval or when trading is restricted.
Entergy Corporation also prohibits directors and executive officers, including the 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 prohibits directors and executive officers, including the NEOs, from engaging in any hedging transactions with respect to Entergy securities.
Compensation Consultant Independence
Annually, the Personnel Committee reviews the relationship with its compensation consultant to determine whether any conflicts of interest exist that would prevent Pay Governance from independently advising the Personnel Committee. When assessing the independence of its compensation consultant 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 any member of the 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 amount of fees paid to Pay Governance is less than 1% of Pay Governance’s total consulting income.
Based on these factors, the Personnel Committee concluded that Pay Governance is independent in accordance with SEC and NYSE rules and that no conflicts of interest exist that would prevent Pay Governance from independently advising the committee.
In addition, Pay Governance has agreed that it will not accept any engagement with management without prior approval from the Personnel 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 2021, Pay Governance did not provide any services to Entergy Corporation other than the services it performed on behalf of the Personnel and Corporate Governance Committees, and it worked with Entergy Corporation’s management only as directed by the committees.
PERSONNEL COMMITTEE REPORT
The Personnel Committee Report included in the 2022 Entergy 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
2021 Summary Compensation Tables
The following table summarizes the total compensation paid or earned by each of the NEOs for the fiscal year ended December 31, 2021, and to the extent required by SEC executive compensation disclosure rules, the fiscal years ended December 31, 2020 and 2019. For information on the principal positions held by each of the 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, 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
Stock
Awards
(3)
Option
Awards
(4)
Non-Equity
Incentive
Plan
Compen-sation
(5)
Change in
Pension
Value and
Non-qualified
Deferred
Compen-sation
Earnings
(6)
All
Other
Compen-sation
(7)
Total
Total Without Change in Pension Value
(8)
Marcus V. Brown 2021 $705,286 $- $2,752,829 $268,787 $852,840 $491,400 $60,135 $5,131,277 $4,639,877
Executive Vice President and 2020 $709,688 $- $1,626,512 $327,172 $662,400 $1,746,000 $78,631 $5,150,403 $3,404,403
General Counsel - 2019 $661,563 $- $1,248,839 $297,182 $684,573 $1,455,300 $69,955 $4,417,412 $2,962,112
Entergy Corp.
Leo P. Denault 2021 $1,289,538 $- $7,383,591 $1,602,462 $2,457,000 $4,178,300 $319,164 $17,230,055 $13,051,755
Chairman of the 2020 $1,308,462 $- $6,716,017 $1,350,986 $2,116,800 $4,416,700 $289,632 $16,198,597 $11,781,897
Board and CEO - 2019 $1,260,000 $- $5,391,253 $1,282,994 $2,416,680 $3,704,500 $208,822 $14,264,249 $10,559,749
Entergy Corp.
David D. Ellis 2021 $381,971 $- $320,279 $42,822 $228,225 $31,300 $24,408 $1,029,005 $997,705
Former CEO - 2020 $331,803 $- $219,889 $36,640 $164,955 $32,200 $19,323 $804,810 $772,610
Entergy New Orleans 2019 $311,004 $- $188,861 $39,104 $159,804 $18,000 $15,267 $732,040 $714,040
Haley R. Fisackerly 2021 $396,604 $- $231,921 $50,319 $216,186 $190,000 $41,723 $1,126,753 $936,753
CEO - Entergy 2020 $384,848 $- $252,819 $49,235 $232,737 $836,200 $48,101 $1,803,940 $967,740
Mississippi 2019 $373,313 $- $197,780 $51,584 $274,570 $644,700 $37,897 $1,579,844 $935,144
Laura R. Landreaux 2021 $350,660 $- $219,035 $47,522 $220,093 $125,000 $20,683 $982,993 $857,993
CEO - Entergy 2020 $323,907 $- $252,819 $49,235 $167,153 $330,700 $26,698 $1,150,512 $819,812
Arkansas 2019 $314,407 $- $188,861 $42,432 $263,523 $228,700 $26,536 $1,064,459 $835,759
(a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k)
Name and Principal Position
(1)
Year
Salary
(2)
Bonus
Stock
Awards
(3)
Option
Awards
(4)
Non-Equity
Incentive
Plan
Compen-sation
(5)
Change in
Pension
Value and
Non-qualified
Deferred
Compen-sation
Earnings
(6)
All
Other
Compen-sation
(7)
Total
Total Without Change in Pension Value
(8)
Andrew S. Marsh 2021 $705,286 $- $1,650,645 $358,235 $906,143 $213,000 $56,018 $3,889,327 $3,676,327
Executive Vice 2020 $704,692 $- $2,053,717 $413,105 $703,800 $2,054,000 $77,741 $6,007,055 $3,953,055
President and CFO - 2019 $641,923 $- $1,579,663 $375,914 $712,400 $1,554,300 $69,863 $4,934,063 $3,379,763
Entergy Corp.,
Entergy Arkansas,
Entergy Louisiana,
Entergy Mississippi,
Entergy New
Orleans,
Entergy Texas
Phillip R. May, Jr. 2021 $413,752 $- $304,893 $66,160 $333,205 $2,000 $25,261 $1,145,271 $1,143,271
CEO - Entergy 2020 $416,677 $- $371,882 $83,585 $284,881 $1,072,100 $28,836 $2,257,961 $1,185,861
Louisiana 2019 $389,016 $- $294,183 $77,376 $407,922 $877,100 $28,297 $2,073,894 $1,196,794
Sallie T. Rainer 2021 $344,453 $- $219,035 $47,522 $127,949 $479,100 $28,151 $1,246,210 $767,110
Former CEO - 2020 $369,133 $- $252,819 $49,235 $175,713 $663,100 $33,383 $1,543,383 $880,283
Entergy Texas 2019 $344,722 $- $197,780 $51,584 $219,069 $617,200 $37,361 $1,467,716 $850,516
Deanna D. Rodriguez 2021 $314,450 $- $339,833 $- $144,662 $144,900 $59,161 $1,003,006 $858,106
CEO - Entergy
New Orleans
Eliecer Viamontes 2021 $324,120 $- $245,000 $53,154 $134,793 $22,300 $102,190 $881,557 $859,257
CEO - Entergy
Texas
Roderick K. West 2021 $748,087 $- $1,512,547 $328,247 $844,277 $77,500 $75,540 $3,586,198 $3,508,698
Group President 2020 $754,742 $- $1,804,816 $363,022 $673,314 $1,976,400 $59,730 $5,632,024 $3,655,624
Utility Operations - 2019 $709,023 $- $1,340,679 $319,039 $674,742 $1,604,100 $67,191 $4,714,774 $3,110,674
Entergy Corp.
(1)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.
(2)The amounts in column (c) represent the actual base salary paid to the NEOs in the applicable year. The 2020 base salary amounts include an amount attributable to an extra pay period that occurred in 2020 as the NEOs are paid on a bi-weekly basis. The 2021 changes in base salaries noted in the CD&A were effective in April 2021, except where otherwise indicated.
(3)The amounts in column (e) represent the aggregate grant date fair value of restricted stock and performance units granted under the 2015 Equity Ownership Plan of Entergy Corporation and Subsidiaries (the “2015 EOP”) and the 2019 OIP (together with the 2015 EOP, the “Equity Plans”), 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 with vesting based on the 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 TSR and Adjusted FFO/Debt Ratio, for performance units granted in 2021 are as follows: Mr. Brown, $1,684,244; Mr. Denault, $10,040,465; Mr. Ellis, $465,928; Mr. Fisackerly, $315,412; Ms. Landreaux $297,772; Mr. Marsh, $2,244,508; Mr. May, $414,542; Ms. Rodriguez $345,515; Mr. Viamontes $333,052; and Mr. West, $2,056,795. Ms. Rainer retired in 2021 and forfeited the 2021 - 2023 PUP units and shares of restricted stock granted to her in January 2021.
(4)The amounts in column (f) represent the aggregate grant date fair value of stock options granted under the Equity Plans 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.
(5)The amounts in column (g) for 2020 and 2021 represent STI award cash payments made under the 2019 OIP, and the amounts for 2019 represent the cash payments made under the annual incentive program.
(6)For all NEOs, the amounts in column (h) include the annual actuarial increase 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 (see “2021 Pension Benefits”). None of the increases for any of the NEOs is attributable to above-market or preferential earnings on non-qualified deferred compensation.
(7)The amounts in column (i) for 2021 include (a) matching contributions by Entergy Corporation under the Savings Plan to each of the NEOs; (b) dividends paid on restricted stock when vested; (c) life insurance premiums; (d) tax gross up payments on club dues; 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
Marcus V. Brown $12,180 $30,184 $11,484 $- $6,287 $60,135
Leo P. Denault $12,180 $107,961 $11,484 $- $187,539 $319,164
David D. Ellis $17,400 $1,618 $915 $101 $4,374 $24,408
Haley R. Fisackerly $12,180 $5,032 $5,883 $4,952 $13,676 $41,723
Laura R. Landreaux $- $6,358 $1,173 $4,225 $8,927 $20,683
Andrew S. Marsh $12,180 $33,989 $9,849 $- $- $56,018
Phillip R. May, Jr. $12,180 $6,837 $6,151 $93 $- $25,261
Sallie T. Rainer $12,180 $5,032 $2,301 $2,327 $6,311 $28,151
Deanna D. Rodriguez $12,350 $6,742 $1,364 $7,920 $30,785 $59,161
Eliecer Viamontes $18,127 $- $647 $16,084 $67,332 $102,190
Roderick K. West $12,672 $31,895 $3,997 $- $26,976 $75,540
(8)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 Personnel 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 NEOs as part of providing a competitive executive compensation program and for employee retention. The following perquisites were provided to the NEOs in 2021.
Named Executive Officer Relocation Personal Use of Corporate Aircraft Club Dues Executive Physical Exams
Marcus V. Brown X X
Leo P. Denault X X
David D. Ellis X X
Haley R. Fisackerly X X
Laura R. Landreaux X
Andrew S. Marsh X
Phillip R. May, Jr.
Sallie T. Rainer X
Deanna D. Rodriguez X X
Eliecer Viamontes 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 NEOs may use the corporate aircraft for personal travel subject to the approval of Entergy Corporation’s Chief Executive Officer. Annually, the Personnel Committee reviews the level of usage. Entergy Corporation believes that its officers’ ability to use its plane for limited personal use saves time and helps to ensure their personal health and safety in light of the ongoing pandemic, in addition to providing them additional security while traveling, thereby benefiting 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 and Mr. West’s personal use of the corporate aircraft was $184,311 and $25,066, respectively, for fiscal year 2021. In addition, Entergy Corporation offers its executives comprehensive annual physical exams at Entergy Corporation’s expense.
Entergy Corporation also provides relocation benefits to a broad base of employees which include assistance with moving expenses, transportation of household goods and in 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 $37,452 and $83,323 in relocation expense for Ms. Rodriguez and Mr. Viamontes, respectively, in 2021. The relocation assistance amounts reported above represent the amount paid to Entergy’s relocation service provider or Ms. Rodriguez and Mr. Viamontes, as applicable. If Ms. Rodriguez or Mr. Viamontes separates from the Company prior to the two year anniversary of their promotion, certain of Ms. Rodriguez and Mr. Viamontes relocation benefits are subject to forfeiture.
None of the other perquisites referenced above exceeded $25,000 for any of the other NEOs.
2021 Grants of Plan-Based Awards
The following table summarizes award grants during 2021 to the NEOs.
Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1)
Estimated Future Payouts under Equity Incentive Plan Awards (2)
(a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l)
Name Grant Date Thresh-old Target
Maximum
Thresh-old
Target
Maximum
All Other Stock Awards: Number of Shares of Stock or Units All Other Option Awards: Number of Securities Under-lying Options Exercise or Base Price of Option Awards Grant Date Fair Value of Stock and Option Awards
($) ($) ($) (#)
(#)
(#)
(#)
(3)
(#)
(4)
($/Sh) ($)
(5)
Marcus V. 1/28/21 $- $568,560 $1,137,120
Brown 1/28/21 2,196 8,784 17,568 $946,617
1/28/21 3,045 $291,924
5/17/21 14,216(6)
1/28/21 21,906 $95.87 $268,787
Leo P. 1/28/21 $- $1,820,000 $3,640,000
Denault 1/28/21 13,091 52,365 104,730 $5,643,167
1/28/21 18,154 $1,740,424
1/28/21 130,600 $95.87 $1,602,462
David D. 1/28/21 $- $249,000 $498,000
Ellis(7)
1/28/21 514 2,056 4,112 $221,567
5/9/21 60 238 476 $38,588
5/9/21 34 136 272 $13,531
1/28/21 486 $46,593
1/28/21 3,490 $95.87 $42,822
Haley R. 1/28/21 $- $159,956 $319,912
Fisackerly 1/28/21 411 1,645 3,290 $177,275
1/28/21 570 $54,646
1/28/21 4,101 $95.87 $50,319
Laura R. 1/28/21 $- $152,000 $304,000
Landreaux 1/28/21 388 1,553 3,106 $167,361
1/28/21 539 $51,674
3,873 $95.87 $47,522
Andrew S. 1/28/21 $- $604,095 $1,208,190
Marsh 1/28/21 2,927 11,706 23,412 $1,261,509
1/28/21 4,059 $389,136
1/28/21 29,196 $95.87 $358,235
Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1)
Estimated Future Payouts under Equity Incentive Plan Awards (2)
(a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l)
Name Grant Date Thresh-old Target
Maximum
Thresh-old
Target
Maximum
All Other Stock Awards: Number of Shares of Stock or Units All Other Option Awards: Number of Securities Under-lying Options Exercise or Base Price of Option Awards Grant Date Fair Value of Stock and Option Awards
($) ($) ($) (#)
(#)
(#)
(#)
(3)
(#)
(4)
($/Sh) ($)
(5)
Phillip R. 1/28/21 $- $250,157 $500,314
May, Jr. 1/28/21 541 2,162 4,324 $232,990
1/28/21 750 $71,903
1/28/21 5,392 $95.87 $66,160
Sallie T. 1/28/21 $- $147,790 $295,580
Rainer(8)
1/28/21 388 1,553 3,106 $167,361
1/28/21 539 $51,674
1/28/21 3,873 $95.87 $47,522
Deanna D. 1/28/21 $- $132,000 $264,000
Rodriguez(7)
1/28/21 325 1,301 2,602 $140,204
5/9/21 125 501 1,002 $81,230
1/28/21 1,235 $118,399
1/28/21 - $95.87 $-
Eliecer 1/28/21 $- $136,000 $272,000
Viamontes 1/28/21 434 1,737 3,474 $187,190
1/28/21 603 $57,810
1/28/21 4,332 $95.87 $53,154
Roderick K. 1/28/21 $- $603,055 $1,206,110
West 1/28/21 2,682 10,727 21,454 $1,156,006
1/28/21 3,719 $356,541
1/28/21 26,752 $95.87 $328,247
(1)The amounts in columns (c), (d), and (e) represent minimum, target, and maximum payment levels under the STI program. The actual amounts awarded are reported in column (g) of the 2021 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 the companies included in the Philadelphia Utility Index and Adjusted FFO/Debt Ratio with TSR weighted eighty percent and Adjusted FFO/Debt Ratio weighted twenty percent. There is no payout under the program if Entergy Corporation’s TSR falls within the lowest quartile of the peer companies in the Philadelphia Utility Index and Adjusted FFO/Debt Ratio 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, 2023). 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 2019 OIP. 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 granted under the 2019 OIP. 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.
(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 3 and 4 to the 2021 Summary Compensation Table for a discussion of the relevant assumptions used in calculating the grant date fair value.
(6)In May 2021, Mr. Brown was awarded 14,216 restricted stock units under the 2019 OIP. The restricted units will vest in one installment on May 17, 2024.
(7)Mr. Ellis’s and Ms. Rodriguez’s awards were modified in connection with their promotions in 2021.
(8)Ms. Rainer retired in 2021 and forfeited the 2021 - 2023 PUP units and shares of restricted stock granted to her in January 2021.
2021 Outstanding Equity Awards at Fiscal Year-End
The following table summarizes, for each NEO, unexercised options, restricted stock that has not vested, and equity incentive plan awards outstanding as of December 31, 2021.
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
(#) (#) (#) ($) (#) ($) (#) ($)
Marcus V. Brown - 21,906(1)
$95.87 1/28/2031
9,524 19,050(2)
$131.72 1/30/2030
11,906 11,907(3)
$89.19 1/31/2029
13,500 - $78.08 1/25/2028
8,784(4)
$989,518
1,893(5)
$213,218
3,045(6)
$343,019
2,020(7)
$227,553
1,179(8)
$132,814
14,126(9)
$1,519,294
Option Awards Stock Awards
(a) (b) (c) (d) (e) (f) (g) (h) (i) (j)
Name Number of Securities Underlying Unexercised Options Exercisable Number of Securities Underlying Unexercised Options Unexercisable Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options Option Exercise Price Option Expiration Date Number of Shares or Units of Stock That Have Not Vested Market Value of Shares or Units of Stock That Have Not Vested Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested
(#) (#) (#) ($) (#) ($) (#) ($)
Leo P. Denault - 130,600(1)
$95.87 1/28/2031
39,330 78,660(2)
$131.72 1/30/2030
102,804 51,402(3)
$89.19 1/31/2029
167,000 - $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
106,000 - $63.17 1/30/2024
50,000 - $64.60 1/31/2023
52,365(4)
$5,898,917
7,816(5)
$880,444
18,154(6)
$2,045,048
8,337(7)
$939,163
5,087(8)
$573,051
David D. Ellis - 3,490(1)
$95.87 1/28/2031
1,066 2,134(2)
$131.72 1/30/2030
3,133 1,567(3)
$89.19 1/31/2029
2,056(4)
$231,608
297(5)
$33,457
486(6)
$54,748
334(7)
$37,625
167(8)
$18,813
Haley R. Fisackerly - 4,101(1)
$95.87 1/28/2031
1,433 2,867(2)
$131.72 1/30/2030
2,067 2,067(3)
$89.19 1/31/2029
2,200 - $78.08 1/25/2028
1,645(4)
$185,309
238(5)
$26,754
570(6)
$64,211
500(7)
$56,325
200(8)
$22,530
Option Awards Stock Awards
(a) (b) (c) (d) (e) (f) (g) (h) (i) (j)
Name Number of Securities Underlying Unexercised Options Exercisable Number of Securities Underlying Unexercised Options Unexercisable Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options Option Exercise Price Option Expiration Date Number of Shares or Units of Stock That Have Not Vested Market Value of Shares or Units of Stock That Have Not Vested Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested
(#) (#) (#) ($) (#) ($) (#) ($)
Laura R. Landreaux - 3,873(1)
$95.87 1/28/2031
1,433 2,867(2)
$131.72 1/30/2030
3,400 1,700(3)
$89.19 1/31/2029
1,553(4)
$174,945
238(5)
$26,754
539(6)
$60,718
500(7)
$56,325
167(8)
$18,813
Andrew S. Marsh - 29,196(1)
$95.87 1/28/2031
12,026 24,053(2)
$131.72 1/30/2030
30,121 15,061(3)
$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
35,000 - $63.17 1/30/2024
32,000 - $64.60 1/31/2023
10,000 - $71.30 1/26/2022
11,706(4)
$1,318,681
2,390(5)
$269,234
4,059(6)
$457,246
2,550(7)
$287,258
1,491(8)
$167,961
Phillip R. May, Jr. - 5,392(1)
$95.87 1/28/2031
2,433 4,867(2)
$131.72 1/30/2030
3,100 3,100(3)
$89.19 1/31/2029
3,300 - $78.08 1/25/2028
2,162(4)
$243,549
350(5)
$39,428
750(6)
$84,488
734(7)
$82,685
300(8)
$33,795
Option Awards Stock Awards
(a) (b) (c) (d) (e) (f) (g) (h) (i) (j)
Name Number of Securities Underlying Unexercised Options Exercisable Number of Securities Underlying Unexercised Options Unexercisable Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options Option Exercise Price Option Expiration Date Number of Shares or Units of Stock That Have Not Vested Market Value of Shares or Units of Stock That Have Not Vested Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested
(#) (#) (#) ($) (#) ($) (#) ($)
Sallie T. Rainer - 3,873(1)
$95.87 1/28/2031
1,433 2,867(2)
$131.72 1/30/2030
6,200 - $89.19 1/31/2029
4,400 - $78.08 1/25/2028
2,600 - $70.53 1/26/2027
145(5)
$16,362
Deanna D. Rodriguez 1,301(4)
$146,558
125(5)
$14,109
1,235(6)
$139,123
567(7)
$63,873
334(8)
$37,625
Eliecer Viamontes - 4,332(1)
$95.87 1/28/2031
1,737(4)
$195,673
231(5)
$26,022
603(6)
$67,928
667(10)
$75,138
Roderick K. West - 26,752(1)
$95.87 1/28/2031
10,568 21,137(2)
$131.72 1/30/2030
12,782 12,782(3)
$89.19 1/31/2029
14,167 - $78.08 1/25/2028
10,727(4)
$1,208,397
2,100(5)
$236,593
3,719(6)
$418,945
2,241(7)
$252,449
1,265(8)
$142,502
(1)Consists of options granted under the 2019 OIP; 1/3 of the options vested on January 28, 2022 and 1/3 of the remaining options will vest on each of January 28, 2023 and January 28, 2024.
(2)Consists of options granted under the 2019 OIP; 1/2 of the options vested on January 30, 2022 and the remaining options will vest on January 30, 2023.
(3)Consists of options granted under the 2015 EOP that vested on January 31, 2022.
(4)Consists of performance units granted under the 2019 OIP that will vest on December 31, 2023 based on two performance measures- Entergy Corporation’s TSR performance and Adjusted FFO/Debt Ratio over the 2021 - 2023 performance period with 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 - 2021 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 TSR performance and Cumulative ETR Adjusted EPS over the 2020 - 2022 performance period with TSR weighted eighty percent and Cumulative ETR Adjusted EPS 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 28, 2022 and 1/3 of the remaining shares will vest on each of January 28, 2023 and January 28, 2024.
(7)Consists of shares of restricted stock granted under the 2019 OIP; 1/3 of the shares of restricted stock vested on January 30, 2022 and the remaining shares of restricted stock will vest on January 30, 2023.
(8)Consists of shares of restricted stock granted under the 2015 EOP that vested on January 31, 2022.
(9)Consists of restricted stock units granted under the 2019 OIP which will vest on May 17, 2024.
(10)Consists of restricted stock units granted under the 2019 OIP; 1/2 of the restricted stock units vested on January 20, 2022 and the remaining restricted stock units will vest on January 20, 2023.
2021 Option Exercises and Stock Vested
The following table provides information concerning each exercise of stock options and each vesting of stock during 2021 for the 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)
(#) ($) (#) ($)
Marcus V. Brown - $- 16,557 $1,763,143
Leo P. Denault - $- 69,093 $7,385,433
David D. Ellis - $- 2,429 $262,835
Haley R. Fisackerly - $- 2,683 $284,394
Laura R. Landreaux - $- 2,797 $295,182
Andrew S. Marsh 4,000 $86,118 20,522 $2,190,324
Phillip R. May, Jr. - $- 3,909 $415,080
Sallie T. Rainer - $- 2,562 $270,993
Deanna D. Rodriguez - $- 1,021 $97,052
Eliecer Viamontes - $- 1,518 $162,507
Roderick K. West - $- 17,751 $1,890,564
(1)Represents the value of performance units for the 2019 - 2021 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 units in 2021.
2021 Pension Benefits
The following table shows the present value as of December 31, 2021, of accumulated benefits payable to each of the NEOs, including the number of years of service credited to each 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 2021
Marcus V. Brown(1)
System Executive Retirement Plan 26.74 $8,325,300 $-
Entergy Retirement Plan 26.74 $1,440,500 $-
Leo P. Denault (1)(2)(3)
System Executive Retirement Plan 30.00 $34,861,100 $-
Entergy Retirement Plan 22.83 $1,295,500 $-
David D. Ellis Cash Balance Equalization Plan 3.06 $30,700 $-
Cash Balance Plan 3.06 $51,400 $-
Haley R. Fisackerly(1)
System Executive Retirement Plan 26.08 $2,490,500 $-
Entergy Retirement Plan 26.08 $1,287,600 $-
Laura R. Landreaux Pension Equalization Plan 14.48 $362,400 $-
Entergy Retirement Plan 14.48 $598,300 $-
Andrew S. Marsh System Executive Retirement Plan 23.37 $6,742,300 $-
Entergy Retirement Plan 23.37 $958,100 $-
Phillip R. May, Jr. (1)(3)
System Executive Retirement Plan 30.00 $3,699,000 $-
Entergy Retirement Plan 35.56 $1,877,700 $-
Sallie T. Rainer (1)(3)
System Executive Retirement Plan 30.00 $2,317,300 $-
Entergy Retirement Plan 37.00 $2,102,600 $-
Deanna D. Rodriguez(1)
Pension Equalization Plan 5.74 $721,700 $-
Entergy Retirement Plan 5.74 $1,443,800 $-
Eliecer Viamontes Cash Balance Equalization Plan 1.95 $11,100 $-
Cash Balance Plan 1.95 $23,300 $-
Roderick K. West System Executive Retirement Plan 22.75 $7,718,800 $-
Entergy Retirement Plan 22.75 $1,020,200 $-
(1)As of December 31, 2021, Mr. Brown, Mr. Denault, Mr. Fisackerly, Mr. May, and Ms. Rodriguez were retirement eligible. Ms. Rainer retired in November 2021.
(2)In 2021, the Company entered into an agreement with Mr. Denault and amended the PEP and the SERP, pursuant to which the benefit payable to Mr. Denault (or to his surviving spouse) under the SERP if 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. See further discussion of this agreement at “What Entergy Corporation Pays and Why - Severance and Retention Arrangements - Non-Qualified Pension Plan Modifications” in the CD&A.
(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, Mr. May and Ms. Rainer are calculated based on 30 years of service pursuant to the terms of the SERP.
Retirement Benefits
The tables below contain summaries of the pension benefit plans sponsored by Entergy Corporation that the NEOs participated in during 2021. Benefits for the NEOs 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
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
Deanna D. Rodriguez
Roderick K. West 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.
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” for the purpose of calculating FAME generally includes the employee’s base salary and eligible annual incentive awards subject to Internal Revenue Code limitations, and excludes all other bonuses. Executive annual incentive awards are not eligible for inclusion in Earnings under this plan.
FAME is calculated using the employee’s average monthly Earnings 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 Earnings 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 Earnings 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%.
Entergy Retirement Plan Cash Balance Plan
Benefit Timing 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.
Non-qualified Retirement Benefits
The NEOs are eligible to participate in certain non-qualified retirement benefit plans that provide retirement income, including the PEP, the Cash Balance Equalization Plan, and the SERP. 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 PEP and the SERP 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
Laura R. Landreaux
Andrew S. Marsh Phillip R. May, Jr.
Sallie T. Rainer
Deanna D. Rodriguez
Roderick K. West
David D. Ellis
Eliecer Viamontes Marcus V. Brown
Haley R. Fisackerly
Leo P. 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
Pension Equalization Plan Cash Balance Equalization Plan System Executive Retirement Plan
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 6 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 6 month delay required under Internal Revenue Code Section 409A.
Additional Information
(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 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 SERP was closed to new executive officers effective July 1, 2014.
(4)Ms. Rainer retired in November 2021. It is anticipated that her SERP lump sum benefit will be paid in 2022.
2021 Non-qualified Deferred Compensation
As of December 31, 2021, 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 participant 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 2021 Registrant Contributions in 2021 Aggregate Earnings in 2021(1)
Aggregate Withdrawals/Distributions Aggregate Balance at December 31, 2021
(a) (b) (c) (d) (e) (f)
Phillip R. May, Jr. $- $- $629 $- $3,696
(1)Amounts in this column are not included in the Summary Compensation Table.
2021 Potential Payments Upon Termination or Change in Control
The Company has plans and other arrangements that provide compensation to a NEO if his or her employment terminates under specified conditions, including following a change in control of the Company.
Change in Control
Under the System Executive Continuity Plan (the “Continuity Plan”), executive officers, including each of the NEOs, are eligible to receive the severance benefits described below if their employment is terminated by their Entergy System employer other than for cause or if they terminate their employment for good reason during a period beginning with a potential change in control and ending 24 months following the effective date of a change in control (a “Qualifying Termination”). 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 her non-compete provision (which generally runs for two years but extends to three years if permissible under applicable law). Entergy Corporation does not have any plans or agreements that provide for payments or benefits to any of the NEOs solely upon a change in control.
In the event of a Qualifying Termination, the executive officers, including the NEOs, generally would receive the benefits below:
Compensation Element Payment
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 in control period or, if higher, immediately prior to a circumstance constituting good reason, plus (b) the participant’s STI, calculated using the average annual target opportunity derived under the STI program for the two calendar years immediately preceding the calendar year in which termination occurs.
Performance Units** For outstanding performance units, participants 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 either case pro-rated based on the portion of the performance period that occurs through the termination date.
Equity Awards All unvested stock options, shares of restricted stock and restricted stock units will vest immediately upon a Qualifying Termination pursuant to the terms of Entergy’s equity plans.
Retirement Benefits Benefits already accrued under the SERP, PEP and Cash Balance Equalization Plan, 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 STI payment under the STI program 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.
** See “Mr. Denault’s 2006 Retention Agreement” for a description of how Mr. Denault’s performance units would be calculated in the event of a Qualifying Termination.
To protect shareholders and Entergy Corporation’s business model, executives are required to comply with non-compete, non-solicitation, confidentiality and non-denigration provisions. 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.
•Cause: The participant’s (a) willful and continuous failure to perform substantially his or her duties after written demand for performance; (b) engagement in conduct that is materially injurious to Entergy Corporation
or any of its subsidiaries; (c) conviction or guilty or nolo contendere plea to a felony or other crime that materially and adversely affects either his or her ability to perform his or her duties or Entergy Corporation’s reputation; (d) material violation of any agreement with Entergy Corporation or any of its subsidiaries; or (e) disclosure of any of Entergy Corporation’s confidential information without authorization.
•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 NEOs, generally will receive the benefits set forth below:
Termination Event Compensation Element
Severance Short-Term Incentive Stock Options Restricted Stock Performance Units
Voluntary Resignation None Forfeited* 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**
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 prior to 2020 vest on the retirement date and expire on the earlier of (i) five years from the retirement date and (ii) the option’s normal expiration date. Unvested stock options granted in or after 2020 continue to vest following retirement, in accordance with the original vesting schedule and expire the earlier of (i) five years from the 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 Entergy Corporation’s discretion, an annual incentive payment.
** If an officer resigns after the completion of a PUP performance period, he or she may receive a payout under the PUP based on the outcome of the performance period.
Mr. Denault’s 2006 Retention Agreement
In 2006, we entered into a retention agreement with Mr. Denault that provides benefits to him in addition to, or in lieu of, the benefits described above. Mr. Denault’s Agreement provides that in the event of a Termination Event (as defined in his Agreement): 1) Mr. Denault is entitled to a Target PUP 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, assuming all performance goals were achieved at target; and 2) all of Mr. Denault’s unvested stock options and shares of restricted stock will immediately vest.
In the event of death or disability, Mr. Denault would receive the greater of the Target PUP Award calculated as described above for a Termination Event under his retention agreement or the pro-rated number of performance units for each open performance 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, as provided for by the applicable PUP Performance Unit Agreements for the open PUP Performance Periods.
Under the terms of his 2006 retention agreement, 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 Personnel Committee; (b) willfully engaging in conduct that is 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 has or may have 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.
Mr. Denault may 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 are 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 our 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 (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 NEOs would have received if his or her employment had been terminated as of December 31, 2021 under the various scenarios described above. For purposes of these tables, a stock price of $112.65 was used, which was the closing market price of Entergy Corporation stock on December 31, 2021, 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
Marcus V. Brown(1)
Severance Payment
- - - - - - $3,784,478
Performance Units(3)
- - - $898,496 $898,496 $898,496 $898,496
Stock Options
- - - $279,338 $646,921 $646,921 $646,921
Restricted Stock
- - - - $147,914 $147,914 $147,914
Welfare Benefits(5)
- - - - - - -
Unvested Restricted Stock Units(7)
- - $333,106 - $333,106 $333,106 $1,601,432
Leo P. Denault(1)
Severance Payment
- - - - - - $10,216,232
Performance Units(3)(4)
- - $5,148,105 $4,314,157 $5,148,105 $5,148,105 $5,148,105
Stock Options
- - $3,397,359 $3,397,359 $3,397,359 $3,397,359 $3,397,359
Restricted Stock
- - $638,199 - $638,199 $638,199 $638,199
Welfare Benefits(5)
- - - - - - -
David D. Ellis(2)
Severance Payment
- - - - - - $581,000
Performance Units(3)
- - - - $166,497 $166,497 $166,497
Stock Options
- - - - $95,324 $95,324 $95,324
Restricted Stock
- - - - $20,951 $20,951 $20,951
Welfare Benefits(6)
- - - - - - $31,923
Haley R. Fisackerly(1)
Severance Payment
- - - - - - $559,847
Performance Units(3)
- - - $133,265 $133,265 $133,265 $133,265
Stock Options
- - - $48,492 $117,307 $117,307 $117,307
Restricted Stock
- - - $25,091 $25,091 $25,091 $25,091
Welfare Benefits(5)
- - - - - - -
Laura R. Landreaux(2)
Severance Payment
- - - - - - $532,000
Performance Units(3)
- - - - $129,773 $129,773 $129,773
Stock Options
- - - - $104,871 $104,871 $104,871
Restricted Stock
- - - - $20,951 $20,951 $20,951
Welfare Benefits(6)
- - - - - - $21,282
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(2)
Severance Payment - - - - - - $3,891,083
Performance Units(3)
- - - - $1,157,591 $1,157,591 $1,157,591
Stock Options - - - - $843,240 $843,240 $843,240
Restricted Stock - - - - $187,056 $187,056 $187,056
Welfare Benefits(6)
- - - - - - $31,923
Phillip R. May, Jr.(1)
Severance Payment - - - - - - $1,334,168
Performance Units(3)
- - - $186,436 $186,436 $186,436 $186,436
Stock Options - - - $72,726 $163,204 $163,204 $163,204
Restricted Stock - - - - $37,637 $37,637 $37,637
Welfare Benefits(5)
- - - - - - -
Deanna D. Rodriguez(1)
Severance Payment - - - - - - $445,500
Performance Units(3)
- - - $86,515 $86,515 $86,515 $86,515
Stock Options - - - - - - -
Restricted Stock - - - $41,903 $41,903 $41,903 $41,903
Welfare Benefits(5)
- - - - - - -
Eliecer Viamontes(2)
Severance Payment - - - - - - $408,000
Performance Units(3)
- - - - $134,616 $134,616 $134,616
Stock Options - - - - $72,691 $72,691 $72,691
Restricted Stock - - - - $70,575 $70,575 $70,575
Welfare Benefits(6)
- - - - - - $21,282
Unvested Restricted Stock Units(8)
- - - - - - $433,703
Roderick K. West(2)
Severance Payment - - - - - - $3,957,550
Performance Units(3)
- - - - $1,033,789 $1,033,789 $1,033,789
Stock Options - - - - $748,765 $748,765 $748,765
Restricted Stock - - - - $158,703 $158,703 $158,703
Welfare Benefits(6)
- - - - - - $23,787
1)As of December 31, 2021, Mr. Brown, Mr. Denault, Mr. Fisackerly, Mr. May, and Ms. Rodriguez are 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. For a description of these benefits, see “2021 Pension Benefits.”
2)See “2021 Pension Benefits” for a description of the pension benefits Mr. Ellis, Ms. Landreaux, Mr. Marsh, Mr. Viamontes, and Mr. West may receive upon the occurrence of certain termination events.
3)For purposes of the table, in the event of a qualifying termination related to a change in control, each NEO would receive a number of performance units for the 2020 - 2022 performance period and a number of performance units for the 2021 - 2023 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. For purposes of the table, the values of the performance unit awards for 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. Brown’s:
2020 - 2022 PUP Performance Period: 5,048 (24/36*7,571) performance units at target, assuming a stock price of $112.65 = $568,657
2021 - 2023 PUP Performance Period: 2,928 (12/36*8,784) performance units at target, assuming a stock price of $112.65 = $329,839
Total: $898,496
Mr. Denault’s:
2020 - 2022 PUP Performance Period: 20,842 (24/36*31,263) performance units at target, assuming a stock price of $112.65 = $2,347,851
2021 - 2023 PUP Performance Period: 17,455 (12/36*52,365) performance units at target, assuming a stock price of $112.65 = $1,966,306
Total: $4,314,157
Mr. Ellis’s:
2020 - 2022 PUP Performance Period: 792 (24/36*1,188) performance units at target, assuming a stock price of $112.65 = $89,219
2021 - 2023 PUP Performance Period: 686 (12/36*2,056) performance units at target, assuming a stock price of $112.65 = $77,278
Total: $166,497
Mr. Fisackerly’s:
2020 - 2022 PUP Performance Period: 634 (24/36*950) performance units at target, assuming a stock price of $112.65 = $71,420
2021 - 2023 PUP Performance Period: 549 (12/36*1,645) performance units at target, assuming a stock price of $112.65 = $61,845
Total: $133,265
Ms. Landreaux’s:
2020 - 2022 PUP Performance Period: 634 (24/36*950) performance units at target, assuming a stock price of $112.65 = $71,420
2021 - 2023 PUP Performance Period: 518 (12/36*1,553) performance units at target, assuming a stock price of $112.65 = $58,353
Total: $129,773
Mr. Marsh’s:
2020 - 2022 PUP Performance Period: 6,374 (24/36*9,560) performance units at target, assuming a stock price of $112.65 = $718,031
2021 - 2023 PUP Performance Period: 3,902 (12/36*11,706) performance units at target, assuming a stock price of $112.65 = $439,560
Total: $1,157,591
Mr. May’s:
2020 - 2022 PUP Performance Period: 934 (24/36*1,400) performance units at target, assuming a stock price of $112.65 = $105,215
2021 - 2023 PUP Performance Period: 721 (12/36*2,162) performance units at target, assuming a stock price of $112.65 = $81,221
Total: $186,436
Ms. Rodriguez’s:
2020 - 2022 PUP Performance Period: 334 (24/36*501) performance units at target, assuming a stock price of $112.65 = $37,625
2021 - 2023 PUP Performance Period: 434 (12/36*1,301) performance units at target, assuming a stock price of $112.65 = $48,890
Total: $86,515
Mr. Viamontes’:
2020 - 2022 PUP Performance Period: 616 (24/36*924) performance units at target, assuming a stock price of $112.65 = $69,392
2021 - 2023 PUP Performance Period: 579 (12/36*1,737) performance units at target, assuming a stock price of $112.65 = $65,224
Total: $134,616
Mr. West’s:
2020 - 2022 PUP Performance Period: 5,601 (24/36*8,401) performance units at target, assuming a stock price of $112.65 = $630,953
2021 - 2023 PUP Performance Period: 3,576 (12/36*10,727) performance units at target, assuming a stock price of $112.65 = $402,836
Total: $1,033,789
In the event of retirement, in the case of Mr. Brown, Mr. Denault, Mr. Fisackerly, Mr. May, or Ms. Rodriguez 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 her 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. Brown, Mr. Denault, Mr. Fisackerly, Mr. May, and Ms. Rodriguez would receive in the event of retirement, it is assumed the achievement levels for the 2020 - 2022 PUP Performance Period and the 2021 - 2023 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 estate would receive a prorated portion of the applicable Achievement Level of PUP Performance Units for each open 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.
4)Pursuant to Mr. Denault’s retention agreement, in the event Mr. Denault’s employment is terminated by his Entergy employer without cause or by Mr. Denault for good reason (as those terms are defined in his retention agreement) and with or without a change in control, he would receive a Target PUP Award equal to that number of PUP performance units calculated by taking an average of the PUP target performance units from the 2017 - 2019 PUP Performance Period (48,700) and from the 2018 - 2020 PUP Performance Period (42,700), which amounts to 45,700 performance units. For purposes of the table, the value of such PUP performance units is calculated by multiplying 45,700 by the closing price of Entergy stock on December 31, 2021 ($112.65), which equals $5,148,105. In the event of death or disability, Mr. Denault receives the greater of the Target PUP Award calculated as described immediately above or the sum of the amount that would be payable under the provisions of each performance period.
5)Upon retirement, Mr. Brown, 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 System Entergy Retirement Plan, in the event of a termination related to a change in control, Mr. Ellis, Mr. Marsh, and Mr. West would be eligible to receive Entergy-subsidized COBRA benefits for 18 months and Ms. Landreaux and Mr. Viamontes would be eligible to receive Entergy-subsidized COBRA benefits for 12 months.
7)Mr. Brown’s 14,216 restricted stock units vest 100% on May 17, 2024. Pursuant to his restricted stock unit agreement, any unvested restricted stock units will vest in a pro rata portion in the event of his termination of employment due to Mr. Brown’s total disability, death or involuntarily termination without cause (each, an “Accelerated Vesting Event”). The pro rata portion is determined by multiplying the total number of restricted stock units by a fraction, the numerator of which the number of days after May 17, 2021 that precede the Accelerated Vesting Event 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. Brown’s Qualifying Termination during a change in control period. Pursuant to his restricted stock unit agreement, Mr. Brown 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. Brown’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. Brown 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)333 of Mr. Viamontes’ restricted stock units vested on February 1, 2022; the remaining 334 restricted stock units will vest on February 1, 2023. In the event of a Change in Control, the unvested restricted stock units 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 a 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.
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 8, 2021 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 to 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 2021 Summary Compensation Table with respect to each of the NEOs.
Entergy Arkansas Ratio
For 2021,
•The median of the annual total compensation of all of Entergy Arkansas’s employees, other than Ms. Landreaux, was $132,376.
•Ms. Landreaux’s annual total compensation, as reported in the Total column of the 2021 Summary Compensation Table was $982,993.
•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 7:1.
Entergy Louisiana Ratio
For 2021,
•The median of the annual total compensation of all of Entergy Louisiana’s employees, other than Mr. May, was $152,954.
•Mr. May’s annual total compensation, as reported in the Total column of the 2021 Summary Compensation Table, was $1,145,271.
•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 7:1.
Entergy Mississippi Ratio
For 2021,
•The median of the annual total compensation of all of Entergy Mississippi’s employees, other than Mr. Fisackerly, was $129,194.
•Mr. Fisackerly’s annual total compensation, as reported in the Total column of the 2021 Summary Compensation Table, was $1,126,753.
•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 9:1.
Entergy New Orleans Ratio
For purposes of this disclosure and to reflect the Chief Executive Officer transition discussed earlier in the CD&A, the compensation amounts paid to each of Mr. Ellis and Ms. Rodriguez for the time he and she respectively served as Entergy New Orleans’s Chief Executive Officer during 2021 have been pro-rated and combined.
For 2021,
•The median of the annual total compensation of all of Entergy New Orleans’s employees, other than Entergy New Orleans’s Chief Executive Officer, was $122,634.
•The combined annual total compensation of Entergy New Orleans’s previous Chief Executive Officer, Mr. Ellis, and its current Chief Executive Officer, Ms. Rodriguez, as reported in the Total column of the 2021 Summary Compensation Table (pro-rated for the time each served as Entergy New Orleans’s Chief Executive Officer in 2021) was $1,011,672.
•Based on this information, the ratio of the annual total compensation of Entergy New Orleans’s Chief Executive Officer to the median of the annual total compensation of all employees is estimated to be 8:1.
Entergy Texas Ratio
For purposes of this disclosure and to reflect the Chief Executive Officer transition discussed earlier in the CD&A, the compensation amounts paid to each of Ms. Rainer and Mr. Viamontes for the time she and he respectively served as Entergy Texas’s Chief Executive Officer during 2021 have been pro-rated and combined.
For 2021,
•The median of the annual total compensation of all of Entergy Texas’s employees, other than Entergy Texas’s Chief Executive Officer, was $130,863.
•The combined annual total compensation of Entergy Texas’s previous Chief Executive Officer, Ms. Rainer, and its current Chief Executive Officer, Mr. Viamontes, as reported in the Total column of the 2021 Summary Compensation Table (pro-rated for the time each served as Entergy Texas’s Chief Executive Officer in 2021) was $1,356,405.
•Based on this information, the ratio of the annual total compensation of Entergy Texas’s Chief Executive Officer to the median of the annual total compensation of all employees is estimated to be 10:1.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12. Security Ownership of Certain Beneficial Owners and Management
Entergy Corporation owns 100% of the outstanding common stock of Entergy Texas and indirectly 100% of the outstanding common membership interests of 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 2022 Entergy 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, 2022 for the directors and 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
Marcus V. Brown** 23,211 63,664 -
Leo P. Denault** 362,159 1,033,899 -
Andrew S. Marsh*** 104,473 307,966 -
Laura R. Landreaux*** 5,624 9,257 -
Roderick K. West*** 43,811 69,784 -
All directors and executive officers as a group (8 persons) 611,534 1,684,959 -
Entergy Louisiana
Marcus V. Brown** 23,211 63,664 -
Leo P. Denault** 362,159 1,033,899 -
Andrew S. Marsh*** 104,473 307,966 -
Phillip R. May, Jr.*** 26,347 16,163 14
Roderick K. West*** 43,811 69,784 -
All directors and executive officers as a group (8 persons) 632,257 1,691,865 14
Entergy Mississippi
Marcus V. Brown** 23,211 63,664 -
Leo P. Denault** 362,159 1,033,899 -
Haley R. Fisackerly*** 7,424 10,567 -
Andrew S. Marsh*** 104,473 307,966 -
Roderick K. West*** 43,811 69,784 -
All directors and executive officers as a group (7 persons) 586,042 1,620,860 -
Name Shares (1)
Options Exercisable Within 60 Days Stock Units (2)
Entergy New Orleans
Marcus V. Brown** 23,211 63,664 -
Leo P. Denault** 362,159 1,033,899 -
David D. Ellis*** 3,060 7,996 -
Andrew S. Marsh*** 104,473 307,966 -
Deanna D. Rodriguez*** 7,239 -
Roderick K. West*** 43,811 69,784 -
All directors and executive officers as a group (8 persons) 588,917 1,618,289 -
Entergy Texas
Marcus V. Brown** 23,211 63,664 -
Leo P. Denault** 362,159 1,033,899 -
Andrew S. Marsh*** 104,473 307,966 -
Sallie T. Rainer*** 12,449 17,357 -
Eliecer Viamontes*** 4,079 1,444 -
Roderick K. West*** 43,811 69,784 -
All directors and executive officers as a group (8 persons) 595,146 1,629,094 -
* Director of the respective company
** NEO of the respective company
*** Director and NEO of the respective company
(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, 2021. 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)
Equity compensation plans approved by security holders (1)
2,819,644 $90.82 4,711,095
Equity compensation plans not approved by security holders
- - -
Total 2,819,644 $90.82 4,711,095
(1)Includes the 2011 Equity Ownership Plan, the 2015 Equity Plan, and the 2019 Omnibus Incentive Plan. 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 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 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.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Party Transactions and Director Independence
The additional information required by this item will be set forth under Director Independence and Review and Approval of Related Persons Transactions in the 2022 Entergy Proxy Statement, to be filed in connection with the Annual Meeting of Shareholders to be held May 6, 2022, which is incorporated herein by reference.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
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, 2021 and 2020 by Deloitte & Touche LLP (PCAOB ID No. 34) were as follows:
2021 2020
Entergy Corporation (consolidated)
Audit Fees $9,030,000 $9,200,000
Audit-Related Fees (a) 1,634,175 909,550
Total audit and audit-related fees 10,664,175 10,109,550
Tax Fees - -
All Other Fees (b) 392,895 183,060
Total Fees (c) $11,057,070 $10,292,610
Entergy Arkansas
Audit Fees $1,086,857 $1,137,507
Audit-Related Fees (a) - -
Total audit and audit-related fees 1,086,857 1,137,507
Tax Fees - -
All Other Fees - -
Total Fees (c) $1,086,857 $1,137,507
Entergy Louisiana
Audit Fees $2,163,714 $2,225,014
Audit-Related Fees (a) 783,092 437,837
Total audit and audit-related fees 2,946,806 2,662,851
Tax Fees - -
All Other Fees - -
Total Fees (c) $2,946,806 $2,662,851
Entergy Mississippi
Audit Fees $1,121,857 $982,507
Audit-Related Fees (a) - -
Total audit and audit-related fees 1,121,857 982,507
Tax Fees - -
All Other Fees - -
Total Fees (c) $1,121,857 $982,507
Entergy New Orleans
Audit Fees $1,096,857 $1,027,507
Audit-Related Fees (a) 212,896 -
Total audit and audit-related fees 1,309,753 1,027,507
Tax Fees - -
All Other Fees - -
Total Fees (c) $1,309,753 $1,027,507
2021 2020
Entergy Texas
Audit Fees $1,131,857 $1,212,507
Audit-Related Fees (a) 252,187 45,713
Total audit and audit-related fees 1,384,044 1,258,220
Tax Fees - -
All Other Fees - -
Total Fees (c) $1,384,044 $1,258,220
System Energy
Audit Fees $1,046,857 $1,017,507
Audit-Related Fees (a) - -
Total audit and audit-related fees 1,046,857 1,017,507
Tax Fees - -
All Other Fees - -
Total Fees (c) $1,046,857 $1,017,507
(a)Includes fees for employee benefit plan audits, consultation on financial accounting and reporting, and other attestation services.
(b)Includes fees for cybersecurity assessment, ethics and compliance assessment, and license fee for accounting research tool.
(c)100% of fees paid in 2021 and 2020 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:
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.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
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.
(a)2. Financial Statement Schedules
Reports of Independent Registered Public Accounting Firm (see page 537)
Financial Statement Schedules are listed in the Index to Financial Statement Schedules (see page S-1)
(a)3. Exhibits
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 514 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.